The converter station is built as an extension of the existing 400 kV switchyard at. Chandrapur. 2. Selection of Main System Parameters. During the design stage, ...
Control System Design at Chandrapur Back-to-Back HVDC Station B A Rowe
N M Kirby
Dr H K Yu
GEC ALSTHOM T&D Power Electronic Systems Ltd PO Box 27, Stafford, England Abstract This paper describes control systems being implemented within the Chandrapur 1000MW Back-To-Back HVDC Station for the POWERGRID Corporation of India Ltd. The Station is being installed at Chandrapur at one end of an existing 200km 400kV AC double circuit line to Ramagundam, and is designed for power transfer in either direction to provide a flexible link between the Western and Southern AC systems. Utilisation of the inherent reactive power variation capability of HVDC converters is described. Other aspects of power transfer control are also described. 1. Introduction Although the power systems of Western and Southern India both operate at 50 Hz, they are not usually synchronised. Because the Southern system is substantially hydro-rich compared with the Western region, which is predominantly thermal in nature, there is considerable prospective economic benefit to be realised from a reliable and controllable interconnection. A synchronous ac link already interconnects the Chandrapur and Ramagundam substations, whenever operating conditions are sufficiently stable. Operational practicalities dictate that the power transfer is limited to a maximum of around 200 MW, and it cannot be a secure transfer, since the synchronising power which can be transmitted is too small to control the behaviour of the power systems. A back-to-back HVDC link rated at 1000MW is to be constructed at the Chandrapur end of the existing double-circuit 400kV line. The station will comprise two substantially independent "poles", each of which has a nominal rating of 2,475 Adc at 205 kVdc. The HVDC link will make it practical for the 400kV lines to transmit several times more power than was previously possible. More importantly, the power transfer will not be influenced by the voltage, frequency or relative phase of the two power systems. Since the converter station equipment is divided into two independent 500
MW poles, half of the total power transfer can be regarded as secure.
Figure 1 - Station Single Line Diagram [1] uses three-winding The back-to-back link converter transformers constructed as single-phase units to make them transportable. Each valve hall contains two twelve-pulse converters, one connected to the western network, and the other to the southern network. Two redundant thyristors are included for each valve in the converters such that there are 54 thyristor levels per valve. Two banks of converter transformers are placed on opposite sides of each valve hall, with their bushings penetrating the valve hall wall. Connection to the ac networks is via PLC filters, while low frequency harmonics are controlled by eight ac harmonic filters on each side of the link. These ac harmonic filters, combined with the characteristics imposed on the converters by control action, provide the necessary reactive support for each of the two ac busbars. The converter station is built as an extension of the existing 400 kV switchyard at Chandrapur.
2. Selection of Main System Parameters During the design stage, optimum values of the DC link voltage and the commutating reactance, to minimise costs arising from thyristor valves,
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converter transformers and reactive elements (filters), were selected. These components account for more than 50% of the capital cost of a scheme. A "high-current, low-voltage" design would minimise the cost of thyristor valves, but a high impedance transformer would be required to limit valve fault current. Since the converter reactive power demand is mainly due to the transformer impedance, a "high-current" design demands more reactive compensation. A "lowcurrent, high-voltage" design can reduce the demand for reactive power, but requires thyristor valves that contain a greater number of seriesconnected thyristors to withstand the higher valvewinding voltage. A cost optimisation study was performed in which the cost of valves, transformers, reactive elements and capitalised losses were considered. The analysis leads to a "medium voltage" "medium-current" design, in which each 500MW converter absorbs about 350Mvar at nominal power transfer. The total reactive power to be provided for each side of each 500MW converter is 424Mvar. Each filter is made as large as possible to minimise the number of high voltage circuit breakers required while observing the voltage change requirement on filter switching. There are 4 by 106Mvar filters for each side of each 500MW converter. Each filter can vary between about 90Mvar and 126Mvar depending on ac system operating conditions and manufacturing tolerances. The var exchanged with the ac system can be limited by using either shunt reactors or by controlling the converters. If shunt reactors are used the capital cost will increase. Moreover, normal high voltage switchgear is not designed for frequent operation. In a Back-to-Back scheme, the converter var absorption can be increased by using higher than normal control angles to depress the direct voltage thereby increasing the direct current needed to meet the power transfer requirement. This method is used for the Chandrapur scheme. 3. Reactive Power Controller Management of the var exported from the Chandrapur Station is achieved by a Reactive Power Controller (RPC). RPC also provides var/voltage control during special operating conditions. The western ac system can normally provide up to ±50Mvar, which is smaller than the size of one
filter, especially when the wide range of operating conditions is considered. In contrast, the southern ac system can always tolerate a var exchange variation of at least 190Mvar. This is large compared with the maximum size of a filter (126Mvar). Therefore, the use of the converter to absorb the surplus usually arises from the var exchange requirement of the western ac system. 3.1 General Applications of Reactive Power Controller During steady state conditions, RPC ensures that the var exported to the ac systems is within the stipulated limits, and that the harmonic performance is satisfactory, by energising an appropriate number of filters and adjusting the converter absorption. The var exported to the ac systems may be biased by up to ±300Mvar by the operator. Alternatively, the var exchange limits may be biased to target any ac system voltage, between 380kV and 420kV, set by the operator. These special operating modes are called Reactive Power Exchange Mode (RPEM) and AC Voltage Control Mode (ACVCM) respectively. The extent to which the scheme can be used in these special modes depends on the inherent capability of the converter equipment, i.e. the current carrying capability of the equipment and the ability of the thyristor valve surge arresters to withstand long term exposure to the voltage overshoot which accompanies valve turn off. To limit the effects of switching filters RPC will change the converter absorption temporarily, by adjusting the converter angles, in a sense opposite to that caused by the switching action. This decreases the magnitude of the net change in var when a filter is switched. During rapid power change, the operating conditions may take a long period to settle. The var exported to the ac systems could differ from that when the operating conditions have settled. During this period RPC employs an open-loop approximation to perform a minimal number of filter switching operations. This initial approximation ensures that the early var unbalance is not greater than about half the Mvar of a filter. Further switching will be performed when the operating conditions have settled, if the var export to the ac systems exceeds the stipulated limit. This refinement is performed by a closed loop controller. This coarse/fine approach ensures that
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early switching actions are not subsequently reversed. 3.2 RPC Control Action During TOV Fault Events RPC also provides var/volt control during fault events. There are three categories of TOV: First when a pole trip results in a reduction in power transfer, then RPC immediately disconnects some filters from both ends of the scheme to control the TOV on both ac systems. The number of filters to be disconnected from each end depends on the change in power transfer and the pre-fault ac system voltage, and is determined by the openloop coarse controller. RPC ensures that the overvoltages that appear on both ends of the scheme are depressed to an acceptable level, and that the filters that remain energised are sufficient to meet the post-fault var/harmonic performance. Secondly, TOV can be caused by load rejection arising from a three phase short-circuit applied to one of the ac systems. The converters on the healthy ac system may then operate in "TCR mode" to limit the TOV. This entails continued conduction by four of the thyristor valves at the faulted end (where commutation will cease when the ac system voltage is removed), whilst the valves at the healthy end operate at a firing angle near α=90o. This circulates current through the HVDC converters at near zero direct voltage, transferring negligible real power, but (because of the action of the AC Overvoltage Limit) absorbing sufficient var to restrain the voltage on the healthy ac system. Under this condition, RPC is not permitted to disconnect any filter immediately to assist the TOV control, since the ac network may subsequently recover. Thirdly, an external ac load rejection can cause a TOV on one side, but leave the power unaffected. TOV of this type will be controlled by the AC Voltage Control Loop in [1] Pole Control , if it exceeds the TOV control threshold. If the TOV exists for a prolonged period (longer than 1 second), it is assumed that a permanent fault exists in the ac system, and RPC will start to disconnect some filters to assist TOV control regardless of the post-fault var/harmonic performance. 3.3 Operational Constraint Under normal operating conditions the converters operate with nominal direct voltage and nominal valve-winding voltage. This is called "Vdo Mode".
However, when there is excess var export, the converter absorption is increased by reducing the direct voltage by using larger than normal control angles (meanwhile increasing the direct current to maintain the transmitted power). This is called Reactive Power Mode (RPM). To meet the var exchange requirement and the harmonic performance at low power transfers, the direct voltage may fall to about 15% of nominal and the o control angles may be increased to about 80 . As power transfer increases, the firing angle required to exert var control becomes smaller. Therefore, as power transfer increases the direct voltage rises towards nominal and the firing angle falls towards normal range. Operating at very large firing angles increases the voltage stress imposed on the valve surge arresters. If the valve-winding voltage remained at nominal, the voltage stress would often be unacceptably high, especially at low power. The valve-winding voltage is restricted by the converter transformer tapchanger, which is used to contain the voltage stress imposed on the valve surge arresters within acceptable limits. The valvewinding voltage at low power transfers (below about half full load) is reduced to a level that o permits the use of firing angles up to 90 . In other words var control using the converters is limited only by the current carrying capability of the equipment. As power transfer increases, the extent to which the converters are required to exert var control is reduced. Therefore, the valve-winding voltage is increased progressively, reaching nominal as power transfer increases to about two thirds of full load. Since the valve-winding voltage at low power transfers is reduced, the maximum direct voltage that may be used at low power transfers is also limited. This reduces the risk of commutation failure, and it also increases the direct current at minimum power transfer, thus avoiding discontinuous current operation and reducing the need for enhanced rating of the valve electronics. Although RPC has no direct control over the valvewinding voltage, a signal is sent from Pole Control to RPC to indicate the status of the tapchanger. Reactive Power Mode is disabled, i.e. the converters will not be used to exert var control, if the tapchanger does not respond correctly. This is necessary to avoid putting equipment at risk. 3.4 Internal Architecture of RPC
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Figure 2 shows a simplified schematic diagram of RPC. RPC is arranged in two main parts: namely an open-loop coarse controller and a closed-loop fine controller. The coarse controller responds immediately to large/rapid changes in power transfer and/or ac system voltage, and switches filters to control approximately the var exchanged with the ac systems. Although the var compensation provided by the open loop controller is approximate, it is rapid and the number of filters switched during the disturbance is the minimum essential. The openloop controller ignores harmonic constraints when energising filters, but it assumes worst case harmonic performance when de-energising filters. The fine controller controls the converter var absorption by depressing the direct voltage when the var exported to either ac system exceeds the stipulated limit. When the operating conditions have settled, it may switch filters so that performance is met by the minimum necessary filters. Thus the converters do not exert more var control than is essential.
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Figure 2 - Simplified Schematic Diagram of Reactive Power Controller
When a harmonic performance limit is exceeded while the number of filters energised is less than the maximum number calculated, a filter will be energised. A filter will also be energised when the var exported to the ac system falls below the deficit limit. A filter will be de-energised if the direct voltage is abnormally low for the power being transmitted, provided that the harmonic performance is also below its limit or the number of filters energised exceeds the calculated minimum number. A filter will be switched sooner if the var error seen by RPC is large. The combined actions of the fine controller and the coarse controller ensure that the var exported to the ac systems and the harmonic performance measured on the ac systems achieve the stipulated limits soon after major disturbances, and remain within the limits during steady state conditions. 4. Operating Modes/States The Operating Mode is defined as the Independent/Station selection, and the Operating State is the Service/Shutdown/Standby selection, for each pole. These features are illustrated in Figure 3. Either pole may be operated in either Station or Independent operating mode. A pole in Independent mode operates without regard for overall HVDC link power transfer; it simply responds to operator settings of Power Demand and Rate of Change of power. If either or both poles are operating in Station mode, the power transfer will conform with the operator settings of Power Demand and Rate of Change of power and also Frequency Demand/Slope and Power Modulation if selected by the operator. If both poles are in Station mode, the power transfer is shared equally between them. If one pole is in Independent and one in Station mode the power transfer of the Station pole is adjusted to take into account the power transferred by the Independent pole. Each pole is controlled by its corresponding Pole Control equipment, either directly if in Independent operating mode, or on instruction from Master Control (through Power Order) if in Station operating mode. When a pole is in the Shutdown state it is blocked and de-energised. In the Standby state a pole is energised and
blocked, and may be in either Station or Independent operating mode. In the Service state a pole is energised and deblocked, and may be in either Station or Independent operating mode
Figure 3 – Operating modes and states 5. Control Equipment Hierarchy The HVDC control system hierarchy shown in Figure 4 is conventional in structure. The upper levels of the hierarchy (which are particular to Chandrapur) are described below. 5.1 Operator Interface The top levels of the Control System are accessed through the operator interface panel at which the operator enters the power transfer and mode settings for each of the two poles. Control settings may be entered separately for each pole, or jointly for Station (or Master) Control. Networked communications are used between equipments within the control room for signals that are not time critical. The Main Station Mimic, the Sequence of Events Recorder (SER) and switchgear interface equipments are all connected through an Ethernet-type network. Pole Control
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equipments are also connected to this network through (duplicated) X25-type serial links.
of a fault, maintenance.
and
manual
changeover
for
It is possible to operate each of the two poles in Independent Control without the Master Control equipment, directly through the Pole Control equipment. equipment.
Figure 4 – Control System Hierarchy
5.2 Master Control Master Control is the top level of automatic control for the two poles. It implements the control functions which concern the AC systems on either end of the HVDC link such as Frequency Control, Power Modulation, Power Demand Overrides (PDO). Master Control generates a Power Order, which is passed to each Pole Control in response to station demands entered by the operator and to changing AC system conditions, according to the selected mode of operation. Master Control has no facilities to bring either pole from Shutdown into Service or to return a pole to the Shutdown state. This ensures that no single equipment failure can bring about the shutdown of both poles simultaneously. Master Control itself is duplicated, the second equipment being in "hot standby" with automatic changeover in the event Page 6
5.3 Pole Control (PCCS, Phase Control) The Pole Control equipment comprises two areas (for each end of each of the two 500MW Poles)a) Pole Control Command System (PCCS) This is implemented in software and provides Power Control, Voltage/Current Order generation, Tapchanger Control, Blocking Control, Sequencing, Overload Control, Control System/Mimic/SER Communications. - The Converter Transformer tapchangers are subject to a predefined characteristic relating the valve winding voltage to ordered power. - Blocking and Deblocking of a pole is implemented by the Blocking Control function, which applies appropriate commands for both normal control and protective purposes. - Sequencing accomplishes the transitions between the Shutdown, Standby and Service states. - The converters may be operated above their nominal rated capacity for periods dependent on ambient temperature, previous loading, cooling capacity and component redundancy. This is limited by the overload control section of PCCS. - Pole Control is the gateway for communications to the upper levels of the control system and both the Station Mimic and the SER, through an X25 serial link that interfaces with the ethernet network.
involved. When the disturbance is self-restoring such as a temporary collapse of ac network voltage, the protection merely monitors the operating conditions, taking no irreversible action. If the disturbance continues for an excessive period, Pole Protection then shuts down and isolates both sides of the pole before its on-valve power supplies become exhausted. If the disturbance is not self-restoring, for example if it is a DC differential fault, Pole Protection immediately acts through Pole Control to shut down both sides of the converter and also disconnects it from the 400kV ac networks.
b) Phase Control This is implemented in hardware and controls Direct Voltage, Direct Current, Firing Angle, and Temporary Overvoltage (TOV). - Normally the Inverter controls the Direct Voltage and the Rectifier controls the Direct Current. However to provide additional control during disturbances Direct Current control by the Inverter is also provided. - Phase Control determines the firing instant of the converters in response to orders derived from operator settings and AC/DC system constraints (power limits, frequency limits, voltage limits, and current limits). - TOV Control restrains the voltage on both sides of the Converter Transformers if it seeks to exceed 1.3pu. Physically integrated with Pole Control but electrically independent of it for reliability reasons is Pole Protection. Its function is to detect and to terminate disturbances in which the converter is
6. Control Modes This section describes the features that determine the control interactions between the converter station and the ac network. The design of this outermost layer of the control system takes into account the presence of the nearby ChandrapurPadghe HVDC link. Selected studies, agreed with POWERGRID, will be carried out to ensure that the characteristics of the Chandrapur Back-to-Back HVDC converter do not conflict with those to be incorporated in the other link. The control modes available on the Chandrapur Back-to-Back HVDC link are : Constant Power Control Frequency Control + Power Control Power Modulation + Power Control Power Modulation + Frequency Control + Power Control and these are described below.
5.4 Reactive Power Control (RPC) RPC acts on the whole station, there being no direct association between particular AC Harmonic Filter Banks and specific poles. RPC sends a Voltage Order to each Pole Control, in response to DC power order and AC system voltage measurements. RPC comprises duplicated control cubicles (one active, and one in "hot standby" as for Master Control). 5.5 Co-ordination with Nearby Converter Studies are to be conducted to demonstrate that no interactions occur, whereby the behaviour of on HVDC link has an adverse effect on the other.
6.1 Power and Frequency Limits
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The power transfer through the HVDC link is subject to the following constraints (refer to Figure 5). Power Limits per pole := 50MW Pmin = 500MW + Poverload Pmax for 2hrs (all redundant Poverload = 10% coolers in service) 20% for 5secs (no redundant cooling) 30% indefinitely with sufficiently reduced ambient temperature
Figure 5 - Power/Frequency Limits These are fixed limits beyond which no power transfer increase/decrease is permitted, and they apply under all control modes. Frequency limits are Fmin (48.5Hz) and Fmax (51.5Hz). These limits are elastic in that, when they are encountered on either AC system, power transfer is adjusted according to the Frequency Slope to minimise the frequency excursion. These limits are applied under all control modes, and presently these values apply to either AC system. 6.2 Power Control Constant Power Control is the default when a pole is first brought into service. A pole in Independent operating mode can only be used under power control. - If a pole is in Station operating mode the operator enters values of Power Demand and Ramp Rate at the Main Mimic and these are passed through the X25 link to Pole Control and then on to Master Control. Master Control validates the Power Demand by comparing this
with any active limits (returning an override value to the mimic if appropriate) and derives a Power Order which is then passed to Pole Control. Pole Control divides this Power Order by the Voltage Order received from RPC. The resultant signal is the Current Order for the pole. Thus the scheme responds to the Power Demand imposed by the operator by controlling direct current, according to a Voltage Order which is derived by combining the demands for real and reactive power. The static characteristics imposed on the converters by the control system take the form of several relationships between direct current and direct voltage, which are explored by variations in the operating conditions. The two characteristics (rectifier and inverter) are engineered to exhibit only a single intersection, which becomes the operating point. Under normal circumstances, the rectifier implements control of the direct voltage while the inverter controls direct voltage. In GEC ALSTHOM's proprietary implementation of the phase-locked oscillator principle, each segment of each static characteristic is produced by a separate phase-locked oscillator. All the individual oscillators acting on one converter share a common reset signal, which effectively eliminates changeover delays when control passes from one part of the characteristic to another. Every phaselocked oscillator solves its characteristic equation twelve times each fundamental frequency cycle, and the oscillator whose output criterion is first satisfied resets all of the oscillators simultaneously at the instant of firing pulse generation, whereupon all of them recommence the solution of their characteristic equations. Thus, Power Order is divided by Voltage Order to generate Current Order, and Current Order is applied to the appropriate phase-locked oscillator to define the required rectifier firing delay angle, while Voltage Order is applied to the appropriate phase-locked oscillator of the inverter to control its firing delay angle. In this way, the power transfer is maintained at the desired level, regardless of variations in the operating conditions, providing only that they remain within their normal range, whenever the converters are operated in Station Control. - When a pole is operated in Independent Control mode, it is no longer subject to the influence of Station Control. Instead, the operator assumes responsibility for defining its behaviour, so his commands are transmitted directly to the PCCS
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section of Pole control without any influence from Frequency or Damping Control. In this case, the operator-imposed Power Demand and Ramp Rate are transferred directly to Pole Control, where they are subjected to limits before being used to develop the Current Order for the pole. If the other pole continues to operate in Station Control mode, it will accept a Power Order from Master Control, and this Power Order takes into account the behaviour of the pole that is no longer under Station Control. In other words, the pole acting under Station control adjusts its Power Order in an endeavour to ensure that the station Power Demand is fulfilled accurately, in spite of the fact that part of the transferred power is separately determined. The Power and Frequency limits described above act on transferred power. Variations in the AC system voltages on either side will also affect the range of variation available to Reactive Power Control, thereby limiting the Voltage Order and possibly the transferred power. 6.3 Frequency Control If either pole is operating in Station mode, then the operator is free to select the ac network to which it responds. This may be either the Southern or the Western system. Once the operator has determined which ac system he requires the transmission to respond to, he can choose to superimpose Frequency Control or Damping Control (described in 6.4 below) or both simultaneously on the Power Demand. In the case of Frequency Control, he also has the option of choosing the Frequency Slope Demand. The Frequency Slope allows the operator to apply a droop characteristic to the HVDC link similar to that exhibited by the generators within the AC system. The Frequency Slope is defined as the change in frequency corresponding to a 1pu change in power. In this instance 1pu power is 1000MW, and slopes of 2%-4% are typical, therefore at a nominal 50Hz system frequency and 2% slope the variation of power transfer through the HVDC link would be 1000MW/Hz. Thus, the variations in frequency of the ac system will give rise to corresponding changes in the power transfer through the link, thereby contributing to and sharing in the power flow distribution between the generators in the AC system. Frequency Control is superimposed upon Power
Control, which has the effect of adding a DC offset to the Power Order presented to Pole Control. 2 illustrates the principle. The operator enters a value of Power Demand, and values of Frequency Demand and Frequency Slope Demand; these values are then interpreted to generate a Power Order for each pole taking into account power and frequency limits. If no Frequency Slope setting were available then the power transfer through the link would be varied to keep the ac system frequency constant at the demanded frequency (in effect 0% Frequency Slope). Then the HVDC link provides most of the frequency support in the AC network, since it can respond to frequency variations significantly faster than the generators in the system. The effect of the Frequency Slope is that the HVDC link is able to emulate a generator, adjusting its power transfer in the same way when it experiences frequency changes as would a rotating machine. This variation can be superimposed at will on the essentially steady state power transfer demands, which arise either from the operator, or from the LFC signal. 6.4 Power Modulation Power Modulation may be selected if one or both poles are in Station control, and may only be selected to be active on one AC network, not both at once. Frequency Control and Power Modulation may only be selected on the same AC network. Power Modulation operates through measurement of the AC system voltage. If the control system detects any variations in frequency in the range 0.1Hz to 10Hz then the power transfer is modified to correct this variation. A closed loop controller of the form illustrated in Figure 6 implements the Power Modulation control function.
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Figure 6 - Power Modulation Control Loop Master Control receives single-phase measurements of voltage of the selected AC system. These measured values must exceed a threshold before the Power Modulation function becomes active (if selected by the operator). Any phase voltage that drops below this threshold disables the Power Modulation function, effectively freezing the output signal at the most recent value. Power Modulation Control operates over a frequency range of 0.1Hz to 10Hz and its overall effect, averaged over a sufficiently long time, will be zero power transfer. This is due to the AC coupled nature of the Power Modulation signal. When the modulation stops (or is disabled) Power Order reverts to the Power/Frequency Demand. RPC switches according to the DC component of Power Order since the actual DC power transfer may vary significantly owing to Power Modulation. Conclusion Diversity of generation between the western and southern power systems of the Indian subcontinent justifies the development of an interconnection. The use of HVDC transmission allows the power transfer capacity of the existing double circuit 400kV lines to be fully utilised. The feature which makes this transmission scheme unique is its extensive use of carefully controlled converter operating conditions to benefit the AC networks by keeping the reactive power exported from the converter station within close limits. Using the converters to compensate for rapid changes enables many temporary conditions to be tolerated without invoking switching operations, an important consideration when the switching is to be carried out by 400kV switchgear with its significant maintenance considerations. Acknowledgements The authors gratefully acknowledge the permission of the POWERGRID Corporation of India Ltd, and GEC ALSTHOM T&D Power Electronic Systems Ltd to publish this paper
References [1] Chandrapur Back-to-Back HVDC Scheme in India, J D Wheeler, and J L Haddock. International Conference on Power System Technology, EPRI, Beijing, October 1994.
Authors Brian A Rowe Born 1940, graduated BSc (Eng) from Imperial College (England) 1962. Has been with GEC ALSTHOM (then English Electric) since the Sardinia-Italy HVDC project in 1962, He is now Technical Manager, HVDC Systems. Neil M Kirby Born 1959, England. Graduated BSc(Eng) at the University of Newcastle Upon Tyne (England) in 1983 and has worked for GEC ALSTHOM since that time. Presently Group Leader, Chandrapur HVDC Converter Station Design. Henry H K Yu (C.Eng, MIEE) Born 1965, Hong Kong. Graduated at Sunderland Polytechnic (England) in 1988 with a BEng (Hons) in Elect. and Elec. Engg., where he was awarded a PhD in Electrical Engg. in 1992. Formerly employed by GEC ALSTHOM, as Senior Applications Engineer for the Chandrapur Back-toBack Scheme.
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