HVdc Transmission

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Name: Manitoba Hydro HVdc Transmission System

Description: The most important source of generation in the Manitoba Hydro system is the Nelson River. Multiple plants have been and are being developed. Transmission of the energy produced in the Nelson River plants takes place though multiple HVdc transmission systems.

When: Planning for the development of the Nelson River and associated transmission began in Manitoba Hydro in the 1950’s. Construction of the first generation began in 196x and construction of the HVdc transmission system began in 196y. Development of the Nelson River and associated transmission continues today.

Where: The works described in this article are located in the Winnipeg area, a transmission corridor from Winnipeg to Gillam and multiple generation sites on the Lower Nelson River (east of Gillam).

Why: When the Nelson River was being considered for development, readily accessible, economic sites for generation in Southern Manitoba were approaching full development. Alternatives to continued development of the hydro-electric resources in the province were either thermal or nuclear. Planners determined that the development of the Nelson River was the most economic alternative at that time.

How: The system has been developed and will continue to be renovated and expanded over a period of many years. The development has involved Manitoba Hydro engineers and technical staff, consultants and manufacturers.


The development of hydroelectric generation on the Nelson River required a transmission system appropriate for the level of generation to be developed and the distance from the generation source to the load centre (Winnipeg). The choice was made to transmit the energy using high voltage direct current (HVdc) technology.

HVdc transmission was first developed on a commercial basis in the 1930s and at the time of the design of the Nelson River transmission system it was a relatively mature technology, based on mercury arc valves and analog control systems. The transmission system requires more sophisticated equipment than a typical ac system. There is equipment on both ends of the transmission line (converter stations) to convert ac voltage and current produced by the generators to dc current and voltage and back to ac. An ac system with similar capability would have required multiple parallel lines and sophisticated reactive power compensation at each end and at one or more new stations along the lines. DC uses a simpler two pole transmission line and extensive active and passive equipment to minimize adverse impacts on the ac system and to ensure reliable operation. Overall, for a transmission system of the length of the Nelson River transmission system, losses are lower than for a comparable ac system and dc is the economic choice.

Development of the HVdc transmission system started in 1966, with first power transmitted on Bipole I (1620 MW at 463.5 kV per pole) in 1972 and Bipole II (2000 MW at 500 kV per pole) in 1978. The system has undergone extensive rebuilding and will be expanded further with Bipole III as early as in 2017.

Successful dc system operation requires at least:

• Ac generation designed to withstand the effects of dc conversion and transmission • • An ac system to transmit the generated power to the rectifier stations • • A rectifier station to convert ac power to dc power • • A dc transmission line (two pole) built to minimize external electromagnetic and electric field effects • • An inverter station to convert dc power back to ac power • • A fast communications system interconnecting the rectifier and inverter stations • Each of these components had to be designed, tested and developed to make the project work. Detailed descriptions of each component follow.

It is possible to transmit electrical power over long distances by ac. Hydro Quebec has done so using multiple lines at 765 kV.

The power transmitted on an ac line is approximately:

Pac = Vs * Vr * sin θ / Xc

where Vs and Vr are the RMS values of the Sending and Receiving system voltages, respectively, θ is the phase angle difference between the two voltages and Xc is the reactive impedance of the line.

To increase the power transfer the choices are to increase the operating voltage and to reduce the impedance. At the time that the transmission system for Nelson River generation was being planned, the practical highest transmission voltage was 735 kV (first used by Hydro Quebec for its long distance transmission system of the James Bay project). A reduction in impedance is achieved though the design of the wire configuration, the presence of series compensation (series capacitors to counteract the natural series inductance of the line) and the number of lines in service. During the planning phase for the Nelson River a 500 kV ac alternative was evaluated and was found to be more expensive. It would have required 5 circuits, with 4 to 5 stations (for compensation) and 75% shunt and 60% series compensation. A 700 kV option seems to have also been considered, in less detail, with 3 circuits required and 2 intermediate stations. At that time, some of the issues associated with high levels of compensation (for example, sub-synchronous oscillations) were not known.

An ac transmission system requires the generation to operate at the same frequency as the system receiving the power and, as can be seen from the approximate power equation, the phase angle difference must be less than 90 degrees – the angle of maximum transmitted power.

In contrast to ac transmission, which responds to system events (outages on the generation and transmission) by changing the transmitted power (a system contingency will affect the ac voltage level and/or the phase angle difference). HVdc transmission is highly controllable and, with the exception of faults close to the converter station ac buses, relatively immune to ac contingencies.

When HVdc transmission is employed, it is possible to operate the generation unsynchronized from the system receiving the power. This allows the generation to respond to a range of contingencies without stressing the transmission system or the generators. The generators must be designed to run at over and under speeds and to accept a reasonable range of harmonics produced by the HVdc conversion process. In the Nelson River case, the generating units were expected to run at up to 84 Hz (40% over the 60 Hz nominal frequency) and down to 54 Hz (10% below the nominal frequency). This is not onerous, since the unit could over-speed beyond 84 Hz if the governor fails and the load on the unit is lost.

Hydro-electric generation, such as the Nelson River generation, is more robust with respect to off-nominal operation than a nuclear or thermal unit would be. These other generation types have turbines and shafts that can resonate as the system frequency deviates from the nominal frequency.

Collector System

A collector system is a relatively small ac transmission system designed to deliver the generated power to the rectifier station. In the case of the Nelson River, the initial system comprised several short 138 kV lines from Kettle Generating Station to Radisson Converter Station, the rectifier station. In the initial planning of the collector system, 138 kV and 230 kV options were considered, with Kettle and Long Spruce Generating Stations connected to Radisson and Limestone isolated with Bipole II through a second converter station designated as Henday Station. The choice of 138 kV was an economic one. Connections to Kelsey Generating Station and the city of Thompson were available from Radisson at 138 kV and 230 kV respectively.

The northern system (collector system) was ultimately developed differently than initially decided. There are advantages to being able to move more generation to whichever bipole is operating at the highest rating. Isolation would have limited that flexibility. Development of the lines to Long Spruce and Limestone was done at 230 kV, so three auto-transformers (138 kV to 230 kV) were provided to allow power from Long Spruce to flow to Radission (and vice versa, power could be transmitted from Kettle to Henday, the site of the second rectifier station). The initial choice of 138 kV did impose some constraints on the operation of the collector system in extreme contingencies due to the limited ratings of the auto-transformers.

HVdc Theory

While the actual detailed design of a HVdc system is quite complex and sophisticated, the basics operating principles are straightforward.

The ac system operates as a 3 phase system, while the dc system requires only two conductor. Transformation from 3 phase ac to dc occurs in a bridge, comprising 6 controllable switches, termed valves. The control system of a dc converter ensures that at any one time a maximum of three of these valves are conducting, providing a path for current to flow from one phase of the ac system, through a converter transformer, into the dc system, then back into a different phase of the ac system. The dc current is flowing through a large inductance, so current cannot be transferred from one valve to another instantaneously – there is a process where the current through one valve is dropping, while it is rising in the most recently conducting valve. This process is called commutation and it is the reason why there may be three rather than two valves conducting at any one time.

This diagram shows currents flowing in the ac system (the transformer is to the left with phases R, S and T) in the valves and dc line (a load, rather than an inverter, is shown). The valves are triggered in the order indicated by their number 1,2,3… and in this case valves 1 and 2 have been conducting and valve 3 has been triggered and is taking on the current that was flowing in valve 1.

This figure shows the situation at the rectifier, where the sinusoidal voltages are shown and the waveforms at the top left have just crossed, indicating a positive voltage across a valve. The voltage on the dc side continues to follow the sinusoid downwards until the a

Theoretically a valve can be triggered at the instant of zero ac voltage, however, practically that is not possible because for the valve to actually start conduction it needs some voltage across it. Therefore the triggering of the valves is delayed by some delay angle α, When a valve is triggered into conduction at α, the current through it starts rising , while decaying in the outgoing valve, over a period referred to as the overlap angle µ. This angle is a function of the inductance in the circuit and the value of the dc current.

Increasing αresults is a reduction of the average voltage on the dc side.

At the inverter, a similar process occurs but firing is delayed beyond 90 degrees until theoretically 180 degrees. However, in practical terms, it is typically limited to about 155 degrees. The overlap angle µ at the inverter has exactly the same definitions as the rectifier, however, there is an additional angle that needs to be defined which is referred to as γ. γ is defined as the angle between the current ending (zero) in the valve to the voltage reversing polarity (going from negative to positive) on the same valve and obviously it occurs at the end of the conduction. In the figure below, βis defined as 180 – α.

Since each ac phase voltage has a sinusoidal form, with voltage reversals every cycle (in North America there are 60 cycles per second = 60 Hz) the control system ensures that a new valve is closed at the right time to ensure a continuous dc current. The valves are only capable of current flow in one direction. They also cannot be opened on command and only open when the current through them drops to zero. For the design of Bipole I, mercury arc valves were the switching elements. At the time of this development, the

Bipole 1 was designed utilizing mercury arc valves, and at that time it represented the highest dc voltage and dc current rating in the industry. This was the last installation of a mercury arc valve design, while Bipole II was the first installation of a water cooled semiconductor (thyristor) design.

The key quantities associated with an HVdc system can be expressed in these equations:

Vdc = Vac N cos (α (or γ)) - 3 Xc Idc /π

Pac = Pdc = Vdc Idc

Qac = Pdc tan φ (up to 60% of real power - always into converters for a line-commutated system such as Bipole I and II)

N is transformer turns ratio, Xc is the commutating reactance of the converter transformer

The converter power factor cos φ = Vdc / Vdco or ½ [ cos α + cos (α + μ)]

The mercury arc valves have now been replaced by solid state (thyristor) valves of comparable ratings.

Looking at the various waveforms in both the ac and dc systems shows that the dc current is essentially constant, while the ac current contains characteristic harmonics of the ac voltage (5, 7, 11, 13, 17, 19, 23, 25,…) (np±1 where n = 1,2,3…and p is the pulse number - 6 or 12) while the dc voltage contains 6, 12, 24, 36. … harmonics (np). The ac harmonics can have adverse effects on connected ac equipment, including generators, and therefore ac harmonic filters are essential to reduce the level of harmonics in the ac system to acceptable levels. Similarly, dc side filters reduce the level of dc voltage harmonics, as these can interfere with communications equipment, for example.

While Bipole I was built with 6 pulse technology (3 phase input to a 6 switch configuration), Bipole II and any modern dc system uses 12 pulse converters. A twelve pulse converter is comprised of two six pulse converters connected in series on the dc side and in parallel on the ac side through a Y/Y and a Y/Delta. This configuration is taking advantage of the 30 degrees phase shift between the Y and the Delta voltages to cancel some of the harmonics.. Analysis of the waveforms in this system shows that the ac harmonics at odd harmonic sets (i.e. 5, 7, 17, 19) are essentially cancelled greatly simplifying the design of the ac filters.

Ac filters at lower frequencies are tuned filters with narrow resonance bands. As such, the design of the filers must consider the whole collector system design, to ensure that resonances within the generators, collector system and converter station filters are such that excessive voltages do not occur as the frequency of the units varies in response to system contingencies. In the Nelson River system, the issue is managed by a complex set of operating restrictions which link allowable filter configurations with line and generator configurations. In some situations, tripping of specific filters may occur during contingencies to avoid particularly bad resonances. In a modern HVdc link such operations are managed by a sophisticated control system referred to as a Reactive Power Control or RPC.

Ac filter design is simpler in the receiving system (southern Manitoba) since the frequency does not vary over a wide range.

There is another effect from firing delay – the converter valve requires (consumes) reactive power in an amount that varies as a function of the firing delay angle. The reactive power required is in the order of 60% of the real power being transmitted for steady-state conditions.

At a rectifier it is normal for this reactive power to be provided by the ac filters (which arte capacitive at nominal frequency) and the generators (which can be designed to provide reactive power at a fairly nominal cost for normal conditions).

The consumption of reactive power has consequences for contingencies associated with the integrated ac and dc systems. Loss of dc transmission or a portion of it, depending on the HVDC loading, as a result of faults leads to a temporary excess of reactive power in the system, resulting in potentially dangerous overvoltages. Similarly, some dc contingencies result in temporary increases in reactive power consumption, with a risk of low ac voltages and potential protection operation.

The firing delay angle at the rectifier is between 5 and 15 degrees for normal operation.

At the inverter the delay angle is larger than 90 degrees, and typically it is around 140 degrees. However what is really important for the inverter is the extinction angle γ. It determines the capability of the inverter valve to recover and withstand positive voltage again following conduction. A typical value for γ is 18 degrees for a 60 Hz system such as the Nelson River system. Smaller values of γ would lead to the outgoing valve re-conducting which causes a disturbance to the dc power. This phenomena is referred to as commutation failure. Often, and certainly in the Manitoba Hydro system, the inverter station (Dorsey) is located a long way from generation sources which could provide reactive power. Therefore, Dorsey station contains rotating machines, referred to as synchronous condensers (sometimes synchronous compensators). A synchronous condenser is basically a synchronous motor operating with no mechanical load. Dorsey station has 6 machines rated at +150 MVAr -60 MVAr and 3 machines rated at +300 MVAr –150 MVAr. Each has some overload capability and the combination of units is controlled on a steady state basis to ensure headroom for control actions (i.e., there is balancing of the loading according to rating).

Beyond the supply of reactive power, synchronous condensers (compensators) have the characteristic of supplying system strength. System strength refers to the ability to supply short circuit current by virtue of having an internal voltage source. (Synchronous condensors have an excitation system that controls the magnetic field generated by the machine rotor. This magnetic field induces a voltage on the stator of the machine.)

It has been found that successful operation of a conventional HVdc system requires a minimum system strength – this is normally calculated as a multiple of the rated HVdc power. The critical ratio is the Effective Short Circuit Ratio and is calculated as

ESCR = System MVA – Filter MVAr


This number should be at least 2.5 for successful operation. Manitoba Hydro operates with an ESCR from 2.5 to 3 at the inverter.


Several contingencies can affect power transmission on an HVdc link. At the rectifier, a fault on the ac system will reduce the voltage and the result will be a reduction in dc voltage to the point where the dc current may drop to zero. Through control of the firing angle, the system can maintain current for distant faults, but once the minimum firing angle is reached, the rectifier dc voltage will fall below the inverter voltage, resulting in the current dropping to zero. The HVdc controls will intervene and reduce the inverter dc voltage accordingly to sustain dc transmission, perhaps at a lower level than before the disturbance.

At the inverter, ac faults will usually result in commutation failures, mainly because as described earlier the outgoing valve did not get enough deionization time and can not withstand the reapplied positive voltage. The degree of commutation failures depend very much on the fault, and the control system

Once the ac fault is cleared, transmission will resume. In an ac system, a fault (a connection between phases or from one or more phases to ground), the current flowing through the fault is uncontrolled and dependent only on the system short circuit level (related to the number of generation sources near the fault) and the impedance of the fault.

In a dc link, for essentially any fault, the link is controlled and the current is limited by control action. The speed of control is mainly limited by the ability of the ac system to accept the impact of the control action and the speed of the control and communication system.


While an HVdc link can be operated without communications, this is a rare emergency form of operation. Normally, a high speed communication system between the inverter and rectifier stations is required. At one of the dc terminals, the requested power transmission level for the link is used to calculate a current order. The current order is coordinated between both terminals by the communications system. Additional control and protection signals are used to ensure that control and protection actions at both terminals are coordinated.),

In the Manitoba Hydro situation, a microwave system was installed (and shared with MTS) with a backup system using railway communication wires. The system has now been upgraded with fibre optics and microwave paths.

A major advantage of an HVdc link resulting from its controllability is that the link can be used to improve the performance of the interconnected ac systems. In the Manitoba Hydro situation signals are developed to improve the damping of both sending and receiving ac systems, to prevent run-down of units under overload conditions and to protect ties lines if one of the tie lines should open under export conditions. The controllability of the link has saved major capital investments that would otherwise have been required to produce the same level of performance.


Normal operation of a dc link uses one dc converter pole connected to one dc line. However, in the event of loss of one or both conductors of one of the dc lines, the system can be reconfigured to put two dc converter poles on one line (i.e., the positive pole of Bipole I can be connected in parallel with the positive pole of Bipole II). The mode of operation is called paralleling and it is possible because of the controllability of the dc links. Paralleling is a form of multi-terminal dc operation.

Since paralleling requires two dc poles to operate at the same pole voltage, it is only possible when the dc poles are fully available (i.e., 3 groups on Bipole I and 2 groups on Bipole II, with the dc voltage of Bipole II adjusted downwards to meet the maximum voltage of Bipole I. In emergency situations, this ability is very valuable. Although the current is doubled on the line, and losses are therefore 4 times normal, the line was designed for such operation and there is a net benefit to operation in paralleled mode.

Ground Electrodes

An essential part of a dc link is a connection at the low voltage end of a pole, to ground, at one terminal of the link. This is to provide a ground reference for voltages on the dc equipment. In the Manitoba Hydro case, ground connections are present at both the rectifier and inverter stations. If one pole is out of operation, the full current flowing in the operating pole will flow in the ground connections (ground return). Ground electrodes are designed to handle such currents for a certain duration. While the dc line resistance is in the order of 15 ohms, the ground path resistance is in the order of 0.1 ohms.

Even in normal operation a small amount of current will be flowing through the ground connections as a result of slight differences in tuning of the current controllers on the two poles.

Dc currents flowing in the ground can have negative impacts on buried equipment, such as pipelines, and mitigation is used to minimize the impacts. While ac ground currents will tend to flow near the surface, dc currents tend to flow very deep in the earth.

DC Line Design

There are presently two dc lines from the Nelson River (Radisson and Henday stations) to Winnipeg (Dorsey station). The distances are 895 and 937 km respectively. The conductors for each line are carried on guyed towers with each pole conductor formed by two bundled sub-conductors (i.e., one pole of the line has two conductors held is close proximity by spacer dampers and clamps, operating as if it were one conductor).

Each conductor is 4 cm diameter. There are about 7400 km of conductor in the two lines [(4*895 + 4*937) plus sag].

The guyed towers have an average height of 38 m, the height being a function of the required ground clearance, the span between towers and the topography.

To minimize the acoustical, electrical and magnetic effects of the dc lines outside of the right-of-way (137 m wide) the system is operated so that the conductors farthest apart are operated at negative polarity while the inner two conductors are operated at positive polarity.

In 2001 a major program of replacement of the spacer dampers was undertaken. Carts suspended from the conductors were used to get access to the spacer dampers, all of which are located within the spans. Access to the carts was by helicopter. http://tdworld.com/mag/power_aerial_damper_changeout/

Kettle Generating Station was in-service before Bipole I was ready to transmit power. The first option form Kettle power was to transmit the output of units 1 and 2 over the 138 kV network. Then there was a temporary reconfiguration of the conductors of lines 1 and 2, to permit a very unbalance ac line to be created between Radisson and Grand Rapids, where the dc lines pass near that station. Because of the unusual parameters of the resulting line, transmission was very limited – to roughly 150 MW,


Bipole I has been in operation since 1971. Bipole I was completed (all valve groups in service) in October of 1977.

A major upgrade was undertaken in response to the aging mercury arc technology and to take advantage of the superior performance of the thyristor valve technology.. This work was completed in November 1993. In the upgrade, each pair of mercury arc valves was replaced by a two-valve thyristor assembly.

Bipole 1 Replacement Thyristor Valves

A unique aspect of the original Bipole I design was the presence of a bypass vacuum switch across each valve group for the purpose to use the start and shutdown of the valve group..

The first pole of bipole 1 of the upgrade was supplied by GEC Alsthom, and the second pole by Siemens.

Bipole II first stage was completed in October 1978. The second stage was completed in May 1985. Development of the bipoles was staged with development of generation. Kettle was completed in 1974, Long Spruce in 1979 and Limestone in 1992 (started 1985, first generation in 1990).

As mentioned above, Bipole II was the first application of water coled thyristor technology. At that time, thyristor ratings required two thyristors in parallel to handle the 2000 A requirement. Modern thyristors have much higher ratings (up to 4000 A) When and if these valves are replaced, the valve design will be much simpler.


With the complexity of HVc links comes the risk of obsolescence. Bipole I was built with control equipment based on the digital logic of the time, TTL. Finding replacement logic is now a problem. Modern control systems use modern technology, such as microprocessors, but these too have risks in terms of finding spare parts compatible with the original equipment.


When Bipole I was being planned, planning study tools were available but limited in capability. At that time, manufacturers used simulators that could incorporate the real control systems but operate at much lower power levels. These large analog computers were expensive and limited in terms of data gathering capability and detail. For Bipole I Manitoba Hydro made use of simulators at English Electric, Stafford, England (the supplier for Bipole I). For Bipole II, they used simulation facilities at IREQ, the research arm of Hydro Quebec. Power flow and stability simulation was possible using software from Westinghouse and General Electric.

Today, sophisticated software like EMTDC/PSCad (from the Manitoba HVDC Research Centre) and hardware like RTDS (From RTDS, Winnipeg) provide a high degree of confidence in the performance of the dc equipment and the integrated ac-dc system. Other sophisticated study tools were developed by the Manitoba HVDC Research Centre, working with IREQ and the University of Wisconsin – Madison, for EPRI. These tools are now part of the software suite from PowerTech, the research arm of BC Hydro.

Operating Philosophy

The design of an HVdc link segregates functions to the greatest extent possible – with groups, poles and bipoles each representing a differentiation in control and protection. This means that the first contingency for a dc link s loss of a group. Loss of a bipole should be a very rare event, brought on by a contingency that affects equipment common to both poles (such as equipment connected to the ground electrode). Modern dc links are designed and built for one bipole outage every 2 years? The experience of Bipoles I and II are reported every year to Cigré (International Council on Large Electric Systems - Conseil International des Grandes Réseau Électriques). http://www.cigre.org

The source of power for the Manitoba Hydro HVdc system is generation on the Lower Nelson River. This is discussed in detail in the article on Manitoba Hydro Lower Nelson River Generation Development.

Key Players:

MH – Ernie Scott, Len Bateman, Lindsay Ingram, Tom Storey, Clarence Thio, Alf Buelow, Fred Jost, Don Simons, Chris Goodwin, Oliver Norris-Elye, Ken Ouelette, David Cass-Beggs, John McNichol and later Doug Chapman, Brett Davies

MH Generation – Mac Uloth (Limestone)

AECL (owner of Bipole I and lines) – Bob Hamlin, Dick Haywood, Art Derry

Teshmont (a joint venture of Templeton, Shawinigan, Montreal Engineering) Rubin Shemie, Ron Harrison, Bob Burton, Dave Fletcher, Arun Ogale, V. Burtnyk?, I. Reinart, R. Radley, L. Chin

Dominion Bridge (towers) F. Stock, D.L.T. Oakes

U of Manitoba - Michael Tarnawecky


Proceedings, Manitoba Power Conference EHV-DC, Winnipeg, Canada 1971

The Background to HVDC in Manitoba – T.E. Storey, J.S. Foster

Single Line Diagram of the Nelson River HVDC Transmission System – R.E. Harrison

Nelson River HVDC Terminal Station Layout – R.K. Shemie, A.F. Buelow

Nelson River Converter Station Auxiliaries and Power Supplies – R.G. Radley, L.S. Chin

Nelson River HVDC Transmission Line Foundation Design Aspects – I. Reinart

Nelson River HVDC Transmission Line Towers – D.L.T. Oakes

Contructional Aspect of the ±450 kV DC Nelson River Transmission Line – B.L. Barry, J.G. Cormie

Radio Interference and Corona Loss Measurements on “Nelson River” Conuctors – R.M. Morris, A.R. Morse

Harmonic Interference from DC Lines – K.R. Ouelette, D.W. Lewis

AC Filters for the Nelson River Transmission Project – D.E. Fletcher, C.D. Clarke

Ground Current Return Electrode Design – R.K. Shemie, D.S. Simons

Insulation Coordination for the Nelson River Converter Stations – D.E. Fletcher, F.G. Goodrich

HVDC Transmission Control Schemes – M.Z. Tarnawecky

Control and Protection Aspects of the Nelson River Transmission Project – A.A. Burrow, B.A Rowe

Us of HVDC for Improving AC System Stability and Speed Control – R.W. Haywood, K.J. Ralls

Nelson River Transmission Project, Telecommunication Requirements and Design of Signal Processing Equipment – Y. Picot, C.J.B Martin

IEE Fifth International Conference on AC and DC Power Transmission, London, 17-20 September 1991

The Integration of new valves and controls to Nelson River HVDC Bipole 1 – F.G. Goodrich, J.L. Hancock, B.A. Rowe and H.L. Thanawala (GEC Alsthom Transmission & Distribution Projects Limited), D.B. Willis (Manitoba Hydro)

On the design ,testing and operating experience of composite dry bushings in HVDC – M.M. Rashwan and W. McDermid (Manitoba Hydro), F. Hammer and A. Küchler (F&G Hochspannungsgeräte)

1980 International Conference on Overvoltages and Compensation in Integrated AC-DC Systems

Switching Overvoltages on the Nelson River HVDC System – Studies, Experience and Field Tests – C.V. Thio, J.R. McNichol, W.M McDermid, D. Povh, W. Schultz

Impact of the Winnipeg – Minneapolis 500 kV AC Interconnection on the Operation of the Nelson River HVDC System – D.A. Woodford, W. Koschik