Connecting nuclear power plants to the national electricity transmission system via HVDC technology

This article highlights some of the key technical issues associated with the connection of large modern nuclear power plants (NPPs) to the national electricity transmission system via high-voltage direct current (HVDC) technology. T

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Sep 25, 2017
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Author(s): Richard Poole


he importance of the electricity system for such a connection is described. The need for reliable and secure supplies from the electricity grid to power the safety systems of the NPP is also discussed. Simulations carried out on the power system computer-aided design have highlighted the susceptibility of HVDC current source converter technology to commutation failure under a three-phase fault condition at the inverter when connected to a weak ac system. The work has also demonstrated the fault ride through the capability of the voltage source converter technology for the same scenario.


Nuclear power plants (NPPs) require a reliable and secure supply of offsite power from the national electricity transmission system (NETS) to ensure continued operation of the reactor safety systems during an emergency. If the supply is lost due to the tripping of a circuit breaker, for example, a switchover to alternate onsite power supplies will be required. Examples would include diesel generators, battery supplies or gas turbines. Following the Loss of all offsite power (LOOP) a reactor scram (shutdown) is initiated<>. The key difference between nuclear and conventional power plants is the heat that must be removed from the core of the reactor following a circuit breaker trip. A nuclear reactor, even with the chain reaction completely shut down, will generate significant heat from fission product decay. Unless this is removed in a controlled manner, the reactor core could overheat and lead to a dangerous situation [1].

The use of high-voltage direct current (HVDC) technology for connecting large modern NPPs to the NETS has been considered as part of the connection options on several UK projects. Some of these have included Hinkley Point C, Sizewell C, Wylfa Newydd NPPs and so on. The use of HVDC technology has not been utilised at the required power ratings (excess of 3 GW) in the UK before and is considered an unproven and a large technological risk [2].

For the first time, a significant amount of work has been undertaken to assess the feasibility of both current source converter (CSC) and voltage source converter (VSC) HVDC technology for such an application. Ratings and industry availability of both the technologies have been reviewed. The technical complexity associated with the control system interface of both the NPP and HVDC system has also been examined.

HVDC technology

This technology is primarily used for both long-distance bulk power transmission and for connecting asynchronous networks. Despite this, it does have many other applications. With dc transmission the power direction and level can be controlled accordingly. This can be done within hundreds of milliseconds and involves either an active power increase (run-up) or decrease (run-back) [3].

CSC HVDC technology has been well established around the world for the connection of large power systems and asynchronous networks. Power ratings of 2 GW or more are available with subsea cable technology. Ratings in excess of 8 GW are available with dc overhead line technology [4].

VSC HVDC technology is gradually becoming more established and has been deployed on numerous projects around the world. At the time of writing, voltage levels of ±500 kV and power ratings of 1800 MW can be achieved with a bipolar link [4]. Despite this there are indications from the industry that VSC ratings of 2 GW or more will be commercially available within the near future [4].

Connecting NPPs by HVDC technology

At the time of writing, no NPP in the world has been solely connected with HVDC technology for power ratings in excess of 3 GW [5].

Some of the new UK NPPs will require substantial grid reinforcement and maybe located long distances away from the nearest connection point. With the existing transmission infrastructure being inadequate for the required ratings, new circuits are needed for such connections. To avoid building ac overhead lines through national parks and environmentally sensitive areas, connection by subsea cables is being considered. Subsea cables would help mitigate both the visual and aesthetic impacts associated with ac overhead lines. However, due to distances in excess of 60 km on some projects, the use of ac cables as the distance increases becomes restricted. The application of dc subsea cables is considered an option due to the long distances encountered. To meet the capacity of NPPs in excess of 3 GW ratings, up to four dc subsea cables may be required [5].

Depending on whether CSC or VSC HVDC technology is adopted for an NPP connection, there are common technical issues associated with both of these technologies. However, there can be some additional benefits with the adoption of VSC HVDC technology.

NPPs and CSC HVDC technology

The following section discusses both the technical issues and benefits associated with CSC HVDC technology for the connection of NPPs to the NETS.

Commutation failure

If CSC HVDC technology is to be adopted, the strength of the generator connection point and the surrounding ac system must be strong enough to cater for both the reactive power and commutation voltage requirements of the dc connection. This is of significant importance at the inverter end of the link where commutation failure could occur if the voltage level at the point of the ac grid connection is too low. This can have an impact on both the reliability and security of the NPP and the surrounding ac system. A three-phase fault at the inverter can cause a commutation failure. The ‘commutation prevention function’ within the dc control system can help aid system recovery post-fault. However, if persistent commutation failure occurs the dc protection and control system will remove the HVDC link from the service. The NPP will have to survive this contingency through appropriate controller actions.

Accurate models and data of both the ac power system and the HVDC link are essential to analyse the impact of this phenomenon. Suitable mitigation actions and system contingencies can then be developed.

Sub-synchronous torsional interaction (SSTI)

Turbine generators can be subject to electrical environments that react with the shafts to produce resonance (torsional vibrations) at shaft natural frequencies. These vibrations can cause cumulative fatigue damage and result in the reduced component life of parts such as rotors and shafts. In some cases, adverse interactions have led to growing oscillations and shaft damage, including twisted couplings and broken shafts. The constant current controllers at CSC HVDC rectifier stations have the potential to reduce the positive damping on the nearby generating units. If the NPP is at the beginning of the transmission system via the dc link, the chance of SSTI occurring is increased due to the weakness at the point of connection. A detailed investigation of the torsional interaction behaviour between the generator units and the dc system over the frequency range of interest is required. To do this, all the relevant generator data (shaft inertia constants, masses etc.) and detailed dc/ac models are required to study the system in detail. A suitable damping controller can then be designed and applied to mitigate the effects of SSTI.

Power reversal

Owing to the change in voltage polarity required to change the direction of power flow in CSC technology, multiple switching events are required [6]. This particular function will be required under an emergency system condition. An example could be under the sudden trip of one of the other interties between the NPP and the ac system shown in Fig 1. However, the time required to complete the reversal process is too long to prevent system instability from an NPP perspective. Instant power reversal will also be required due to the thermal constraints associated with circuits in the ac system.

Fig 1: Single-line diagram showing the power system model developed in PSCAD

AC voltage control

CSC technology can be used to provide voltage support to the connected systems through appropriate active filter switching and firing angle control. However, careful monitoring of both the ac system and NPP is required in case a circuit breaker is opened (due to a fault/switching operation) and system overvoltages are encountered.

Reactive power control

Reactive power control can be implemented through similar control actions associated with the ac voltage control. In a weak ac system, due to the amount of reactive power required for minimal operation, care needs to be taken to avoid possible overvoltages on both the NPP and ac system in the event of an ac filter tripping. If the demand for reactive power from the ac system/NPP is low enough, overvoltages may also occur for this condition.

Operational tripping scheme (OTS)

An OTS will function to a set of operating rules that determine the action of the design in response to system events and states. In operation, the scheme operator will select which of the total set of rules will be active or inactive. For conventional OTS schemes on ac circuits the procedures and sequences of operation are well established and proven.

For dc schemes the action may take the form of different run-up or run-back quantities rather than a circuit trip. These have to be coordinated and carried out at the correct speed and rate to avoid possible system instability. When a dc OTS needs to interface with an NPP, the level of control complexity and coordination required increases. The station control of the dc system needs to interface with both the NPP and the surrounding ac substations. The latency and speed of control signals, operational sequencing, as well as co-ordination between the different ac/dc systems present a complex and high-risk challenge.

Power oscillation damping (POD)

Through fast active power modulation by the dc control system oscillations can be quickly damped out. The POD calculates an additional rate of change of power based on the frequency variation of the connected ac system. The power can be varied depending on the direction of power flow and can either be disabled during normal operation, or enabled under transient conditions.

Frequency control

The frequency control function calculates an additional rate of change of power based on the frequency variation of the connected ac system. Any measurement that exceeds the set values results in an error adjustment and the dc control system will implement the required change via an active power run-up or run-back signal. The power level will be adjusted to bring the frequency back within the required limits. This can be of benefit to both the NPP and the surrounding ac system under emergency conditions. Detailed system studies will be needed to determine the overall effectiveness of this particular control function.

The frequencies of ac systems interconnected through an HVDC system tend to fluctuate violently because of lack of synchronising power. Fluctuations in frequency have an unfavourable effect on an NPP because it applies an excessive stress to the turbine and varies the output power of the cooling water pumps, thus resulting in a variation of steam pressure. If the frequency in the NPP was to increase or decrease this can have a profound effect on the reactor and cooling pump motors causing them to stall [7].

To solve the above-mentioned difficulties of generator speed variation, it is necessary to control the HVDC system so that it produces a synchronising power equivalent to that of an ac transmission line. Suitable control system modifications between the turbine generator and dc control systems may be required to co-ordinate the frequency in a controlled manner. This can be achieved by introducing the integral type frequency controller as depicted in [7,8].

System stability support

The fast active power run-up or run-back function of the dc link can be used to deload or increase power supply to either the NPP or the surrounding ac system to aid system stability. The required run-up or run-back rates will need to be determined through detailed power system studies.

NPPs and VSC HVDC technology

The following section discusses both the technical issues and benefits associated with VSC HVDC technology for the connection of NPPs to the NETS.

Sub-synchronous torsional interaction (SSTI)

The risk of SSTI as a consequence of a VSC connection to a power system is similar to the risk proposed by the connection of a CSC. The risk is a consequence of interactions between the converter controller and the ac system. As with any HVDC project, contract stage studies would need to be undertaken to establish and to mitigate any risk of such interactions.

Power reversal

The speed at which power can be reversed in a VSC converter is dominated by the inductance in the circuit as power reversal is essentially current reversal. However, the speed of any such power reversal is dominated by the capability of the ac system to which the converter is connected to respond without becoming unstable. Providing the system is strong enough, power reversal may be completed within a few hundred milliseconds, subject to the latency of the communications used. This can prove to be useful to both the surrounding ac system and NPP. This is dependent on whether the time taken for the function is within the timeframes required for system stability purposes.

AC voltage control

The VSC system can act as a static compensator (STATCOM) if one end of the dc link is unavailable due to a fault or outage condition. This way the voltage within the NPP or surrounding ac system can be maintained through the ac voltage control function and can enhance the performance of the power system.

Reactive power control

The reactive power control is used under steady-state conditions The reactive power within either the NPP or the surrounding ac system can be kept within a designated level through appropriate control action. If an increase or reduction in level is required, this can be coordinated separately to the active power control providing this is within the operating limits of the converter power/voltage (PV) curve.

Operational tripping scheme

An OTS may need to be utilised and will involve the same high level of control complexity as that encountered with CSC technology.

Power oscillation damping

The same function can be utilised by VSC technology; however, due to its capability to control both active and reactive powers independently, either one or a combination of the two can be used to achieve the same purpose.

Frequency control

This function is also available with VSC technology and can be used to keep the frequency of the NPP and surrounding ac network within the required system limits.

System stability support

The fast active modulation of both the active and reactive powers independently can be used to enhance the stability and performance of both the NPP and the surrounding ac system.

Black start

The fast black start capability of VSC technology can be used to restart the surrounding ac system or NPP. This is particularly useful if supplies to the NPP are lost and the back-up diesel generators fail to start during the alternate power supply changeover sequence.

Half-bridge technology

If half-bridge VSC converters are used, under a dc side fault scenario the protective actions will result in the complete removal of the link from the service to prevent the free-wheeling diode rectification within the converter bridge itself. This will result in 100% power transfer lost through the affected link. The NPP will have to survive this contingency through appropriate operational procedures. Full-bridge VSC technology allows blocking to prevent this situation and providing the fault is temporary and successfully cleared; the link may be restarted.

System simulations

System simulations were carried out on the transient analysis software known as power systems computer-aided design (PSCAD) to analyse the system shown in Fig 1. A three-phase fault condition located on busbar 3 at the inverter end of the dc link was analysed for the two separate cases. Case 1 involves the CSC HVDC link and case 2 involves the VSC HVDC link (Fig 2).

Fig 2: Three-phase fault applied to busbar 3

In Fig 1, the 400 kV double circuit ac overhead lines (O1–O5) interconnect the four networks shown (A1–A4) to form the surrounding ac system. Each of the two nuclear reactors and associated ac switchyards are shown as N1 and N2. Nuclear Reactor 1 station (N1) is connected to the northern part of the ac system by a 400 kV double circuit ac overhead line. Nuclear Reactor number 2 station is connected in the southern part of the ac network by the HVDC link (H1). The data used for the power system components have been supplied internally by national grid electricity transmission. The dc link is represented as a ‘black box’ solution where greater detail of the inner model components is available. The loads and generators are reminiscent of those used on the NETS. Each of the reactor stations are kept separate to avoid a fault/outage on one affecting that of the other.

The parameters used for the ac system are shown in Table 1and the parameters for the HVDC link are shown in Table 2.

Rectifier side

Inverter side

S max, MVA

Voltage, kV



S max, MVA

Voltage, kV











Table 1: AC system parameters

Rectifier side inductance, H

Rectifier side resistance, Ω

dc line/cable capacitance, µF

dc voltage, kV

dc current, kA

dc power, MW

Inverter side inductance, H

Inverter side resistance, Ω









Table 2: DC line/cable parameters

The short-circuit ratio (SCR) is a measure of how strong or weak the connected ac system is and is given by the following formula:

where Ssc is the short-circuit capacity of the commutation bus; PdN is the rated power of the converter station.

To take into account the effect of the reactive shunt compensation on system impedance as seen by CSC converters and therefore give a better estimate of the total system strength the effective SCR (ESCR) is used.

This is given by the following formula:

where Ssc is the short-circuit capacity of the commutation bus; Qc is the reactive contribution from the shunt compensation (filters); and PdN is the rated power of the converter station.

Lessons Learned

When considering the application of HVDC technology for large NPP connections, there are certain technical issues that must be considered and investigated before this task is undertaken. These include the following:

  • The strength of the surrounding a.c. system is very important and will have a large influence on the interaction of the dc technology with this and the NPP.
  • If the surrounding ac system is weak and CSC HVDC technology is to be used, the risk of commutation failure and SSTI occurring needs to be considered carefully and mitigation measures will needs to be put in place to manage the risks.
  • Depending on the power flows and configuration of the power system, additional control actions may be required from both the NPP and dc link to manage the situation. These may include a fast reduction in active power by the Rapid Power Reduction System (RPRS) within the NPP to ensure stability is maintained and thermal ratings of circuits and plant are not exceeded.
  • If two dc links are connected in parallel, following the trip of one link a ramp in active power maybe required from the other, this will take a certain amount of time. If transmission circuits are out for maintenance, suitable operational tripping schemes (OTS) will need to be in place to ensure the security and stability of both the NPP and a.c. system is maintained.
  • Providing the power ratings are available, VSC technology would be better suited for the connection of the NPP in the above scenario. However, the strength of the connecting system will still have some influence on how the dc link behaves under both steady state and transient conditions.


Both VSC and CSC HVDC models have been successfully tested in PSCAD power system analysis software. Simulations have been presented for a single case scenario involving a three-phase fault at the busbar connected to the inverter end of the link. The studies have highlighted the susceptibility of CSC HVDC systems to commutation failure at the inverter for a close-in three-phase fault when connected to a weak ac system. The converters are able to deal with this situation using appropriate control actions; however, if persistent commutation failure occurs the dc link will be removed from service by the protection and control system. This will result in a 100% loss of power transfer through the affected dc link and the NPP will have to survive this contingency through appropriate procedures/actions. The fault ride through capability of the VSC has been demonstrated for the same fault condition. Once the fault has been cleared the recovery of the link to full power is quick and smooth. The STATCOM capability of the VSC converters is able to keep the ac voltage profiles in the NPP within limits during the contingency. At the current time of writing HVDC technology has never been used for connecting a large NPP to NETS at the power ratings required (>3GW) ever before. This may prove to be a large and unproven technological risk for the application of NPP connections. The high degree of technical complexity associated with the interaction of the different control systems associated with the HVDC link, NPP and ac substations requires further detailed investigations. In particular the latency of control signals and sequence of actions required for a range of system events presents high complexity and risk with such a system. However, with a combination of further work, detailed investigations, supplier engagement and with the continuous evolvement of dc technology, the application could yet be proven to be technically feasible in the future


The author acknowledges the cooperation and support of the National Grid Electricity Transmission Ltd and the University of Hertfordshire in the preparation and production of this paper.


  1.  ‘IAEA Nuclear Energy Series’, ‘Electric Grid reliability and Interface with nuclear power plants’, plants, accessed October 2014.
  2. ‘National Grid Electricity Transmission, North Wales Connections Project’., accessed October 2014.
  3. Arrillaga J.: ‘Flexible power transmission: The HVDC options’ (John Wiley and Sons, Canterbury, 2007).
  4. Ltd, ABB. HVDC General Presentation-Sari/energy., accessed September 2014.
  5. National Grid Electricity Transmission: ‘North West Coast connections report’ (System Design National Grid, 2012).
  6. Ltd, ABB. HVDC Light Its time to connect-Abb., accessed October 2014.
  7. Sagisaka Y.: ‘Coordinated control of PWR nuclear power plant and HVDC radial type transmission system’. Kansai Electric Power Co, Mistubishi Electric groups, 1987, vol. 107, no. 5.
  8. Ikawa M.: ‘Development of a coordinated control system for a BWR Nuclear Power Plant and HVDC transmission system’. Tokyo Electric Power Co, Tokyo, Japan. IEEE Transactions on power delivery, July 1986, vol. 1, PWRD-1.
  9. Devi R.: ‘Cigre Benchmark model’ (IEEE, 2012).

Case studies

Case study 1 simulation results

In Fig 3, the dc voltage at both the rectifier and the inverter has collapsed due to the commutation failure at the inverter. Owing to the sudden reduction in dc voltage, the current shoots up to 3.0 and 4.0 per unit at both the rectifier and the inverter. The rectifier current controller attempts to reduce the dc current by increasing the firing angle as shown. The rectifier enters into the inverter region approximately 10 ms into the fault. Here the angle order of the rectifier advances to 110° (minimum limit) by the commutation prevention function, increasing the commutation margin and eliminating consecutive failure during recovery. The firing angle at the inverter is reduced according to the voltage-dependant current order limiter (VDCOL) function to help increase system recovery [9].

Fig 3: Dc system profiles for three-phase fault applied to busbar 3

In Fig 4, after successful fault clearance there are current spikes at both the rectifier and the inverter once the ac voltage at the inverter has recovered. Owing to the commutation failure, as soon as the fault is cleared, the dc-link voltage reduces momentarily during recovery, causing an abrupt decrease in current order. This triggers an abrupt firing angle advance at the rectifier, which in turn causes a dip in both inverter and rectifier currents until normal order is resumed. During the system recovery harmonic and oscillations are present in both the rectifier and inverter dc voltages, respectively. During system recovery harmonics and oscillations are present in the dc voltage profiles of the rectifier and the inverter caused by the commutation failure and weak ac system connection. The voltage profiles on busbars 18, 20 and 27 have been unaffected by the fault due to the firewall function provided by the HVDC link. Owing to the large voltage depression at the inverter and temporary removal of the load, the reactor output power has experienced a slight decrease in output power during the fault. Once the fault has been cleared the reactor returns to nominal approximately 50 ms after fault clearance. The severity of the commutation failure has resulted in a longer recovery time of the reactor output power returning to nominal value. The commutation prevention function available within the dc control system can help aid recovery after the fault unless the voltage depression is high when the connecting ac system at the inverter is too weak. If commutation failure persists, this will result in the removal of the dc link from service by the protection and control system. The NPP will have to survive this contingency and depending on the running arrangements of the system at the time, some additional control actions may be required from the dc link to ensure the integrity of both the NPP and the surrounding ac system is maintained.

Fig 4: Ac system profiles for three-phase fault applied to busbar 3

Case study 2 simulation results

In Fig 5, the dc voltage and current on VSC 1 is unaffected by the fault due to the firewall function provided by the HVDC link. The ‘STATCOM’ function is unaffected and this helps to keep the ac voltage at the NPP interface busbar within limits by controlling the reactive power available within the system. The active power is temporarily reduced due to the collapse in AC voltage on VSC 2. The current at VSC 2 during the fault rises to 3.0 kA and the reactive power drops to zero. A temporary protective block may be required in practice to prevent overloading of the IGBTs until this condition has been alleviated. The dc voltage experiences a slight initial rise, but the control system keeps this constant during the fault. This in turn ensures a smooth recovery once the fault has been cleared by the protection and control system. Owing to the self-commutation capability of the VSC the link is able to recover and full power transfer is resumed 20 ms after the fault has been cleared. In Fig 6, the ac voltage at B3 has severely collapsed while the busbars in the NPP have been unaffected due to the firewall function provided by the dc link. The power transfer from the reactor through the link has decreased during the fault but recovers within 20 ms once the fault is cleared.

Fig 5: VSC profiles for three-phase fault applied to busbar 3

Fig 6: Ac/dc profiles for three-phase fault applied to busbar 3

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Richard Poole

HVDC/FACTS Technical specialist, National Grid NSL HVDC interconnector project

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