Prepared for the Institution of Engineers in Scotland, by Colin Bayfield MSc, CEng, FIET.  Retired Industry professional.


Reducing carbon emissions from energy systems requires adoption of clean electricity generation and substitution of carbon fuel combustion with electricity in heating and transport. Renewable electricity from wind and solar currently play a significant and increasing part but they introduce increased technical risks which need to be managed. These increased risks come about from the major change in grid system characteristics which required radical changes in the way the network is planned and operated to ensure that the quality and security of supply is maintained. The increased exposure to extreme weather events adds to this changing background resulting in an elevated risk of a major system failure. The traditional generation capacity surplus [see glossary 1] and operating margins [see glossary 2] are significantly depleted and the ability to recover from a grid failure or partial grid failure is under question. There is a need for long term sustainable energy planning with less reliance on short term market solutions.


A measure of the resilience of a system is its ability to return to normal after a breakdown (which may be local, regional or national in its field of disruption). The electricity supply system in Britain, which has provided reliable energy supplies for decades, is undergoing a radical transformation in pursuit of zero carbon emissions. The headline changes are from a system based on large thermal power stations to one with a high penetration of intermittent renewables such as wind and solar. The number of HVDC Interconnectors [see glossary 3] has also increased significantly. This transformation is changing the supply system characteristics from being highly controllable and highly stable with low technical risk to a system with a large proportion of highly intermittent generation, less stable and with enhanced levels of technical risk.

The causes of major system disturbances that may lead to system blackouts may be summarised as follows:

  • Electricity supply is unable to meet high demand, resulting in progressive automatic disconnection of demand across the Grid System.
  • Severe weather events that cause the network to be depleted beyond the level for which it is designed or intended to operate.
  • Lack of system inertia impairing the ability of the System Operator to match the system generation output to changing system demand and the ability of the network to recover automatically from transient faults.
  • Other exceptional events, e.g. solar storms, cyber security breaches, unforeseen technical anomalies etc.

Major supply interruptions are thankfully rare in GB. When they occur, they are often the result of a combination of the above issues. However, the increase in severe weather events from climate change and the significant change in characteristic behaviour of the grid system resulting from the large-scale integration of renewable generation give rise to an overall increased probability of a major system failure. Given the societal reliance on the electricity supply and the profound impact of a widespread blackout, it is imperative that recovery from such an event should be fast as practically possible.

Network Issues Contributing to Major Network Failure

The Grid System Operator (SO) and Transmission Owners have Licence obligations to plan and operate their networks to be compliant with the National Electricity Transmission System Security and Quality of Supply Standard (NETS). This provides a prescriptive minimum level of network capacity and defines the levels of network security under normal operation and under system maintenance conditions, to accommodate credible network faults. In simplified terms, credible faults are assumed to be a double circuit fault (both circuits faulting on a double circuit tower line) or two separate single circuit faults. Under more frequent extreme weather events from climate change, this conservative level of system depletion may be exceeded several times and may increasingly result in significant loss of supply.

Under post fault conditions the SO is required to re-secure the network by re-despatching generation to reduce the flow over stressed parts of the network. However, as the amount of controllable generation has been significantly reduced, the opportunities of the SO to re-secure the network post fault have also reduced. The output from renewable generation cannot be increased beyond its normal output, only reduced under emergency conditions.

Generation Security

The closure of all coal fired power stations has resulted in severely depleted plant margins, defined as the difference between maximum demand and available generation to supply it. A number of nuclear generators are nearing their end-of-life, which will deplete the margins even more. This, along with the reluctance of developers to engage in new generation projects and the much-delayed nuclear fleet replacement, has resulted in Ofgem seeking to promote a number of mitigation initiatives including Demand Side Management (contractual demand reductions), increased HVDC Interconnectors to Europe and Energy Storage initiatives (batteries).

For network planning purposes, the transmission licensees make a statistical assumption that 60% of wind capacity is available to supply the system demand. However, the maximum demand for electricity often occurs when there are very small quantities of renewable generation available. This may happen when a large high-pressure weather system sits over Europe resulting in very little wind generation and hence no Interconnector import capability. Hence generation security places a high reliance on gas imports from Russia and Norway. This situation is getting progressively more onerous as the ageing nuclear generation fleet retire, against a background of increasing electricity demand from electric vehicles and electric heating (including the replacement of gas central heating boilers by resistive heating and heat pumps). The NGC future energy scenarios (ref 1) predict that the peak demand for electricity will increase from about 59GW today to about 78GW by 2050 under three of their future energy scenarios. It is unclear where this firm generation capacity will come from.

Changing System Characteristics

The change in characteristics of the electricity supply system has required continuous changes to the Grid and Distribution Codes (the technical codes that govern the operation and planning of the Transmission and Distribution networks), to ensure that new plant technologies do not adversely affect the security and quality of supply. With the reduction in the number of heavy fossil fuel generators, the inertia of the grid system has significantly reduced [see glossary 4]. Wind turbines (and solar generators) make no contribution to the inertia of the grid system because they are electrically de-coupled through their DC/AC power inverter control systems. This affects the grid system performance in a number of ways.

With a lower inertia system, the rate of change of frequency is greater when there is an imbalance between generation and demand, so the governor response [see glossary 5] provided on generators to increase their output in order to keep the frequency within operational limits has to be faster. This is not a problem for gas turbine generators or where HVDC interconnectors are providing the response, but the output from wind farms (or solar panels) cannot be increased, only decreased under emergency conditions. Furthermore, the older designs of nuclear generators are not capable of providing a significant response level because their rate of change of output is too slow. When the output from wind and solar generators is high and demand is low the proportion of generation capacity with sufficient response will make it difficult for the SO to contain the frequency within operational limits. This would be particularly difficult if the level of generation loss approaches or exceeds the infrequent generator loss limit [see glossary 6] and may result in low frequency demand shedding. This was a factor with the load shedding event in August 2019 when a lightning strike caused the Hornsea windfarm and Little Barford gas turbines to trip. Notably there was also a loss of about 500MW of embedded generation [see glossary 7] that tripped because of the low frequency deviation, highlighting the vulnerability of embedded generation providing additional operational uncertainty for the SO.

When a fault occurs on the transmission system, the transient response of generators must not cause them to lose synchronism [see glossary 8]. With significantly reduced system inertia, the rate of change of frequency will be higher during faults and stability limits (assessed by computer simulation) may impose significant power flow restrictions on the operation. This issue has required the SO to consider an additional ancillary services market for ‘system inertia’ and ScottishPower is seeking to install Synchronous Compensators [see glossary 9] on their transmission system, to maintain the Anglo-Scottish power transfer capability. The need for such devices poses a legitimate question as to who should pay for restoring system inertia caused by the closure of coal and nuclear stations. Should this fall on the operators of the remaining rotating machines, should it be the operators of the new, low-inertia generation or should it be their customers?

A significant proportion of the equipment installed on the transmission and distribution systems has complex power electronic control systems. The modelling required to securely and comprehensively integrate these control systems is very challenging and may not always adequately represent the real system behaviour. Unintended adverse resonant control system interactions, overlooked by inaccurate modelling, may occur; particularly under unusual or extreme operating conditions. This could lead to significant disruption to electricity supplies.

Black Start

The probability of a complete or partial failure of the British grid system is very small but, for the reasons given above, it is increasing. The societal, financial and political consequences of a major blackout are substantial so the SO has a Licence obligation to operate a viable Black Start procedure. The procedure requires all generators with a Black Start capability to start independently and supply island loads [see glossary 10], before the SO reconnects the islands to restore the complete system. The process of synchronising the islands may take considerable time. A significant part of the generation portfolio with Black Start capability used to reside in the coal fired fleet but these facilities are now all being decommissioned. Since Longannet power station closed, the ability for supplies to be restored to the central belt of Scotland following a Black Start has been severely compromised. The delay to re-establish supplies from England could now take up to 5 days.

Recognising this unacceptable recovery time, a funded innovation project, ‘Distributed ReStart` (ref 2), promoted by ScottishPower Energy Networks, with partners National Grid SO and consultants TNEI, will investigate a bottom-up approach to Black Start recovery. The project seeks to use the large volume of distributed generation now connected to the grid, to play a role in Black Start recovery. However, there are formidable technical, organisational and procurement challenges to overcome. In addition, the majority of this distributed connected generation is renewable energy sourced and might not be available without wind or sunlight at the time of need.


The radical changes in the electricity network in pursuit of net zero carbon emissions include great cost and technical risk. Our reliance on electricity in the modern world is not appreciated until there is a loss of supply for a significant period of time. The partial grid failure in August 2019 provided a stark reminder of the effect of an electricity blackout, although this event was minor when compared to some other well documented, widespread blackouts that have been experienced in various countries of the developed world.

The current measures taken to manage the worryingly low plant margin are in the main short term and significant predictable firm generation capacity is required if the increasing demand from electric vehicles and electric heating is to be met.

It is imperative that the grid system issues caused by reducing inertia and increasing intermittency are better managed and resolved. The current industry regulatory framework seeks to promote renewable generation without adequate consideration of the operational security and cost impacts. The System Operator is required to respond reactively with expensive, inefficient ancillary services, when a proactive holistic planning approach to renewables integration would be more effective and efficient.

The role of the industry Regulator should be changed, or a new body created, to address the optimum long term energy needs in terms of plant mix, including diversity, controllability, sustainability and technical compliance.

There needs to be increased political awareness of the high impact of a Black Start and the inadequate measures currently available to restore the network to all parts of Great Britain in acceptable timescales, even though this is a low probability event. If the innovative distributed generation approach cited above is to provide a significant benefit there will need to be massive investment in control communications infrastructure, to enable the connected demand to be managed during a Black Start procedure.

The adequacy of the Security and Quality of Supply Standards (Operation and Planning) should be reviewed in the light of the increased likelihood of extreme weather events and their impact on the network.

  1. Generation capacity surplus: all the generation available to run but whose operating costs are such that they are never called to operate in the energy market. Traditionally this would be over 35% more than system demand but in recent years most of this surplus has gone.
  2. Operating margins: the difference between available generation and the system demand. Traditionally there would be 15% more generation despatched (running with spare capacity) to cover for plant breakdown or shortfalls and demand forecasting errors
  3. HVDC interconnector: A High Voltage Direct Current connection that used AC to DC converter stations at each end of the line. Enables very long high-capacity cables to be used, not possible with AC.
  4. System inertia: Energy stored in rotating machines connected to the grid system, that helps to keep the system running within operational frequency limits, also known as the flywheel effect
  5. Governor: a control system regulating the output of a generator in response to grid frequency.For the UK the mains frequency is required to be maintained between 49.5Hz and 50.5Hz (50 cycles per second ±1%)6. Infrequent generator loss limit: The system is operated to withstand the loss of this amount of generation without infringing statutory frequency limits. The limit is currently 1800MW.
  6.  Infrequent generator loss limit: The system is operated to withstand the loss of this amount of generation without infringing statutory frequency limits. The limit is currently 1800MW.
  7. Infrequent generator loss limit: The system is operated to withstand the loss of this amount of generation without infringing statutory frequency limits. The limit is currently 1800MW.
  8. Embedded generation: independent sources of supply feeding capacity into the distribution system
  9. Synchronous system: System wide generators that run at the same frequency (50 cycles per second) tied together in synchronism. When a synchronous generator loses synchronism, it is automatically disconnected to preserve the security of the network.
  10. Synchronous compensator: Similar to a generator but with no turbine drive to produce active power. It provides a contribution to system inertia in transient fault timescales and provides system voltage support.
  11.  Islands: sub-sections of the National Grid which contain generators and consumers and can operate in isolation from the rest of the grid on a temporary emergency basis

Ref 1

Ref 2

The opinions expressed are those of the author and do not necessarily reflect the views of IES.

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