NIC0001

Written evidence submitted by Colin H Bayfield MSc, CEng, FIET

 

Introductory Personal Statement

 

I retired from the Electricity Supply Industry in 2014 as Network Development Manager for ScottisPower Energy Networks (SPEN), following a 37year career in system operation, network planning and latterly renewable integration innovation projects (Ofgem NIC and NIA funding).

 

The scope of my career involved Transmission and Distribution system operation, planning, asset management and regulatory price review submissions. I represented SPEN on a number of national committees, e.g. British Grid System Committee, DECC Energy Networks Strategy Group, Grid Code Review Panel etc. I have been engaged in a number of significant industry review projects, e.g. Review of Security & Quality of Supply Standards (GBSQSS), BETTA STC drafting working group, Impact of Climate Change on Networks project (Met Office & network operators) and a Review of Security of Supply to Central Business Districts etc.

 

Since retirement I have maintained an interest and watching brief on the industry, facilitated by the industry obligation to engage with stakeholders and provide open and transparent access to Planning Statements, Operating Codes and innovation projects etc. This has been a valuable source of high quality information for which I compliment the industry.

 

The reason for responding to the consultation is to express my concern over some trends and developments in the industry affecting the reliability and resilience of the electricity networks, with high levels of renewable generation. I must add that I am in full support of the transition to renewables, having spent much of my career facilitating their integration and development. My position as a retired professional, gives me the freedom to make independent, informed comments and judgements at this time of rapid change and engineering challenge in the industry.

 

Although my evidence is aimed at non-technical stakeholders and politicians, the nature of the subject does require an airing of important technical issues, for which I have provided a glossary of some technical terms where appropriate. If my evidence requires any further explanation, I would be very pleased to provide it.

 

Reliability and resilience of the GB electricity system with high levels of renewables

 

Summary

The electricity supply system in Britain, which has provided reliable energy supplies for decades, is undergoing a radical transformation in the delivery of a net zero carbon supply system. 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. This transformation is changing the supply system characteristics from having high levels of controllability, stability and system strength, with low technical risk, to a system with a large proportion of highly intermittent generation, reduced stability and system strength, with enhanced levels of technical risk.

Renewable electricity from wind and solar generators play a major part in the delivery of net zero economy, 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 security and quality of supply standards are 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 although this has been compensated for, to some extent, by the introduction and reliance of European interconnectors which currently supply about 10% of the GB electrical power. There will always be periods when there is little or no renewable generation available and substantial back-up energy supplies are required.

The current ability for the GB transmission system to recover from a major grid failure (Black Start), or partial grid failure, is of serious concern. Although this event is a low, but increasing probability, it has a very high economic and societal impact due to the prolonged restoration times that may be expected.

There is an urgent need for long term coordinated energy planning, with less reliance on short term market solutions, in order to provide sustainable energy security for the future, at an economic and affordable price.

Reasons for the interruption of electricity supply

 

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

Major supply interruptions are thankfully rare in GB. When they do 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 as fast as practically possible.

Issues Contributing to Major Network Failure

 

Background

 

The Grid System Operator (SO) and Transmission Owners (TO’s) 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. There are no equivalent standards for the future planning or procurement of generation capacity; this is left to the electricity market.

The change in characteristics of the electricity supply system with large scale integration of renewable generation, has required continuous changes to the Transmission and Distribution Codes that govern the operation and planning of the networks, to ensure that new plant technologies do not adversely affect the security and quality of supply.

 

Security of generation supply

The success of renewable generation currently results in approximately 25% of UK annual energy produced from wind, with an installed capacity of approaching 20GW. These figures are predicted to rise significantly over the next decade with an offshore target of between 31 GW and 47GW of wind by the year 2030. (see NGC Future Scenarios document) https://www.nationalgrideso.com/document/174541/download.

The highest demands for electricity sometimes occur when there are very small quantities of renewable generation available. This may happen when a large high-pressure cold weather system sits over Europe, sometimes for a number of days, resulting in very little domestic wind generation and reduced European Interconnector import availability. Hence, at times of reduced renewable output, generation security requires gas-fired generation to be available and places a high reliance on gas imports from eastern Europe, Russia and Norway, with high price volatility due to increased demand.

The closure of coal-fired power stations has resulted in severely depleted plant margins, [see Glossary 2] and the closure of the nuclear fleet in coming years will significantly exacerbate this issue. An unintended consequence of the introduction of renewable generation is the erosion of the economic case (due to the loss of volume generation opportunity), for developers to build new conventional power stations that could back-up supplies when renewables are not available. Regulatory intervention to provide a ‘Capacity Market, i.e.to pay generators to be ‘available’ without necessarily generating, has had limited impact in stimulating new generation projects.

To address the shortage of generation capacity, Ofgem have also promoted a number of mitigation initiatives including Demand Side Management (contractual demand reductions), increased HVDC Interconnectors [Glossary 3] to Europe and Energy Storage initiatives (batteries).

The NGC Future Energy Scenarios document referenced above, predicts that the peak demand for electricity will increase from about 58GW today to around 69GW in 2030, rising to between 92GW and 113GW by 2050, under their four future energy scenarios. Electricity demand increase to supply electric vehicle charging and electric heating (including the replacement of gas central heating boilers with heat pumps), is a key deliverable for the government’s decarbonising policy. It is however highly questionable where this additional generation capacity may be realised without a radical change to the way future generation needs are planned, procured and delivered. It is appropriate to point out that the 20GW of gas fossil generation that plays a vital role in providing generation security today, is targeted be removed by 2050.

 

Future generation requirements need careful planning to ensure there is a coordinated, sustainable, efficient and secure plant mix including renewables, large and small nuclear and large-scale energy storage etc.

 

System inertia and synchronous generation

The system inertia, or flywheel effect, is the energy stored in rotating machines connected to the grid system, which helps to keep the system running during short periods of imbalance between generation and demand, and this also helps the system ride through transient network faults, improving transient stability.

With the reduction in the number of heavy fossil fuel generators, the inertia of the grid system has significantly reduced. 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 generators with governor response [see Glossary 4] need to respond more quickly to regulate frequency within operational limits. This is not a problem for gas turbine generators, or HVDC interconnectors providing frequency 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 in service today 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 more 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 5] 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 6] which tripped because of the low frequency deviation, highlighting the vulnerability of embedded generation. This provides 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 7]. With significantly reduced system inertia, the rate of change of frequency (or acceleration) during a fault will be higher, and stability limits (assessed by computer simulation) may impose significant power flow constraints on the operation. This issue has required the SO to create an additional ancillary services market for System Inertia. ScottishPower is seeking to install Synchronous Compensators [see Glossary 8] on their transmission system, to provide inertia in order to maintain the Anglo-Scottish power transfer capability. Other third parties are seeking to invest in the market to provide Inertia from energy storage devices, e.g. batteries and flywheels.

Network faults

In simplified terms, credible faults, e.g. caused by lightning strikes to overhead lines, are assumed, for security purposes, to affect both circuits on a tower line, or two separate circuits on two tower lines. 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. The fundamental principles of the system operation and planning standards (described above and known as N-D or N-2) have remained substantially unchanged since their inception over 50 years ago.

Under post fault outage conditions, the SO is required to re-secure the network by re-scheduling generation, e.g. 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.

System Strength

Conventional synchronous generators contribute to the ‘strength’ of the network and when a fault occurs, a large amount of fault current flows into the network, which enables the power system protection systems to operate securely and the system to return back to normal stable operation. Renewable generation produces only a small amount of fault current and as such the system is much weaker in areas where there are no synchronous generators. To attempt to compensate for the loss of system strength, the SO has introduced another market for the provision of ‘Fault Level’.

The need for Inertia and Faut Level services poses a legitimate question as to who should pay for restoring system security caused by the closure of coal and nuclear stations. Should this fall on the operators of the remaining synchronous machines, should it be the operators of the new, low-inertia generation, or should it be their customers?

System design uncertainty

Windfarm generators and a significant proportion of the equipment installed on the transmission and distribution systems, have complex power electronic control systems. The modelling required to securely integrate these diverse control systems is technically challenging and time-taking and may not always accurately represent the behaviour of the plant in the real world. It is not unusual for unexpected adverse control system interactions (resonance) between equipment on the network to take place, particularly under weak or extreme operating conditions.

On 24/08/2021, there was a serious incident in the north of Scotland which is currently under investigation by the SO, the TO’s and academia. During this incident there was severe voltage and power oscillation, thought to be associated with the newly commissioned Caithness – Moray HVDC link and the absence of any conventional synchronous generation in the north of Scotland. A number of windfarms tripped as a result of the disturbance. The oscillation was seen 300km away at Torness power station which was adversely affected. If Torness power station had tripped, the transmission system in Scotland might have suffered severe consequences. A significant near miss. The incident was described in the following webinar: https://globalpst.org/wp-content/uploads/Research-Agenda-for-Transformed-Power-Systems-Mark-OMalley-and-Julian-Leslie.pdf

There is an implication in the webinar material that the SO was unaware of the incident, until brought to their attention after the event by the Scottish TO’s. The SO does have instrumentation developed expressly for detecting abnormal system oscillations across GB, i.e. in NIC project VISOR https://www.spenergynetworks.co.uk/pages/visor.aspx#tablist1-tab2 (Proposed by the writer of this evidence). It appears this instrumentation may not have been in service at the time of the event.

Incidents like this are likely to occur on other parts of the GB network as the number of HVDC links for offshore generation are connected to the transmission system, with the attendant risk of control system design uncertainty. It is imperative that the entire GB grid system is monitored for unexpected oscillation at all times. There is a need for adaptive Power Oscillation Damping controls to be made available on all appropriate HVDC equipment.

Resilience

A measure of the resilience of a system is its ability and time to return to normal after a breakdown (which may be local, regional or national in its field of disruption).

The probability of a complete or partial failure of the British Grid System is currently small, but for the reasons given above, it is increasing. The societal, financial, and political consequences of a major blackout are substantial, requiring the SO to have a licence obligation to put in place a viable Black Start plan. The procedure requires all generators participating in the Black Start market to start independently and supply island loads [see Glossary 9], before the SO reconnects the islands to restore the complete system. The process of balancing and synchronising the islands may take considerable time. The SO licence obligation which comes into effect in 2026, requires 60% of the total GB demand to be restored within 24 hours and 100% within 5 days.

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 or more.

Recognising this unacceptable recovery time, a funded innovation project, ‘Distributed ReStart`, https://www.nationalgrideso.com/future-energy/projects/distributed-restart, is being delivered with partners ScottishPower Energy Networks,  National Grid SO and consultants TNEI. The project is investigating a bottom-up approach to Black Start recovery and seeks to use the large volume of distributed generation now connected to the grid, to play a role in accelerating supply recovery. There are formidable technical, organisational and procurement challenges to overcome, but it is recognised that a significant improvement in Black Start capability may be achieved by the modification of windfarm control systems and the deployment of large-scale battery installations. It is suggested that the solution will be a hybrid of integrated Black Start services across the full range of transmission and distribution network voltages. Successful implementation will require significant Ofgem funding for the transmission and distribution network operators to work closely together, to deliver technically complex solutions.

It should be remembered that almost all of the distributed connected generation is renewable energy sourced and might not be available without wind or sunlight at the time of need.

The East Coast HVDC interconnector projects cited in the SO ETYS, being jointly developed by NGC and Scottish TO’s, should be equipped with a Black Start capability, unlike the Western Interconnector which requires a significant fault level for stable operation.

Conclusions & Recommendations

In the transition to a net zero carbon emissions supply, the radical changes in the electricity network, unfortunately lead to 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 on millions of people, although this event was minor when compared to other well documented, widespread blackouts, which have been experienced in many countries in the developed world.

There needs to be increased political awareness of the high impact of a major blackout 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. There needs to be a civil contingency plan to support emergency services and manage societal breakdown when basic essential services, e.g. water, sewage, food, fuel, communications and much transport are lost for a prolonged period of time. Each utility and public service needs to aware of and prepare for this event.

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. This requirement needs to reflect conditions where there is minimal availability of European-wide renewable resources, that is, reduced European interconnection availability, to ensure independent security of supply in the UK. The ageing fleet of nuclear power stations are reaching the end of their economic life and there is a real danger they will close before they are replaced, leaving the country with a serious shortage of generation capacity, when renewables are not available.

It is imperative that the grid system issues caused by reducing inertia and system strength e.g. uncontrolled oscillation events, are sustainably managed and resolved. The current industry regulatory framework promotes uncoordinated renewable generation applications, without adequate consideration of the operability, system security and consequential operating costs. The System Operator is required to respond reactively, with expensive inefficient ancillary services, when a proactive holistic planning approach to renewables integration could be more effective, efficient and sustainable in the long term.

In order to address the optimum long-term energy needs, an independent energy planning authority should be created, or the role of the SO expanded to cover these needs. The future energy needs should include an assessment of renewable and non-renewable generation capacity and energy storage requirements. Furthermore, the optimum plant mix should be identified, including diversity, controllability, preferred location and ability to support Black Start recovery etc.

The body could use a range of government backed incentives and volume guarantees to attract investment from potential developers for discreet sections of the market to achieve the optimum balance and diversity of energy sources.

The adequacy of the long-standing Security and Quality of Supply Standards (Operation and Planning), should be reviewed in the light of the increased likelihood of more extreme weather events and the increased societal reliance on electricity supply.

If the innovative distributed generation approach to Black Start recovery cited above, is to provide a significant benefit, there will need to be significant investment cross-industry engineering resources and communications infrastructure.

Glossary

  1. Generation capacity surplus: all the generation available to run, but the operating costs are such that they are never called on 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 plant margins: the difference between available generation and the system demand. Traditionally there would be 15% more generation dispatched to cover for plant breakdown or shortfalls and demand forecasting errors etc. Plant margins are now in the order of 5% and require sustained imports from European interconnectors and demand reduction contracts.
  3. HVDC interconnector: A High Voltage Direct Current connection that uses AC to DC converter stations at each end of the line. Enables very long hig-capacity under-sea cables to be used, not possible with AC.
  4. Governor: a control system regulating the output of a generator in response to grid frequency. For the UK the mains frequency is legally required to be maintained between 49.5Hz and 50.5Hz (50 cycles per second ±1%), but normal operation limits are 50Hz +/- 0.2Hz
  5. 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. Embedded generation: generation, usually less than 100MW, connected to the distribution system at 132, 33 and 11kV
  7. 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 and protect the generator from damage.
  8. 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 control.
  9. Islands: sub-sections of the National Grid which contain generators and consumers and 22/can operate in isolation from the rest of the grid on a temporary emergency basis

22 December 2021