Power System Stability – Keeping the Grid Stable in the Modern Age
Under ideal conditions, electricity grids are operated close to a state of equilibrium; power flows smoothly, oscillating at a steady frequency and is held near to its nominal voltage. But in reality, sudden disturbances can – and do – occur, such as equipment faults, generator failures, or swings in demand and generation that can quickly push the system out of balance. Power system stability is all about the grid’s ability to absorb these shocks and return to a stable operating state. In essence, it is a measure of how tightly the grid can hold on to its key performance indicators, i.e. the voltages, frequencies and phase angles in the system, when disturbances happen.
A System in Transition
For decades, the foundation of the power system was set by large, spinning machines: steam turbines driven by fossil-fuelled synchronous generators. We have designed the fundamental operating principles of the grid, and the way we study it, around the well-known and predictable physical behaviour of these machines. This familiar rhythm is changing. Modern power systems are rapidly adopting inverter-based resources (IBRs) such as wind turbines, solar PV, battery storage (BESS), HVDC links, and FACTS devices. These technologies don’t spin – they switch – interfacing with the grid through power electronic converters. Unlike the heavy, mechanically governed generators of the past, their response to system events is faster, programmable, and fundamentally different.
It is now common to see wind and solar-based IBRs displacing fossil-fuelled thermal generators in energy markets due to their low short-run marginal cost and a priority to utilise low-carbon energy sources. HVDC interconnection between different synchronous systems is also increasing. Energy markets connected through HVDC are non-synchronously coupled and can offset the use of thermal generation in the energy market on the import side. As such, deploying IBRs can reduce inertia and fault levels by pushing the synchronous machines ‘out-of-merit’ or displacing them entirely from the energy mix.
Figure 1: Declining Carbon Intensity of the GB Power System (2009–Present). Since 2009, the average carbon emissions from electricity generation in Great Britain have fallen dramatically – reflecting the shift away from coal and the rise of renewables. This marks significant progress toward a cleaner grid, but much work remains to achieve a net-zero-carbon energy system and support economy-wide decarbonisation.[Source: National Energy System Operator (NESO) – carbon intensity dashboard]
This shift brings both opportunities and challenges. Inverter-based resources can respond almost instantaneously and be precisely controlled through software, offering a level of speed and flexibility that wasn’t possible with traditional generators. However, common IBR designs lack the natural inertia and high short term overload capability (often referred to as fault level) that traditional machines contribute during disturbances. As these characteristics change, the system’s core indicators – the frequency and voltage – can become more sensitive to change.
What are Inertia and Fault Level?
Inertia is the natural tendency of objects in motion to stay in motion. Traditionally, it refers to the energy stored in the spinning mass of synchronous machines like turbines and generators. When system frequency starts to change – due to a sudden imbalance between generation and demand – this stored energy is automatically exchanged with the grid, helping to slow the rate of change and stabilise the system.
Fault Level is ameasure of the ability of connected sources to inject fault-current into a short-circuit fault at a specific point in the network. High fault levels are important for effective operation of protection systems and to limit the voltage depression during disturbances. Fault current characteristics vary between technologies, and their contribution to overall system stability is complex but essential.
The new challenges that must be overcome can, in some cases, only become apparent at high levels of IBR penetration. Grid operators must adopt new approaches to frequency control, voltage regulation, and managing emerging modes of instability unique to these new technologies.
Planning for Power System Stability
Great Britain has one of the most reliable power systems in the world. The specifications that define the minimum requirements for reliability and operational security are defined in the Security and Quality of Supply Standards (SQSS), the Grid Code, and the Frequency Risk and Control Report (FRCR). These standards define how the grid must perform under stress, particularly when hit by credible contingencies, known as “secured events”. These are not the absolute worst-case scenarios, but realistic ones: faults that are deemed serious enough to matter, and likely enough to plan for. For example, the SQSS requires that no system instability should result from a fault affecting a double-circuit overhead line.
Understanding how the grid will respond to different types of disturbances, across a wide range of operating conditions, is essential for maintaining stable operation of the system. Achieving this depends on two things:
- Knowing the dynamic characteristics of the power system and its component parts.
- The ability of engineers and modelling tools to accurately replicate its behaviour.
Power System Stability covers a broad range of complex mechanisms, including the traditional frequency, voltage and angular stability that are related to both synchronous machines and inverter-based resources. But in addition, new forms of converter-driven stability mechanisms are emerging that require additional and new study techniques.
System stability has always been a complex topic, but capturing the full range of dynamic responses in IBR dominated systems demands more advanced models, more granular data, and new simulation techniques that can keep pace with evolving technologies. Crucially, we also need to anticipate future system needs to ensure that, as we move toward operating a zero-carbon grid, reliability is not just maintained – but strengthened.
Figure 2: example of a power system study assessing a transient stability problem – these types of issues are affected by the characteristics of generators, loads and their controls, but also the inertia and fault levels in the grid. (source: PSCAD, ‘Introduction to Electromagnetic Transient Simulations and Applications’)
Evolution of Power System Stability Markets
As natural inertia and high fault level provision are inherent characteristics of synchronous machines, they come as by-products of running thermal generation in the energy market. Today, with more IBRs in the mix, it is increasingly important to procure these system dynamic properties separately from energy production to maintain system security.
To keep inertia above a defined minimum level, which is set based on the expected frequency deviation following the loss of the largest infeed to the system, NESO often has to instruct thermal generators to turn on through the Balancing Mechanism even when they are otherwise out-of-merit. This can be costly: synchronous generators must respect their minimum operating level and require payment above market rates to come online, while low-carbon generators must also be paid to turn-down and make space for the inertia-providing units. These type of balancing actions will only increase if no alternatives are implemented.
To address some of these technical challenges and manage the re-dispatch costs associated with stability services, NESO introduced the Stability Pathfinder programmes. These initiatives were designed to procure inertia and fault level directly from assets connected to the GB transmission network. Phases 1, 2, and 3 have now concluded, focusing on different needs across the system. Phase 1 targeted system-wide inertia, Phase 2 procured fault level in Scotland and Phase 3 procured both inertia and fault level in England and Wales. The volumes tendered for in each phase are shown in Figure 3.
Figure 3: Procured quantities of inertia (in Gigawatt seconds) and fault level (in Gigavolt-ampere) from each phase of the stability pathfinder program. The figures are the amounts intended to be procured by the tender exercise (i.e. NESO’s view of the system’s need).
The contracts awarded through the Stability Pathfinder programmes have led to investment in new-build assets that are paid to be available and synchronised to the grid. These assets are not remunerated through energy markets but are instead contracted specifically for their stability contributions. As the name suggests, the Pathfinder tender exercises were exploratory in nature. They were designed to find viable approaches to procuring inertia and fault level in a changing system.
The next step by NESO is the introduction of dedicated stability markets, moving from one-off tenders to structured, repeatable processes. These markets are proposed to operate over three time horizons, each targeting different operational needs:
- Long-term markets (four-year timeframes) aim to support investment in new capacity, similar to the Pathfinder model.
- Mid-term markets (annual timeframes) are intended to secure availability from already built assets to meet foreseeable stability requirements.
- Short-term markets (operating intra-day) will address near-term stability needs, functioning more like today’s energy balancing services, with assets procured based on marginal cost.
Frequency Response Markets for a Low Inertia Grid
It is also worth noting that another key lever available to system operators for managing frequency stability is the suite of frequency response and reserve services. When there is a sudden imbalance between generation and demand – such as the unexpected loss of a generator – the resulting change in system frequency is proportional to the size of the imbalance and inversely proportional to the amount of system inertia. In other words, the larger the disturbance, the greater the frequency deviation, and the lower the inertia, the faster that deviation occurs.
To maintain frequency near its nominal value of 50 Hz, system operators rely on power reserves delivered over various timescales. These frequency response services work hand in hand with inertia. The more inertia present in the system, the more time there is for response services to act.
Take the example of a generator trip. Primary Frequency Response (PFR), typically delivered by governor controls on flexible gas or coal-fired units, begins within approximately two seconds and reaches full delivery by around ten seconds. In the critical moments immediately after the fault, the inertial energy from synchronous machines helps arrest the frequency decline and buys time for PFR to take effect. Faster-responding assets can help catch the frequency drop sooner, especially in low-inertia conditions. This is where Battery Energy Storage Systems (BESS) come into play. Batteries can begin responding within ½ second and reach full power delivery in under 1 second.
Reforms to the frequency response framework have already been implemented. NESO has introduced a new structure, dividing services into pre-fault and post-fault categories. Dynamic Moderation (DM) and Dynamic Regulation (DR) are pre-fault services that act continuously to maintain frequency within a narrow operating band of ±0.2 Hz. These services make ongoing adjustments to reduce the need for larger corrections later. Dynamic Containment (DC) is the main post-fault service, designed to provide a rapid injection of power following a significant loss of generation, managing frequency decline in low-inertia conditions.
These new frequency response markets have quickly matured, and many are now saturated with battery systems. BESS now provide the majority of frequency response capacity in Great Britain, reshaping the system’s dynamic behaviour following contingencies.
Technological Advances: Forming The Grid
So which types of systems are capable of delivering these stability services? Today, the grid still relies on synchronous machines as the main source of these important dynamic properties. The majority of the capacity procured in the Stability Pathfinders was also from synchronous machines – specifically, synchronous compensators. These are essentially de-loaded synchronous generators: machines that spin freely without producing real power, but still provide inertia, fault current, and reactive power. By remaining connected and synchronised to the grid, they offer the same stabilising characteristics as conventional generators, but without generating active power, making them suitable for supporting system stability in a low-carbon energy mix. However, sync-comps are not a silver bullet and can also be relatively high cost.
Most IBRs to date are based on a control philosophy know as ‘grid-following’. This means that they rely on measuring the grid’s voltage and frequency as a reference and then feed in current that is in-phase with the grid voltage. This can become problematic during major system disturbances as the grid voltage and frequency can quickly change, becoming hard to track. Despite this limitation, grid-following converters – especially those paired with energy storage like lithium-ion batteries – can still provide fast power injections. They are well suited to participate in frequency response services such as Dynamic Containment. However, by design, they do not contribute inertia or fault current in a way that supports the grid’s underlying stability needs.
Figure 4: example of frequency response after a disturbance for the current day system compared to an IBR dominated future with either grid-following or grid-forming control. Source: Frequency Response in High IBR Scenario Illustration Studies, WECC Modelling and Validation Subcommittee September 2022, D. Kosterev, M. Ayala Zelaya, E. Mitchell-Colgan, BPA Transmission Planning
A newer type of IBR is starting to be deployed that has a ‘grid forming’ control strategy. These converters are controlled to behave as voltage sources, actively setting and regulating local voltage and frequency. In doing so, they emulate the behaviour of synchronous machines and can contribute to system stability during both normal operation and disturbances. Grid-forming IBRs are, therefore, able to provide the kinds of inertia and fault level that are compatible with the requirements of the stability ancillary services – opening up new possibilities for stability support in a zero-carbon grid.
At Blake Clough Consulting, we are regularly engaged on projects that are participating in stability markets as well as innovation projects assessing the future of power system stability in the GB grid. Get in touch to discuss your system stability projects!