Impact of IBRs on Grid Frequency and Voltage

It has been truly busy time, diving deep into the causes and dynamics of the Iberian blackout last week. After all, I wanted to take a step back and compile the most frequent technical questions I’ve received, along with my personal answers based on experience and system technology perspective. I think this recent grid event raised some important lessons for power system stability in high-renewable grids. Here’s a simplified closer look, question by question: Q1: Did renewables cause the blackout? Cannot say directly. But with ~60% solar and ~10% wind generation at the time, the grid had low inertia due to inverter-based sources. This lack of synchronous inertia left the system vulnerable actually. That means as a disturbance occurred, the frequency deviation was sharper and faster, overwhelming protection systems before corrective action could stabilize the grid. Q2: Why is inertia so critical? Inertia from synchronous generators acts instantly with the frequency deviation, slowing down frequency changes by releasing kinetic energy. Without inertia, frequency falls faster and deeper, reducing reaction time for controls and risking cascading trips. Q3: Would more thermal or hydro have prevented it? Very likely yess, because synchronous thermal and hydro plants don’t just supply inertia; they provide short-circuit strength crucial for fault clearing and relay operation. Their presence also improves voltage stability and mitigates frequency oscillations. Without these stabilizers, a high-inverter grid faces higher risk during disturbances. Q4: Can batteries (BESS) or fast frequency response (FFR) replace inertia? Unfortunately not fully (or very very less than imagined / expected). Because BESS and FFR react after(!) a frequency deviation occurs; inertia works with(!) the deviation, inherently delaying the drop. While grid-forming inverters and synthetic inertia are promising technologies, they cannot (yet) replicate the instantaneous stabilizing effect of physical rotating mass at system scale. Q5: What’s the way forward for high-renewable grids? I think a robust future grid actually should have a balance. In that scenario, renewables deliver clean energy; synchronous thermal, hydro, and pumped storage provide inertia and grid strength; grid-forming inverters enhance stability but cannot entirely replace synchronous inertia. After all as a short summary, I can clearly state that decarbonization doesn’t mean eliminating inertia; it means integrating renewables with inertia-providing resources to ensure frequency stability, fault tolerance and protection system performance. The Iberian event echoes lessons from Europe’s Jan 8, 2021 grid split. Let’s never forget, inertia remains the backbone of a stable 50 Hz synchronous grid☘️

⚡ The official report on the Iberian blackout confirms it was mainly a voltage instability event. The system had already experienced "intense voltage fluctuations" in the days before the incident. Wide-area oscillations prompted the system operator to increase grid meshing and reduce exports to France. These measures, unfortunately, decreased line flows, which paradoxically raised voltages due to the line charging effect, causing power plants to trip on over-voltage. This triggered a cascading failure, worsened by some plants tripping improperly before voltage limits were reached. The main conclusion from the report is a "lack of voltage control resources"; either they were poorly scheduled, or those allocated failed to provide sufficient power, despite an overall adequate generating capacity.   🔦 For the voltage control to be effective, it is important to consider the difference between high R/X and low R/X ratio systems. In high-voltage grids (transmission networks), which typically have a low R/X ratio, voltage magnitude is primarily sensitive to reactive power. Here, the voltage drop can be approximated by ignoring resistance and focusing on the reactive component. This is why traditional grid operators use reactive power to regulate voltage in these systems. Conversely, in low voltage (LV) systems and distribution networks, the high R/X ratio means voltage magnitude is more sensitive to active power injection. In these systems, the effect of resistance is significant, and the voltage drop approximation includes both active and reactive components. For instance, a PV plant can regulate voltage by reducing active power injection or providing negative reactive power, as per standards like IEEE 1547-2018. If reactive power alone is insufficient, active power control, which involves elements such as heat pumps, electric vehicles (EVs), or battery storage, may be necessary.   🪫 A notable point from the Iberian blackout report is the recommendation to "allow asynchronous installations to apply power electronics solutions to manage voltage fluctuations." This indicates that the voltage control capabilities of inverter-based resources (IBRs) were not fully utilised. Although IBRs offer considerable potential, challenges persist, particularly for real-time smart inverter Volt/Var Control (VVC). These include susceptibility to control instability caused by incorrect parameter selection, as smart inverter settings are sensitive to feeder configuration and operating conditions. An inappropriate droop (slope) setting can lead to control instability or voltage oscillations. There is an inherent trade-off between maintaining control stability and achieving accurate set-point tracking, which can cause voltage violations. Additionally, the non-adaptability of droop VVC to changing conditions can hinder deployment. #blackout #renewables #gridmodernization #powerelectronics #gridforming #voltage #cleanenergy

Kauai nearly learned the hard way what “IBR grid physics” really means. In 2021, an island grid with rising inverter penetration saw a system oscillation after a large unit tripped; the unit was supplying ~60.6% of system load (a severe N−1). System frequency didn’t just dip, it rang for ~60 seconds, with a reported 18–20 Hz with a reported 18–20 Hz oscillatory mode superimposed (well above classical electromechanical swing frequencies). The response wasn’t “add more spinning mass.” It was control engineering, in three steps: • identify the inverter interactions behind the oscillation • validate with high-fidelity EMT + hardware-grade testing • then shift the control behaviour, with grid-forming operation later observed to mitigate the oscillations. The bigger point is this: Stability is becoming a measurable, engineerable grid commodity, not something we historically inherited by default from synchronous machines being online. And once you accept that, a lot changes: • connection requirements: “model + settings + performance envelope”, not just MW/Mvar • model validation expectations: EMT credibility becomes a gate, not a nice-to-have • what operators need visibility over: control modes, limits, and fast transitions become operational signals • how we specify (and procure) grid services: “energy” and “capacity” aren’t enough, we start buying damping, fast frequency response, and voltage support as products The question isn’t whether inverters can provide “strength”. It’s whether our planning, compliance, and operational frameworks are ready to treat stability like a first-class product. 👉 Will we end up requiring grid-forming capability for every new large inverter-based solar or battery plant, or only where the grid is already weak? Figure is an illustrative reconstruction (not measured data). Source for the underlying event is in the first comment. #PowerSystems #GridStability #InverterBasedResources #GridForming #EMT #SystemStrength #FrequencyStability #GridCodes

🚧 Inverter-Based Resources (IBRs) Need Special Attention in Power System Studies ⚡ As the grid becomes greener 🌱 with more solar PV, wind, and BESS, one critical shift is happening silently — the rise of Inverter-Based Resources (IBRs). But here's the twist: 🌀 IBRs don't behave like traditional generators — especially during system disturbances! 🔍 So, what's different about IBRs? ✅ They have no rotating mass — hence, no natural inertia. ✅ Their response is software-defined — governed by fast digital control loops. ✅ During faults or transients, they may limit current quickly or trip altogether. ✅ Their contribution to voltage & frequency support is not physical but programmed. That means… we can't assume they'll behave like synchronous machines in disturbance studies! 🧪 RMS Simulations: A Tool to Analyze IBR Behavior To evaluate IBR integration in large grids, we use RMS (Root Mean Square) simulations — which solve the dynamic phasor equations over time. These simulations are perfect for studying: 📉 Frequency response 🔄 Reactive power behavior ⚖️ Control mode interactions (P/Q/V) 📈 System-level stability ⚙️ How IBRs Are Controlled: Grid Code Driven Depending on the grid’s requirement, IBRs operate in different modes: 🔹 Power Factor (PF) Control – Maintain a fixed PF (e.g., unity or lagging). 🔹 Reactive Power (Q) Control – Inject/absorb specific MVArs. 🔹 Voltage (V) Control – Act like an AVR to hold voltage steady. These flexible modes make IBRs powerful — but also more complex to study! ⚠️ But What About the PLL? Isn’t It Crucial? Yes — and here's where it gets tricky: 🧭 The Phase-Locked Loop (PLL) tracks grid voltage phase, helping the inverter sync with the grid. But in RMS simulations, PLLs are often not explicitly modeled. Instead, we assume: 🕒 The reference phase is fixed or slowly changing 🧮 The injected current phasors are not sensitive to phase errors ✅ This assumption simplifies modeling. ❌ But it may miss fast transients, PLL instability, or sub-synchronous interactions in weak grids. 👉 For such detailed studies, we turn to EMT simulations (like PSCAD/EMTP). 📌 In Summary: 🔋 IBRs ≠ Synchronous Machines 🧠 Their behavior is controlled, not physical 🔬 RMS simulations help understand their grid-level impact 🎯 Control modes (PF, Q, V) must align with grid codes 🚫 PLL is often simplified — a limitation of RMS studies 💡 As we move toward high IBR penetration, dynamic studies must evolve — combining RMS + EMT, realistic controls, and accurate PLL models to keep the grid secure and resilient ⚡🔒

Europe’s Most Severe #Blackout in 20+ Years:- What Happened — and What Every Energy Market Must Learn (ENTSO-E publication today) **The Iberian blackout wasn’t a failure of #RenewableEnergy — it was a failure to operate a system built for the past in a world of new physics.** On 28 April 2025, #Spain and #Portugal experienced the most significant blackout in the European #powersystem in over two decades. While #France saw only minor disturbances, the Iberian system collapsed within seconds, triggering a full separation from Continental Europe. #RootCauseSummary :- The blackout was driven by a convergence of vulnerabilities, not a single point of failure: #Widespread inverter‑based generation tripping due to voltage protection settings. #Insufficient damping of emerging oscillations in a high-renewables environment. #Low inertia (Spain: 2.17–2.67s, Portugal: 2.45–2.95s) that amplified system sensitivity. #Protection coordination gaps across PV, wind, and conventional assets at transmission and distribution levels. #Rapid overvoltage rise once reactive‑power‑absorbing units tripped, further accelerating generator losses. #LessonsLearned for All #EnergyMarkets :- Whether you operate in #Europe, #NorthAmerica, #APAC or beyond — this event is a blueprint for the risks ahead. 1. Higher Renewables = High Complexity (a new normal) As synchronous machines retire, grid inertia, damping, and voltage control degrade. Traditional planning of the past is no longer sufficient. 2.  Protection Settings Must Be Fit for a High‑IBR Future Overvoltage and underfrequency relays behaved as designed, but not as the system needed. Markets must urgently update: a. Ride‑through requirements b. Tripping logic c. Dynamic protection coordination 3.  HVDC and FACTS Devices Are Now Critical System Assets When controller limits are reached — as happened with the HVDC POD‑Q saturation — the system loses a major stabilizing tool. Their roles must evolve from “enhancing” to “essential for stability.” 4. System Observability Needs to Extend Deep into the Distribution Grid Significant generation loss came from <1 MW embedded resources that TSOs could not see in real time. Visibility gaps are now a systemic risk. 5. Operational Planning Must Include Real‑Time Dynamic Assessment Traditional N‑1 security was met on the day — yet the system still collapsed. We now need:- a. Real‑time oscillation monitoring b. Inertia and short‑circuit strength forecasting c. Dynamic stability‑informed dispatch 6. Cross‑Border Coordination Saves Minutes — and Megawatts The strong collaboration between TSOs and RCCs helped the rapid restoration. Future markets require shared situational awareness as a standard, not an exception.