Challenges in Grid-Forming IBR System Integration

☀ Distance Protection Challenges in Presence of Grid-Forming Inverters In the paper "Impacts of Grid‐Forming Inverters on Distance Protection" by D. Johansson et al., published in IET Generation, Transmission & Distribution (2025), the authors investigate how the integration of Grid-Forming Inverters (GFMs) introduces new challenges for traditional protection schemes. One significant issue arises in distance protection, particularly due to the fundamentally different fault behavior of GFMs compared to synchronous machines. 🧠 Key Insight from Recent Research: The study reveals that distance relays, designed with the expectation of strong fault current contributions from synchronous generators, may malfunction or underreach when operating in inverter-dominated grids. 📉 What Happens During a Fault? GFMs are designed to limit their fault current output to protect inverter hardware. As a result: The apparent impedance seen by distance relays increases, often exceeding the protection zone. This leads to delayed or failed relay tripping, particularly in areas with high GFM penetration. 📊 Simulation-Based Evidence (Figures 12–15): To visualize these effects, the authors simulate a single-line-to-ground fault scenario. Here's what the key figures demonstrate: Figure 12 – Apparent Impedance at R1: The relay’s measured impedance stays outside Zone 1, despite the fault location being within it. This is a classic underreaching issue caused by current-limited GFM behavior. Figure 13 – Positive Sequence Voltage at Bus 3: The voltage remains relatively stable due to the GFM's control loop, reducing the voltage dip typically used as a fault indicator in traditional schemes. Figure 14 – Positive Sequence Current at R1: Fault current magnitude is significantly lower, causing the impedance calculation to overestimate distance and miss the fault. Figure 15 – GFM Current Injection: The inverter’s fault current saturates quickly, showing a flat and controlled response, protecting the device but undermining impedance-based logic. ⚙️ Implications for Power System Protection: This analysis suggests a strong need to: Develop adaptive or communication-based protection schemes. Reassess relay zone settings and coordination. Investigate hybrid approaches that incorporate non-impedance-based fault detection. Revising protection strategies becomes critical to ensure system security and reliability as we transition toward inverter-dominated, low-inertia grids. 📖 Reference: Johansson, D. et al. “Impacts of Grid‐Forming Inverters on Distance Protection”, IET Generation, Transmission & Distribution, 2025. #PowerProtection #GridForming #InverterControl #DistanceRelay #PowerSystemSecurity #GFM #ProtectionEngineering #RenewableGrid #FutureGrid #RelayCoordination

I didn’t truly understand protection challenges until I started working with systems that had a high share of inverter-based resources. On paper, protection looks simple: fault happens -> current spikes -> relay trips. In reality, that logic was built for synchronous machines. With rotating generators, faults are loud. Current shoots up 5–8 times rated. Voltage collapses clearly. Phase angles swing in a predictable, physics-driven way. Relays see the fault instantly. Now compare that with IBR-dominated systems. Fault current barely reaches 1.1–1.3 pu. Waveforms are shaped by control algorithms. Current limiting, PLL dynamics, and ride-through logic all kick in. What looks like a fault to the network can look like a “normal operating point” to a conventional relay. That’s where protection blinding becomes very real — not a theoretical risk. This is not about IBRs being “bad”. It’s about the fact that we are using protection philosophies designed for a different era. Modern grids dont fail because protection is wrong. They fail because protection assumptions are outdated. The future of protection is not: ❌ higher current thresholds ❌ more aggressive settings It’s: ✅ waveform intelligence ✅ faster measurements ✅ grid-forming behaviour ✅ protection designed with controls, not against them The grid has changed. Protection has to catch up. #PowerSystems #GridProtection #EnergyTransition #InverterBasedResources #PowerEngineering #GridModernization #ElectricalEngineering #FutureGrid #EnergySystems

I’ve seen BESS projects pass every requirement and still behave dangerously under stress. Nothing failed. No equipment malfunction. No vendor issue. The risk was already baked in, from a simple misunderstanding. VSG and grid-forming were treated as the same thing. They are not. And that confusion is quietly showing up in modern power systems. What usually happens On paper, the BESS is specified as “grid-forming.” Everyone assumes stability, inertia replacement, and disturbance performance are handled. So the project moves forward. Control philosophy? Decided late. Dynamic behavior? Not fully challenged. Protection coordination? Assumed to “work with commissioning.” Then the system is energized. It technically meets the requirements, but under disturbance, it behaves unpredictably. Why this keeps repeating Because two very different concepts are being conflated. Grid-forming is a capability: the ability of a BESS to establish voltage and frequency without a grid reference. VSG is a behavior: how that BESS responds dynamically once it is forming the grid. When this distinction isn’t made early, projects are optimized for compliance, not for system performance. The real consequences • Inertia expectations are not met • Frequency response is weaker than assumed • Protection coordination becomes fragile • Weak-grid and islanded operation expose hidden instability These issues are rarely caused by hardware. They are caused by assumptions made early, and questioned far too late. What actually works This is not a vendor feature problem. It’s a system integration problem. Robust projects require: • Clear differentiation between grid-forming capability and control behavior • Intentional selection of VSG or alternative grid-forming strategies • Alignment between control philosophy, protection design, and grid strength • Validation through appropriate stability and EMT studies when required Most importantly, they require someone to look at the entire system, not just individual components. Why this matters now As power systems lose mechanical inertia and become increasingly inverter-dominated, small control decisions have system-wide consequences. In this environment, “grid-forming” is not a sufficient specification. Behavior matters. Final thought Grid-forming tells you what a BESS can do. VSG tells you how it will behave when the system is stressed. Confusing the two doesn’t just create technical debate. It creates operational risk. Question for those working on BESS projects today: When grid-forming capability is specified, is the control behavior being deliberately engineered at the system level, or assumed to sort itself out later? Hanane Oudli 🌍

𝗪𝗵𝘆 𝗔𝘂𝘀𝘁𝗿𝗮𝗹𝗶𝗮 𝗶𝘀 𝘀𝗵𝗶𝗳𝘁𝗶𝗻𝗴 𝗳𝗿𝗼𝗺 𝘀𝘆𝗻𝗰𝗵𝗿𝗼𝗻𝗼𝘂𝘀 𝗰𝗼𝗻𝗱𝗲𝗻𝘀𝗲𝗿𝘀 𝘁𝗼 𝗴𝗿𝗶𝗱-𝗳𝗼𝗿𝗺𝗶𝗻𝗴 𝗯𝗮𝘁𝘁𝗲𝗿𝗶𝗲𝘀   On 30 September 2025, Transgrid announced a tender for about 1 GW of grid-forming battery (GFM BESS) system-strength services – the first step towards 5 GW.  The design is simple but transformative: 𝗰𝗮𝗽𝗮𝗯𝗶𝗹𝗶𝘁𝘆-𝗯𝗮𝘀𝗲𝗱 𝗽𝗮𝘆𝗺𝗲𝗻𝘁, 𝗲𝗻𝗲𝗿𝗴𝘆-𝗻𝗲𝘂𝘁𝗿𝗮𝗹 𝗼𝗽𝗲𝗿𝗮𝘁𝗶𝗼𝗻. Here’s why and how Australia is changing gears.   𝗪𝗵𝘆 𝘁𝗵𝗲 𝘀𝗵𝗶𝗳𝘁  - 𝗗𝗲𝗺𝗮𝗻𝗱 𝗿𝗲𝗱𝗲𝗳𝗶𝗻𝗲𝗱 – High-renewables grids now lack “system-forming strength + flexibility”, not more spinning steel.  - 𝗠𝘂𝗹𝘁𝗶-𝗿𝗼𝗹𝗲 𝗮𝘀𝘀𝗲𝘁𝘀 – GFM BESS delivers strength while earning from arbitrage, frequency regulation and congestion relief, cutting total cost.  - 𝗟𝗼𝗰𝗮𝗹𝗶𝘀𝗲𝗱 𝗿𝗲𝗶𝗻𝗳𝗼𝗿𝗰𝗲𝗺𝗲𝗻𝘁 – Placed at Renewable Energy Zone (REZ) and bottlenecks to lift connection capacity directly.  - 𝗦𝗼𝗳𝘁𝘄𝗮𝗿𝗲 𝗲𝘃𝗼𝗹𝘂𝘁𝗶𝗼𝗻 – Firmware updates enable droop control, black-start and fault-ride-through to match new standards.   𝗞𝗲𝘆 𝗰𝗵𝗮𝗹𝗹𝗲𝗻𝗴𝗲𝘀  - 𝗙𝗮𝘂𝗹𝘁 𝗹𝗲𝘃𝗲𝗹𝘀 – GFM current limits demand adaptive protection coordination.  - 𝗖𝗼𝗺𝗽𝗹𝗶𝗮𝗻𝗰𝗲 – Model alignment, parameter tuning and hold-point testing across scenarios.  - 𝗠𝗲𝗮𝘀𝘂𝗿𝗲𝗺𝗲𝗻𝘁 & 𝗽𝗮𝘆𝗺𝗲𝗻𝘁 – Defining verifiable “system-strength capability” and enforceable performance terms.  - 𝗢𝗽𝗲𝗿𝗮𝘁𝗶𝗼𝗻𝗮𝗹 𝗰𝗼𝗼𝗿𝗱𝗶𝗻𝗮𝘁𝗶𝗼𝗻 – Weak-grid voltage control and relay integration.  - 𝗦𝘂𝗽𝗽𝗹𝘆 𝗰𝗵𝗮𝗶𝗻 – Long-lead parts, EPC interfaces and controller updates.   𝗥𝗼𝗮𝗱𝗺𝗮𝗽  - 𝗦𝗵𝗼𝗿𝘁 (1–3 yrs) – Hybrid mix: renewables + condensers + GFM BESS. Condensers anchor VAR and faults; GFM builds stability.  - 𝗠𝗶𝗱 (3–7 yrs) – GFM-led fleet with condensers at critical nodes. Mature the “standard – testing – payment” loop.  - 𝗟𝗼𝗻𝗴 (>7 yrs) – GFM + digital protection replace most new condensers, keeping rotating back-up only where needed.   This is not about “opposing condensers” but “buying the right capability”. As the grid’s challenge shifts from “generating power” to “ensuring stability and usability”, assets must evolve from single-function to programmable multi-capability.   ✅ 𝗧𝗮𝗸𝗲𝗮𝘄𝗮𝘆  Australia’s system-strength strategy is entering a phase where GFM BESS complement synchronous machines – with payments finally reflecting true grid value.    🤔 𝗤𝘂𝗲𝘀𝘁𝗶𝗼𝗻  Which barrier is most critical for large-scale GFM BESS rollout – testing, fault-levels, or performance verification?   #TechToValue #GridForming #BESS

As power systems transition toward higher shares of Inverter-Based Resources (IBRs), traditional Root Mean Square (RMS) models are no longer sufficient to fully capture the dynamic interactions between converters and the grid. ✓ RMS models provide averaged, simplified representations that are effective for conventional synchronous machines. ✓ However, IBR control dynamics — such as phase-locked loops (PLL), fast inner control loops, and ride-through strategies — can lead to sub-synchronous oscillations, control interactions, or stability issues that RMS models simply cannot detect. This is where Electro-Magnetic Transient (EMT) models become indispensable EMT simulations operate at microsecond-level time steps (10–20 µs) and include detailed switching and control behaviours. They allow engineers to: ▪️Analyze sub-synchronous oscillations and converter-grid interactions. ▪️Validate protection schemes under unbalanced faults. ▪️Accurately assess plant performance during disturbances. ▪️Ensure interoperability between multiple IBR technologies (e.g., hybrid BESS + PV). In essence: ▪️RMS = quick overview. ▪️EMT = high-resolution “slow-motion” insight into system dynamics.

A critical challenge in modern grid stability is that inverter-based resources (IBRs) are often “black boxes” to utilities and system operators. Inverter manufacturers and plant developers understandably hesitate to disclose proprietary control strategies, leaving operators with limited visibility into internal dynamics. The problem is further compounded by the fact that IBRs can switch among multiple control modes, which are typically unknown to operators yet can exhibit dramatically different dynamic behaviors. In the final days of 2025, we were excited to learn that our paper on black-box IBR modeling was accepted by IEEE Transactions on Smart Grid. In this work, we develop a comprehensive data-driven framework that uses only terminal measurements to discover unknown control modes and learn continuous-time models that accurately capture IBR dynamics under each mode. By leveraging physics-inspired deep learning, the proposed approach addresses four major challenges in a unified way: 🚀 High-Order Nonlinear Representation Using only terminal measurements, the framework provides a general learning approach for characterizing arbitrary high-order nonlinear dynamics of IBRs. It is not tied to any specific control paradigm and can cover anything from power/voltage/current control loops to virtual synchronous machines (VSMs) and phase-locked loops (PLLs). 🚀 Continuous-Time Modeling Unlike most data-driven methods built on discrete-time models (e.g., RNNs, LSTMs, Transformers), our approach learns continuous-time state-space models (differential-algebraic equations). This enables seamless integration of the learned IBR models into standard power-system time-domain simulations with arbitrary numerical integration schemes and step sizes. 🚀 Discovery of Unknown Control Modes A physics-inspired deep unsupervised learning mechanism automatically identifies distinct control modes from historical disturbance data and learns separate state-space models that represent the dynamics associated with each mode. 🚀 Robustness to Noise and Uncertainty Inspired by Kalman filtering, the learning architecture explicitly accounts for system uncertainties and measurement noise, both of which are ubiquitous in real-world grid systems and data. It ensures the method’s robust performance in practical settings. The examples in the paper demonstrate how the proposed framework can learn accurate time-domain models of fully black-box IBRs and deliver highly accurate long-horizon predictions of their responses to grid disturbances, e.g., subsynchronous oscillations caused by PLL interactions in weak grids. See details here: https://lnkd.in/eFd5CU4e #PowerSystem #SmartGrid #InverterBasedResources #RenewableEnergy #PowerElectronics #Control #PowerSystemStability #PowerSystemModeling #PowerSystemSimulation #SystemIdentification #DataDriven #MachineLearning #DeepLearning #ArtificialIntelligence #PhysicsInformed #IEEETransactionsOnSmartGrid

⚡ Traditional vs IBR Grids — From a Protection Perspective ⚡ As IBRs increasingly dominate power systems, protection engineers are facing a fundamental shift. The issue is not relay performance — it’s a change in fault source behavior. 1️⃣ Fault current magnitude 🔹 Synchronous machines Deliver high fault current (up to ~3 p.u.) almost instantaneously This is exactly what conventional protection (OC, distance, differential) was designed for 🔹 IBRs Fault current is limited (≈1–1.5 p.u.) and control-dependent GFL and GFM behave differently, but neither naturally provides strong fault current 🔑 Traditional overcurrent-based protection loses sensitivity with IBRs 2️⃣ Negative- and zero-sequence current 🔹 Synchronous machines Naturally inject negative- and zero-sequence currents during unbalanced faults 🔹 IBRs By default, contribution is minimal or zero Sequence currents can be synthetically injected via control, but this: Consumes current headroom Impacts voltage support and stability objectives 🔑 Protection elements relying on sequence components (earth fault, directional) become unreliable unless controls are carefully coordinated 3️⃣ Phase angle during faults 🔹 Synchronous machines Phase angle remains stable and predictable 🔹 IBRs Phase angle can change rapidly due to: PLL dynamics (GFL) Internal oscillator dynamics (GFM) 🔑 Distance and directional relays may misoperate due to an unstable angle reference 4️⃣ Harmonics and interharmonics 🔹 Synchronous machines Minimal harmonic content during faults 🔹 IBRs High harmonic and interharmonic content, especially during: Current limiting Control saturation 🔑 Relay measurements can be distorted Filtering and longer measuring windows may be required — at the cost of speed 5️⃣ Dynamic behaviour 🔹 Synchronous machines Governed by physical inertia and excitation systems Result in slower, smoother responses 🔹 IBRs Governed by fast electronic controls, leading to abrupt changes in: Current magnitude Phase angle Apparent impedance 🔑 This is the root cause of “non-intuitive” protection behavior in IBR-dominated grids 6️⃣ Fault duration and critical clearing time 🔹 Synchronous machines Stability is limited by critical clearing time (CCT) 🔹 IBRs Can ride through faults as per FRT requirements Do not lose synchronism in the classical sense 🔑 Faults may persist longer, making coordination between primary and backup protection more complex Fast tripping is no longer always aligned with system stability needs 7️⃣ Impedance seen by relays 🔹 Synchronous machines Fault impedance is relatively constant 🔹 IBRs Impedance is dynamic and control-driven 🔑 Distance protection faces serious reach and directionality challenges. IBRs are not “weaker generators.” They are fundamentally different fault sources — and protection philosophy must evolve accordingly.

Key Power System Protection Challenges in BESS + Solar/Wind Systems: 1. ⚡ Low Fault Current Contribution Inverter-based resources (IBRs) limit fault current to ~1.1–1.5 × rated current. Traditional overcurrent protection (50/51) becomes ineffective. Challenge for: Feeder protection Busbar protection Backup protection coordination 🛠️ Mitigation: Use differential protection (87) or distance protection (21). Employ IEC 61850 GOOSE logic for fast tripping schemes. 2. 🔁 Bidirectional Power Flow Protection must detect and respond to faults regardless of power direction. Impacts: Transformer protection (needs directional sensing) Reverse power protection (32R) Islanding detection schemes 🛠️ Mitigation: Use directional overcurrent (67/67N). Integrate with PPC/EMS logic for islanding and grid-following modes. 3. 🧲 Islanding and Anti-Islanding Protection Inverters may continue energizing a disconnected grid (unintentional islanding). Passive schemes (voltage, frequency) may not detect it promptly. 🛠️ Mitigation: Use active anti-islanding techniques (e.g., Sandia method, impedance shifting). Integrate ROCOF (df/dt) and vector shift relays (per G99 or grid code). 4. 🔌 Coordination Between Grid Code & Protection Grid codes like G99 (UK), NERC PRC (US), or CEA (India) require: Voltage/frequency ride-through LVRT/HVRT logic Fault ride-through (FRT) behavior Inverter protection must coordinate with utility protection. 🛠️ Mitigation: Implement adaptive protection logic in relays or PPC. Use grid-compliant protection relays (e.g., SMA615, P345, SIPROTEC 7SJ85). 5. 🧯 Transformer Differential Protection with Inverters Inverter inrush and asymmetry may cause false tripping in 87T. Also, transformer energization from BESS may appear as internal fault. 🛠️ Mitigation: Use harmonic restraint and inrush blocking in the 87T relay. Tune sensitivity thresholds based on commissioning data. 6. 🧠 Fast Dynamics of BESS Protection needs to operate faster than traditional systems. Energy management and protection must interact coherently. 🛠️ Mitigation: Use high-speed differential relays (e.g., RED615, SEL-487E). Implement EMS-PPC-protection integration via IEC 61850/GOOSE. 7. 🌩️ Grid Weakness and Stability BESS and solar may operate in weak grids with high impedance. Fault detection becomes less reliable due to lower fault current and poor signal quality. 🛠️ Mitigation: Use distance relays with quadrilateral characteristics. Apply positive-sequence overvoltage or ROCOF relays. 8. 🧮 Protection Settings Complexity Multiple modes: Grid-following, islanded, black start, etc. Requires mode-dependent settings. 🛠️ Mitigation: Use group setting selection (GSS) in relays. Automate settings switching through EMS/PMS.

The Hidden Weakness in Our Clean Energy Future The world is racing to build more solar, wind, and battery plants. These plants bring clean power but also change the grid's heartbeat. For over a century, big spinning machines in coal, gas, and nuclear plants gave the grid its strength. They had weight and momentum. When something went wrong, their mass kept the system steady. Now, those machines are closing, and with them goes that natural stability. In their place come electronic inverters. Most of them are grid-following. They only copy what the grid tells them. When there are too many of these, the grid starts to wobble. We see it in blackouts and near misses. In April 2025, the Iberian Peninsula went dark after a chain reaction. It was a warning. Grid-forming inverters are different. They can act like those old machines. They can set the pace, hold voltage, and push back when the system shakes. But they are not yet ready everywhere. They need better design, stronger protection, and rules that match their behavior. Here are the hard problems. They do not give inertia the way heavy machines do. When faults strike, their currents are limited by electronics, not physics. Protection systems built for big machines often fail to read the inverter signals correctly. Hybrid grids with both machine power and inverter power can conflict. The DC side of the inverter, where solar panels or batteries feed in, often cannot respond fast enough to keep the AC side strong. There are also policy gaps. Grid codes in many countries do not demand the right support from inverters. Markets reward megawatts, not stability. Engineers can design strong inverters, but they will not be built at scale without rules and incentives. Yet the opportunities are real. Batteries with grid-forming control can supply a fast response and even black-start a grid after a collapse. Weak grids in remote areas can be steadied if we use GFMs correctly. New designs are making progress on current limits and fault behavior. And pilot projects are proving that inverter-based systems can run whole islands and towns. What must happen now is clear. Utilities and grid operators should test these technologies in live systems, not just in labs. Manufacturers must design controllers that make GFMs easy to integrate with old equipment. Regulators must write standards that demand not only clean power but stable power. Policymakers must align incentives with stability, not just capacity. If we get this right, renewables will not just be plentiful, they will be dependable. If we ignore it, the lights will flicker and then fail. The choice is between fragile abundance and steady abundance. Stability is the core of the future grid. — #GridFormingInverters #PowerSystemStability #RenewableIntegration #EnergyResilience #CleanEnergy #EnergyStorage #FutureGrid #Infrastructure

Why multiple IBRs don’t act independently during grid disturbances This animation shows what really happens when several inverter based resources (IBRs) are connected to the same point on the grid. During a voltage dip: Each inverter reacts to the same grid weakness Each one injects reactive current to support voltage Current limits are reached, so active power is reduced Here’s the key insight: The voltage at the point of interconnection is not controlled by any single inverter. It is shaped by all inverter currents flowing through the same grid impedance. So when one inverter changes its current: The local voltage shifts Every other inverter sees that change Their controls react to it in turn This is why in weak grids: Inverters interact Controls become coupled Protection and stability issues can appear even when each unit is “doing the right thing” IBRs don’t respond to the grid alone, they respond to each other through the grid. #PowerSystems #IBR #GridStability #LVRT #WeakGrid #PE