Ensuring grid stability with high levels of IBRs is a growing technical challenge. Traditional grids derived strength and inertia from big spinning generators, but when those are replaced by solar inverters and wind turbines, the system behaves differently.
Renewable Grid Integration
Q&A with Parth Shah, P.E., Technical Consultant and Product Manager | Hitachi Energy
What are the biggest technical hurdles renewable developers face when trying to connect solar, wind, and battery projects to the grid, and how are these challenges evolving?
One of the fundamental hurdles is limited grid capacity and lengthy interconnection queues. In many regions, the transmission system was not built for the rapid influx of solar, wind, and storage projects, so developers find that available connection points are scarce or require costly upgrades. As a result, interconnection wait times have ballooned In the U.S., the average wait has doubled since 2015 to over three years. At the end of 2022, more than 10,000 projects (over 2,000 GW of generation and storage) were stuck in interconnection queues nationwide. This backlog forces developers to navigate cluster studies and uncertain upgrade costs. Network inadequacy has become a global issue: there simply isn’t enough transmission in the right places to accommodate all the new renewables. These capacity constraints are prompting reforms (like FERC Order No. 2023) to streamline the queue with “first-ready, first-served” cluster studies, but for developers the near-term reality is that securing a grid interconnection can be a protracted, complex process.
Beyond the capacity bottlenecks, ensuring grid stability with high levels of inverter-based resources (IBRs) is a growing technical challenge. Traditional grids derived strength and inertia from big spinning generators, but when those are replaced by solar inverters and wind turbines, the system behaves differently. The reduction in synchronous generators decreases system strength and inertia, leading to reduced voltage and frequency stability margins. In practice, this means a renewable developer might face stringent requirements to prove their project won’t destabilize local voltage or frequency. System strength (short-circuit strength) issues can manifest as voltage fluctuations or protection malfunctions in weak grids. In fact, at high renewable penetrations there have been instances of instability. For example, a major 2019 UK blackout was triggered by the sudden loss of a wind farm alongside a gas plant, exposing how a low-inertia grid can struggle to recover. As these challenges evolve, new phenomena such as harmonic interactions and control instabilities are emerging. Inverter controls can interact with the network and other devices (like HVDC links or capacitor banks) in unintended ways, sometimes causing sub-synchronous resonances (SSR) or oscillations. Studies have shown that power-electronic control interactions can damage equipment (e.g., turbine shafts) and are time-consuming to diagnose and expensive to fix if discovered late. Therefore, developers today must not only worry about getting in the queue, but also about performing more advanced studies (stability, SSR, harmonics, etc.) to meet evolving grid codes. In short, the hurdles are shifting from simply finding a grid connection to making sure the project can operate reliably on the grid. This drives a need for sophisticated modeling, stronger partnerships with utilities, and in some cases deploying new technologies (like advanced inverters or synchronous condensers) to overcome integration challenges.
How do Grid-Following versus Grid-Forming inverters impact renewable integration, and what should developers understand about these technologies?
The distinction between grid-following (GFL) and grid-forming (GFM) inverters is crucial as we integrate more renewables. Grid-following inverters are the traditional type used in most solar, wind, and battery installations today. They act as current sources that latch onto the grid’s voltage waveform. In essence, a GFL inverter needs an existing stable grid to operate; it uses phase-locked loops to synchronize with the grid’s frequency and voltage. These inverters are simpler and cost-effective, with fast control responses, but they cannot establish grid voltage or frequency on their own. As a result, in a weak or blacked-out grid scenario, grid-following systems can’t hold up the grid. They actually depend on conventional generators (or other sources) to set the reference. Developers should be aware that high concentrations of grid-following resources can lead to stability issues; if the grid voltage becomes erratic or the frequency deviates, GFL inverters have limited ability to help and may even trip offline. For example, under severe disturbances, a phase-locked loop in a GFL inverter can lose synchronization, which is a known risk in low-inertia systems.
Grid-forming inverters, by contrast, are an emerging solution designed to tackle those very issues. A grid-forming inverter operates as a voltage source, being able to establish and regulate its own AC voltage and frequency, effectively mimicking the behavior of a traditional synchronous generator. This means GFMs can set the pace for other inverters and even form an islanded grid. In practical terms, a grid-forming battery or wind turbine could ride through disturbances by sustaining voltage and frequency, instead of dropping out. They inherently provide synthetic inertia and fast frequency response: a GFM can resist changes in frequency for a few seconds using its controls and help absorb or inject power to stabilize the system. This capability is a game-changer as renewable penetration rises. For instance, grid-forming batteries have been demonstrated to provide substantial inertia support. In South Australia a 150 MW battery now supplies about 15% of the region’s inertia needs via virtual synchronous machine mode. Developers should understand that GFMs can improve system strength and resilience: they support voltage during faults, enable black-start capability (starting the grid from scratch), and dampen oscillations. However, they are also more complex and currently more expensive. Integration of GFM technology is still in early stages, and there are challenges around standards and interoperability. From a developer’s perspective, it’s important to follow the evolution of grid-forming requirements. Some grid operators are beginning to encourage or even require grid-forming capability in weak grid areas. For example, ERCOT has strongly encouraged GFM capability for new projects in low short-circuit ratio locations. The key takeaway is that grid-following inverters suffice in strong grids today, but grid-forming inverters are likely to play a pivotal role in the near future. They will help ensure stability in networks dominated by renewables, and developers should be ready to adopt GFM technology as it matures, whether by using inverters with dual modes or adding energy storage with grid-forming controls. Keeping an eye on evolving standards like IEEE P2800 (which addresses inverter performance) and engaging in pilot projects for GFM will position developers to better meet future interconnection requirements.
With utilities under pressure to accommodate massive offshore wind capacity, what grid infrastructure changes are most critical?
Integrating gigawatt-scale offshore wind is a monumental task that calls for significant upgrades and new infrastructure on multiple fronts. First and foremost is transmission expansion. Offshore wind farms are often located far from load centers (e.g., 30–60 miles out to sea), so we need high-capacity transmission links to bring that power onshore. Planners are looking at high-voltage solutions. For example, HVDC transmission is likely to play a big role because it can efficiently carry large amounts of power over long distances under the sea. We’re already seeing proposals for coordinated transmission hubs: one idea is to have an offshore or coastal “backbone” where multiple wind projects connect and feed into the grid at a few robust points, rather than each project splicing into the grid independently. Such planned, networked approaches can reduce the number of redundant export cables and onshore grid upgrades required. These upgrades must ensure there’s enough capacity to carry the wind energy into the existing grid without overloads. It’s a massive investment: studies have shown that proactive offshore transmission planning can avoid billions in onshore upgrade costs by optimizing where and how wind power is injected.
Beyond just adding wires and stations, grid infrastructure must be enhanced for stability and reliability when large offshore wind plants come online. Offshore wind is produced by inverter-based resources (the wind turbine converters and any HVDC converters), which means the onshore grid receiving will see a high volume of non-synchronous injection. Utilities and developers will likely need to invest in equipment like synchronous condensers or STATCOMs to provide additional short-circuit strength and voltage support at key nodes. For example, in weaker parts of the network, adding a synchronous condenser (essentially a spinning generator without a prime mover) can help maintain stable voltage and inertia as the wind output fluctuates. Harmonic filters or carefully tuned reactive compensation might be critical too. Large HVDC converter stations and long cables can introduce harmonic distortion, so filtering systems must be in place to meet standards (like IEEE 519 limits on harmonics). From my experience, a study for integrating several GWs of offshore wind, one should focus on grid integration studies that checked stability and harmonic compliance under various scenarios. This includes performing harmonic impedance scans to ensure the offshore wind converters wouldn’t excite resonances in the grid. Another critical change is upgrading protection schemes and operational tools. Protection systems may need to be adjusted for lower fault currents from inverter-based sources. Additionally, grid operators will implement advanced control systems to manage the variability – for instance, fast-acting generation dispatch or energy storage to smooth output. In summary, the path to GWs offshore wind involves a holistic grid makeover: new transmission infrastructure (HVDC links, cables, substations), system strength enhancements (voltage support, inertia substitutes), and updated planning/operations protocols to maintain reliability as this massive new resource is connected.
How can model quality testing and harmonic analysis prevent costly delays and technical issues in renewable interconnection projects?
“Model quality testing” (MQT) is essentially a due diligence process to ensure that the simulation models of a new renewable plant accurately reflect its real behavior. It might sound arcane, but it has very practical implications for project timelines. Grid operators like ERCOT have learned that if a solar, wind, or battery project comes in with a poorly tuned or inaccurate dynamic model, it can lead to surprises laterFor example, unexpected control interactions or failure to ride through a disturbance. By requiring model quality testing up front, the developer and consultants prove that the plant’s inverter control models behave properly under a range of conditions (voltage dips, frequency swings, etc.) before the project ever gets operational. This proactive testing can catch unstable control settings or errors in the model that would otherwise cause the plant to trip unexpectedly or not meet grid codes. Preventing those issues avoids costly late-stage fixes. Imagine if after commissioning, a wind farm keeps tripping during minor voltage oscillations; that could force a shutdown and retrofit of controls, costing months of delay. Instead, with rigorous MQT, such problems are identified in simulation and corrected long before equipment is energized. ERCOT’s process is a good example: they now require that inverter-based resource owners submit detailed models and perform a variety of tests (comparing model output to expected results) as part of interconnection. If the model doesn’t meet the standards, say it doesn’t match the field test data within a certain tolerance, the project cannot move forward until it’s fixed. This incentivizes developers to work closely with manufacturers to get the models right. In my work, I develop detailed PSS/E and PSCAD models for renewables and run these quality tests per ERCOT’s criteria, and it undoubtedly has saved projects from headaches by ironing out model flaws early.
Hand-in-hand with model quality is harmonic analysis, which is all about ensuring the new plant will not introduce problematic electrical harmonics or suffer from resonance issues when it connects to the grid. Every inverter or HVDC converter can generate harmonic currents, and the network itself has natural resonant frequencies. If a project is connected without proper study, you might later find that at a certain frequency, say the 5th or 7th harmonic, the combination of the plant and the grid causes a big voltage distortion or even equipment damage. This has happened in the past: there have been instances of sub-synchronous resonance (SSR) where wind farms interacting with series-compensated lines led to turbine failures. Such issues, if discovered late, can be “expensive to fix” and cause long project delays (as one might need to design and install hefty filter banks or even modify the turbine controls). By conducting harmonic analysis during the interconnection study stage, these risks can be identified and mitigated proactively. A harmonic impedance scan, for example, will reveal if the grid at the point of interconnection has a resonant spike at a frequency that coincides with the inverter’s harmonics. If it does, the developer can design a filter or damping solution as part of the project scope, rather than discovering the issue during commissioning when the plant fails a THD (Total Harmonic Distortion) test. Many utilities now require a harmonic compliance study to show the project will meet standards like IEEE 519 (which limits voltage THD, often to 5-8% depending on voltage level). In my role, I am managing the Harmonic Assessment Toolset that automates these studies – computing network harmonic impedance, distortion levels, and designing filters. This kind of upfront analysis ensures that by the time the project is built, it can smoothly pass harmonic performance requirements. The payoff is avoiding last-minute surprises that could otherwise force a project to halt operations while fixes are implemented. In summary, model quality testing and harmonic analysis are preventive medicine for grid integration: they tighten the accuracy of predictions and iron out incompatibilities early, thereby saving developers from costly rework, preserving project timelines, and safeguarding grid reliability.
What role do energy storage systems play in solving grid stability challenges as renewable penetration increases?
Energy storage systems are becoming an indispensable tool for maintaining grid stability in the face of high renewable penetration. One major challenge with renewables is their variability and the resulting stress on frequency control. Storage can act as a shock absorber for the grid. For instance, when solar output suddenly drops due to cloud cover or wind generation lulls during a calm, a battery can swiftly inject power to compensate, keeping the grid frequency steady. Conversely, during periods of excess renewable generation, batteries can absorb the surplus, preventing over-frequency or the curtailment of renewables. This fast balancing capability is something traditional generators (with slower ramp rates) struggle to provide at the speed required. In fact, batteries excel at frequency regulation services; they can respond within fractions of a second to correct frequency deviations. Many grid operators now rely on grid-scale batteries for primary frequency response and regulation reserves because they’re so agile.
Beyond balancing energy, storage contributes to inertia and stability in new ways. With advanced inverters, a battery system can be configured in grid-forming mode to provide virtual inertia. Essentially, the inverter is programmed to mimic the inertial response of a spinning mass. When the frequency dips, the battery discharges power almost instantaneously to arrest the decline (and charges when frequency rises). This is often called synthetic or “virtual” inertia. It’s a critical service in low-inertia grids. Grid-forming batteries can also help with voltage stability, acting like a voltage source that holds up the local voltage during disturbances. They can even perform black start, meaning they can energize a dead grid and form a reference for other resources to follow. This was once the sole domain of thermal plants; now storage is taking on that role in pilot projects.
For developers and utilities, storage is also a key to smoothing out the “duck curve” and other operational challenges of high renewables. By charging during midday when solar generation is peaking (and demand is low) and discharging during the evening peak, batteries flatten the net load curve and ease ramping requirements on other plants. This not only improves grid stability but also maximizes the use of renewable energy that would otherwise be curtailed. Furthermore, energy storage provides ancillary services such as fast frequency response, spinning reserve (a battery can be on standby to inject power immediately if another resource trips), and even reactive power support. In summary, as renewables become the dominant source, energy storage is the linchpin that can supply the missing pieces of grid stability: inertia, frequency regulation, ramping support, and voltage control. It’s why we see massive deployments of batteries in places like California, Texas, and Europe. They not only keep the lights on in a high-renewables grid by responding faster than any power plant, but they also enable deeper renewable integration by making the grid more flexible and resilient. Moving forward, one can anticipate energy storage to be co-located with wind and solar farms as standard practice, essentially acting as the stabilizing “brain and muscle” for these clean resources on the grid.
How are transmission planning requirements changing to support the clean energy transition, and what should developers anticipate?
Transmission planning is rapidly evolving from a traditional, slow-paced process into a more agile and forward-looking one to enable the massive scale-up of clean energy. Developers should anticipate several key changes in requirements and processes:
- Move to Cluster Studies and “Ready” Projects: The interconnection process, which is closely tied to planning, is undergoing reform. Under FERC Order No. 2023, the old “first-come, first-served” serial queue is being replaced by “first-ready, first-served” cluster studies. This means that projects are studied in batches with set windows, and only those meeting stricter readiness criteria progress. Transmission providers are also held to firmer timelines with penalties for delays. Developers should be prepared for more regimented study cycles, larger study groups, and the need to demonstrate project maturity early. The new rules also improve transparency. For example, planners must publish capacity “heatmaps” of the grid. Utilizing these, developers can better anticipate where the grid can accept new generation with minimal upgrades. Overall, the planning requirement is shifting towards efficiency: only serious projects enter the fray, and transmission planning can then size upgrades for a cluster of resources rather than one-by-one.
- Proactive Long-Term Planning & Policy-Driven Upgrades: In the past, transmission planning was largely reactive, building new lines when reliability criteria were violated. Now, with decarbonization goals, planners are looking 10–20 years ahead to identify upgrades needed for public policy objectives (like state renewable mandates). Other regions are similarly implementing scenario-based planning: MISO and SPP have started multi-year plans for a future grid with high renewables, identifying new “trunk” lines to wind-rich areas. FERC has signaled support for this approach, urging incorporation of future generation portfolios into planning criteria. Developers should anticipate more planned transmission projects that create capacity for renewables, as opposed to the ad-hoc upgrades of the past. This means opportunities to connect may improve if you align with those plans. For example, if a new 345 kV transmission line is built to a high-solar region, projects in that region might face lower interconnection costs after it’s in place. At the same time, if you’re first in a new area, you may be required to fund network upgrades that later projects will share. Understanding your RTO’s long-term roadmap is becoming as important as the interconnection queue itself.
- Stricter Modeling and Reliability Requirements: With the rise of renewables and storage, planning studies now demand more detailed modeling and stricter performance standards. Planners and regulators (NERC, for example) are introducing new requirements for inverter-based resources in studies. A clear sign is NERC’s guideline recommending that EMT (electromagnetic transient) models be provided for all new inverter-based plants – this is a step beyond the old RMS stability models, reflecting concern about control interactions that require finer simulation. We also see new NERC reliability standards in development focusing on IBR model validation and performance. Developers should expect that as part of the planning and interconnection process, they’ll need to supply more robust models (perhaps EMT models, detailed plant-level controls) and even commit to certain performance capabilities. For example, FERC and NERC are discussing standards that might require ride-through of disturbances (voltage/frequency) that exceed the current IEEE or PRC-024 guidelines, given the weak grid issues. In Texas, ERCOT’s planning criteria now include things like mandatory Weak Grid Mitigation Plans if your project is in a low short-circuit area, and possibly a requirement to have grid-forming or fast frequency response capability for large plants. All this translates to developers needing to anticipate additional up-front work: more comprehensive studies (stability, SSR, EMT, etc.), stronger validation of their models, and potentially investment in advanced controls or added equipment to meet the criteria.
In summary, transmission planning is becoming more integrated and forward-looking. There’s an emphasis on planning the grid for the clean energy transition rather than letting the grid limit it. Developers should anticipate a planning environment that demands greater technical diligence (through detailed modeling and testing), adherence to new interconnection processes (cluster studies with strict milestones), and participation in coordinated expansion efforts. The positive side is that these changes aim to streamline the build-out of renewables. For instance, cluster study cost-sharing and planned transmission can reduce uncertainty and bottlenecks. But it also means that success will favor those developers who are technically prepared and engaged with the evolving requirements. Staying updated on FERC orders, new IEEE/NERC standards, and your region’s transmission roadmaps will be essential. In practice, a developer might need to budget for longer lead times to get through studies, possibly hire specialized consultants for things like EMT studies or harmonic screening, and design projects with grid support capabilities in mind (such as voltage control or inertia support from day one). The grid of 2030 will be very different from today’s, and transmission planning reforms are the bridge to that future. Developers who understand the new rules of the road will be best positioned to connect their projects efficiently and reliably into the clean energy grid.
Parth Shah, P.E., is a Technical Consultant and Product Manager at Hitachi Energy with over 3.5 years of experience in power system consulting. He specializes in renewable energy interconnection studies, grid integration analysis, and model quality testing for solar, wind, and battery storage systems. He holds a Master's in Electrical Engineering from USC and a Professional Engineer license in Power Systems, advising utilities, renewable developers, and ISOs on transmission planning and grid stability challenges.
The content & opinions in this article are the author’s and do not necessarily represent the views of AltEnergyMag
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