Wind, solar and battery projects across Southeast Europe are expanding, while grid access is increasingly tied not only to installed capacity and connection infrastructure but also to the quality and stability of electricity injected into the power system. The issue is linked to how new generation behaves dynamically once connected.
European grid connection requirements expected in the next phase of implementation are set to focus on the dynamic behaviour of renewable assets. In particular, regulators are looking at whether large facilities create repetitive fluctuations that could interact with the wider Continental European synchronous system. The technical topic under discussion is forced oscillations, which may affect approval, financing and operation of renewable projects.
Forced oscillations and the NC RfG 2.0 assessment approach
Forced oscillations are defined as periodic variations in active power output driven by mechanical behaviour, environmental conditions, equipment characteristics or control-system interactions. ENTSO-E and WindEurope have developed a common assessment methodology to address the challenge. The work supports the proposed Network Code on Requirements for Generators 2.0 (NC RfG 2.0).
The revised network code has not yet been formally adopted by the European Commission, so its provisions are currently proposed rather than legally binding. Projects already in front-end engineering design, turbine procurement, grid studies or financing processes may still be assessed under the framework once it is incorporated into national legislation. In that context, forced-oscillation requirements can become part of project delivery timelines.
Synchronous-area links across Southeast Europe
The forced-oscillation issue is described as particularly relevant for Southeast Europe due to close integration with the Continental Europe synchronous area. Serbia, Montenegro, Bosnia and Herzegovina, North Macedonia, Albania, Kosovo, Croatia, Romania, Bulgaria, Greece, Hungary and Slovenia are either directly connected or operate within the wider electrical environment. A disturbance from a single generating facility can therefore interact with system-wide electromechanical behaviour and affect multiple countries.
Cross-border effects are expected because electricity markets can be organised into separate bidding zones while the grid remains interconnected. Disturbances can propagate through transmission networks beyond national borders. This means dynamic performance assessments can no longer be limited to local conditions alone.
How forced oscillations differ from normal variability
Normal renewable variability is characterised as expected production changes driven by wind speed variations for wind farms and sunlight changes for solar plants. Batteries adjust output according to dispatch instructions and these variations are managed by system operators. Forced oscillations are distinguished by repeated power fluctuations at identifiable frequencies that persist long enough to interact with power-system characteristics.
When oscillation frequencies approach natural modes of the system, resonance can amplify disturbances. The source mechanisms described for wind turbines include tower shadow effects, blade-passing frequency, wind shear, rotor dynamics, structural vibration modes and active tower-damping systems. Mechanical movement within turbine structures can translate into electrical fluctuations through changes in generator torque.
For solar and battery installations, potential oscillations are linked more closely to inverter controls and plant-level controllers. Weak-grid conditions and interactions between multiple converter-based systems operating at the same connection point are also cited as relevant factors. System operators’ concern is focused on whether disturbances occur at frequencies matching grid natural modes rather than on fluctuation size alone.
Frequency ranges tied to inter-area and local modes
Continental Europe’s main inter-area oscillation modes generally occur between 0.1 and 1.0 hertz. Local and intra-area oscillations typically fall between 1.0 and 2.0 hertz. These ranges are described as increasingly important for Southeast Europe because the region combines large synchronous generators with rapidly expanding inverter-based renewable capacity.
The transmission structure is also described as increasing the importance of dynamic performance across corridors. Major flows connect Romania with Bulgaria, Greece with the Western Balkans, Hungary with Central Europe and Serbia with neighbouring systems. Serbia is identified as a significant regional transmission corridor, while Serbia, Montenegro and North Macedonia cooperate through the SMM control block for balancing energy and reserve exchange.
Recent disturbance sensitivity in Continental Europe
The Continental Europe system separation on 8 January 2021 is cited as an example of how quickly operational problems can affect a larger synchronous area. The separation originated from cascading transmission events in Croatia rather than forced oscillations. The event is used to underline the importance of maintaining system stability across Southeast European corridors.
Where forced-oscillation requirements would apply
Under the proposed framework described in the methodology workstream, forced-oscillation requirements would primarily apply to Type C and Type D power park modules . Within the Continental Europe synchronous area, a proposed threshold for national classification of Type C facilities is 50 MW. Projects connected at 110 kV or higher voltage levels are generally considered Type D.
National transmission system operators would retain authority to introduce stricter requirements than those thresholds. As a result, a significant share of Southeast Europe’s future renewable pipeline could fall within the potential compliance framework described for these module types . Large wind developments mentioned include Serbia’s Čibuk 2 by Masdar and Taaleri and Enlight Renewable Energy’s Pupin wind project.
Compliance measurement boundaries for shared connections
The assessment challenge increases where multiple renewable projects share connection infrastructure because oscillations from individual turbines or separate sections of a wind farm may not be synchronised . At a common connection point some fluctuations may partially cancel each other out. That can mean a project that appears problematic when assessed independently could perform within limits when evaluated as part of a larger interconnected facility.
This leads to a technical and contractual question about where compliance should be measured . Potential measurement points listed include an individual plant transformer, a shared substation, the transmission-system connection point or an aggregated point of common coupling. The selected boundary needs definition before detailed engineering is completed and should be reflected in grid-connection agreements, EPC contracts, turbine supply agreements and operational procedures.
Monitoring responsibilities beyond ownership of assets
The document notes that ownership of connection infrastructure does not automatically determine responsibility for compliance . A developer financing a substation or export connection that later becomes part of the transmission network must still understand who is responsible for installing monitoring equipment. It also covers maintaining data systems and implementing corrective measures if performance requirements are not met.
Proposed limits for continuous and temporary oscillations
The technical limits described introduce a more detailed compliance framework for renewable generators under onshore wind assumptions . Continuous forced oscillations would generally be limited to either ±0.5% of maximum plant capacity or 500 kW, whichever value applies under the stated rule set. Temporary oscillations could reach ±2.5%, but the plant would need to return within the continuous limit within 180 seconds.
The temporary deviation reduction requirement is described as needing to fall below half of that level within half of the permitted recovery period . Temporary exceedances would also be restricted in frequency: they would generally be allowed for no more than 1% of each day under the proposed approach . The default assessment method would limit events to three exceedances per hour evaluated at the 95th percentile over a measurement period.
Sensitivity to threshold selection during methodology testing
The selection of thresholds is described as having direct impact on project compliance outcomes . Testing during development showed compliance rates varied significantly depending on which limit was applied . Under the strictest temporary onshore wind requirement only a small share of assessed operating periods achieved compliance.
Adoption of the proposed default threshold produced significantly higher compliance results compared with that strictest interpretation . The differences are presented as evidence that national implementation cannot be treated as only a procedural technical step . A transmission system operator applying strictest available interpretation could classify standard turbine configurations as non-compliant.
Data coverage gaps and detection challenges up to 20 hertz
The methodology itself is described as still developing . Available operational data covers mainly 0.1–2.0 hertz, while an obligation could extend up to 20 hertz. The analysed wind farms and manufacturers have not been publicly identified, while the assessment tool remains a developing MATLAB-based prototype rather than a fully mature industry platform .
A further challenge involves distinguishing true forced oscillations from normal operating events such as turbine start-up and shutdown processes, power ramps, curtailment instructions, wind turbulence and system-support actions . These can create fluctuations that resemble oscillatory behaviour . To reduce false identification, minimum detection periods are proposed potentially between one and ten seconds depending on project and system conditions.
SCADA limits versus PMU-based monitoring standards
The detection-period approach creates additional requirements for accurate operational records so developers can demonstrate whether an event was caused by their facility or by external grid-support instructions . Many existing renewable facilities rely on conventional SCADA systems recording active power at intervals of one second or ten seconds or longer . Such data may be insufficient for analysing higher-frequency oscillations between 2 and 20 hertz.
The proposed monitoring approach uses phasor measurement units (PMUs) preferably compliant with IEC/IEEE 60255-118-1, together with accurate current and voltage measurement equipment . For oscillations up to approximately 2 hertz, around 100 milliseconds measurement resolution may be sufficient . Monitoring across up to 20 hertz requires substantially higher sampling capability with practical systems expected around 50 samples per second.
EPC-stage integration for time synchronisation and cybersecurity
The monitoring requirements should be incorporated during early engineering stages rather than added after construction . PMU installation plans include communication systems, time synchronisation, data storage and cybersecurity interfaces considered during substation design and procurement . Retrofitting after commissioning can require modifications to protection panels along with additional testing and operational interruptions.
The document therefore describes dynamic monitoring capability as part of standard design philosophy for large renewable and storage projects . Compliance assessment continues beyond construction because initial assessment begins after completion of a period of commercial operation . The first evaluation requires sufficient operating data representing different weather conditions, loading levels and operating scenarios.
Turbine certification interactions with structural damping controls
A project could energise complete standard grid compliance testing begin commercial operation while still carrying potential future obligations related to forced oscillations . Financing considerations then treat dynamic performance as an ongoing operational requirement rather than only a one-time construction milestone . Financing agreements would need clear allocation covering modelling, monitoring, data analysis, equipment upgrades manufacturer support controller modifications and potential production losses.
A general commitment that turbines or inverters comply with applicable grid code may no longer be sufficient because final outcomes depend on project-specific limits set by transmission operators plus measurement point selection aggregation methodology and detection algorithm choice . The issue extends into turbine structural design since modern turbines use active tower damping systems adjusting generator torque to reduce mechanical stress . Those control actions can influence electrical power output potentially creating measurable oscillations.
If stricter grid requirements reduce power fluctuations they may require changes increasing mechanical loads affecting tower design foundation requirements fatigue calculations or certification procedures . Once certified configurations reach commercial operation modifications can become technically complex and financially expensive . Mitigation solutions mentioned include battery storage STATCOM equipment flexible AC transmission technologies improved control algorithms and structural damping systems.
Treatment of hybrid plants using integrated control analysis
The appropriate mitigation depends on where oscillation sources originate; battery storage could absorb rapid changes in renewable output but is not presented as universally solving dynamic issues . Poorly coordinated inverter controls could introduce additional dynamic problems especially in weak-grid locations . Hybrid projects combining wind solar and storage would therefore need integrated control-system design rather than treating assets separately connected together.
The interaction between multiple inverters plant controllers and grid-support functions must be analysed as one operational unit when assessing dynamic behaviour at shared points . For Southeast Europe uneven regulatory implementation across countries adds complexity since Serbia North Macedonia Bosnia and Herzegovina have made progress adopting existing European grid connection requirements while Montenegro Albania Kosovo continue developing parts of formal implementation frameworks . In Serbia EMS already performs functional testing approval procedures for energisation temporary connection and permanent connection.
Status of certifiers and national thresholds across operators
The introduction of more advanced dynamic requirements could increase workload for national operators as large volumes of wind solar and battery projects approach commissioning simultaneously . The region lacks a strong network of authorised independent technical certifiers able to perform complex dynamic assessments according to operator responsibilities described in validation processes relying on simulations manufacturer documentation commissioning tests and operational measurements . Transmission system operators remain responsible for much validation work.
Divergent national approaches without coordination could create barriers for investors because separate technical thresholds measurement requirements evidence standards adopted by EMS CGES NOSBiH MEPSO KOSTT OST could require different compliance packages per market . A coordinated Southeast European framework would use common rules covering measurement locations sampling rates data formats operational exclusions monitoring periods and assessment methodologies while preserving national system operator authority . This coordination is positioned around standardising technical solutions across markets.
Cumulative grid constraints alongside forced-oscillation obligations
Southeast Europe’s renewable pipeline already faces challenges from grid congestion limited transmission capacity and lengthy connection procedures before considering forced-oscillation obligations linking turbine design inverter controls substation engineering plus long-term ability to operate . Projects entering front-end engineering stage today should therefore be designed for future grid requirements rather than current minimum standards according to planning guidance described in relation to cost comparisons during construction versus later redesign needs . Installing high-quality monitoring systems preparing accurate data infrastructure defining contractual responsibilities during construction is stated as lower cost than redesigning controls modifying equipment or repeating compliance testing after commercial operation.
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