Renewable Energy Grid Integration Week 2024

Hydrogen, through electrolysis technologies, is crucial for sectors that cannot be fully electrified. However, aging phenomena in water electrolysers reduce efficiency, service life, reliability, and safety, especially with frequent startups and shutdowns, common with renewable energy sources like solar and wind. This degradation leads to decreased efficiency and higher operating costs over time, and a degraded membrane can create an explosive mixture by allowing hydrogen to transfer to the anode.While overall degradation can be tracked by measuring cell voltage, this does not identify specific causes or suggest preventative actions. Therefore, monitoring and understanding degradation is essential for advancing electrolysis technologies. This paper presents a model-based approach for continuous monitoring, allowing the identification of ageing causes and providing recommendations to prevent and mitigate these effects, thereby improving safety, service life, and efficiency and supporting the global hydrogen strategy.

Dynamic unbalance in low-voltage grid can be controlled by battery energy storage systems (BESS). A calculation of the cost caused by unbalance is not that clear. Distribution System Operators (DSOs) have to cover grid losses, including unsymmetrical losses. Energy and power used for unbalance reduction is yet not requested from the DSO. Dynamic unbalance disturbances can occur violating the VUF limit of 2% according to standard EN 50160. Deteriorating life-cycle costs can be estimated, but the detailed costs for the influence of unbalance in the low-voltage grid are indeterminable. This study focusses on BESS owners with photovoltaic (PV). Using BESS with an unbalance control with their associated costs to find out a fair compensation. Challenges lie in calculating a fair price considering PV feed-in tariffs, costs for operating the BESS, pricing of the benefit of the dynamic unbalance control for the DSO, technical standards and grid codes. Simplified implementation of an unbalance control in BESS involves identifying the behaviour of multiple BESS and its power and energy possibilities in the grid calculated due to laboratory experiments and simulations. This paper provides a suggestion of a fair cost compensation with a factorized energy recharge from the DSO for a voltage unbalance factor control by BESS.

Large-scale battery storage systems are increasingly being used for a variety of applications, including ancillary services in the power grid. The reliability, lifetime and performance of large-scale battery storage systems depend on various factors. Our 5 MW/7.5 MWh research-focused hybrid battery storage system M5BAT (Modular Multi-Megawatt Multi-Technology Medium Voltage – Battery Storage System), consists of ten battery units, including two lead-acid technologies and three lithium-ion technologies with different properties and is mainly operated on the Frequency Containment Reserve (FCR) market. This study presents our experiences, challenges, and solutions for the successful operation of the large-scale battery storage system M5BAT in field application. The results show that on the BMS side of different battery units, 75 % of outages are caused by communication and sensor errors, as well as difficulties with balancing and proper SOC estimation. Balancing issues lead to a reduction in usable capacity of up to 35 % of a M5BAT battery unit, which limits the performance of the battery unit and the whole battery storage system. Solutions need to be implemented by the manufacturers, but intelligent energy management systems can detect issues early and trigger maintenance cycles. On the efficiency side, low partial load operation (utilization < 10 %) increases the losses in the power conversion system and results in roundtrip efficiencies of 70 % to 75 %. Implementing an efficient inverter control algorithm including inverter switching rules and the introduction of multi-use operation to increase utilization can help to enhance efficiency At M5BAT, we were able to demonstrate round-trip efficiencies around 80 % in regular FCR operation and around 85 % round-trip efficiency in energy trading operation. The in-house developed energy management system with a power distribution algorithm can handle different battery technologies and battery sizes in terms of energy-to-power ratio with user defined energy throughput and power levels. The experience with M5BAT has demonstrated the impact of increased availability and marketable power. The findings of this evaluation provide a valuable foundation for large-scale battery system operators and future research and development efforts focused on improving the design and operation of large-scale battery storage systems. This will contribute to the widespread adoption of sustainable energy solutions.

Hydro-Quebec TransEnergie, the transmission grid operator, is conducting a pilot project using a grid-forming battery energy storage system (BESS) operating as the only source of an islanded network with a 1MW residential load powered at 25kV. The BESS (20MWh) is charged from the grid at 4MW, collecting energy from renewable energy source (93% of hydraulic generation). The BESS releases the energy when the main power source, the grid, is unavailable to avoid the use of diesel generators.The technical specifications in terms of performance and functionality required the BESS to replicate the behavior of a synchronous generator. The system dynamic performances were demonstrated by simulations and test validation during this innovative project. The approach was using electromagnetic transient (EMT) simulations, hardware-in-the-loop, on-site testing with transient recorder and BESS faults tests.The transient studies and transient recordings during tests, one of the main interests of the project, allowed the identification of some performance issues related to this new technology that may be difficult to observe with the usual approach of this type of project. The transient phenomena are as important as the steady state performances and should be the main design factor for these projects. BESS faults testing also give a better understanding of somes limits of the system.The present paper shows some transient challenges, issues, some corrections, and recommendations for future projects. Some of those presented challenges are:

• Control algorithms during a fault with the island configuration and it’s firmware update (simulation and control-in-the-loop).
• Overvoltage observed when transitioning from grid-connect to island (simulation and on-site testing).
• Power oscillations due to some control instabilities (simulation and control-in-the-loop).
• Differents faults tests results.

The electricity system of Finland has faced new challenges due to the increasing penetration of inverter-based resources (IBR), such as wind power. Rapid increase of IBR can cause new stability challenges such as converter driven and resonance stability issues. Fingrid, the Finnish transmission system operator, has implemented various measures to mitigate these issues. These measures include new monitoring tools, technical requirements, operational guidelines and tendering grid supporting devices. This paper presents large-scale electromagnetic transient (EMT) simulations that compared the performance of different grid supporting devices, such as synchronous condensers, grid following (GFL) and grid forming (GFM) static synchronous compensators (STATCOMs), and GFM battery energy storage systems (BESSs). The results highlight the effectiveness of GFM based devices to improve the damping of converter-driven and resonance oscillations. Fingrid has decided to invest in a synchronous condenser and GFM STATCOMs, and to require GFM control for new BESS connections in regions with high converter penetration. The paper also presents the new Finnish grid forming BESS requirements and discusses future challenges and opportunities of hybrid power plants and converter-connected loads.

Dynamic voltage and frequency oscillations in offshore island grids are significantly higher than in strong interconnected onshore grids. The integration of wind turbine generators in such grids is therefore challenging. This paper presents the pioneering work of integrating the Hywind Tampen offshore wind park into a hybrid grid with five remote interconnected oil and gas field platforms in the North Sea. The aim of the project is to reduce CO2 emissions by substituting part of the local fossil fuel-based power generation on the installations with wind energy. The dynamics of the system require fast acting grid stabilizing wind turbine controls to support the power system stability. This paper discusses challenges and solutions for the successful integration of wind turbines into hybrid grids. Furthermore, two dynamically challenging operational events are shown. Detailed simulations and field commissioning results of the full-scale tests for these cases are presented.

This paper presents a comprehensive investigation into the harmonic distortion observed at the onshore point of interconnection(POI) of an offshore wind farm. The study focuses on assessing the harmonic performance of the offshore network, taking intoconsideration various components such as passive offshore network elements, wind turbine generators (WTGs), STATCOM,and background harmonic sources. The research involves a thorough analysis of different switching configurations. Criticalresonances between the onshore grid and the offshore network are identified, leading to significant amplification of backgroundharmonics. The paper also evaluates the effectiveness of various mitigation strategies, including active filters from wind turbinesand the active filter function of the STATCOM, in compensating for harmonic distortion during worst-case resonanceconditions. The study provides valuable insights that can aid in optimizing the design and operation of offshore wind farms,ensuring compliance with regulatory standards, and minimizing the risk of harmonic-related issues.

This paper presents investigations focussing on the parallel operation of grid-forming and grid-following inverters with a focus on static voltage support with Q(V) characteristics. The focus here lies on the stable operation of the various inverter controls, the effectiveness of Q(V) characteristics in grid-forming inverters and the distribution of the reactive power provided in parallel operation of both inverters. In order to investigate these aspects, a laboratory test was set up in which the parallel operation of the two inverter types was tested and compliance with the Q(V) characteristic curves was verified for both inverters. In addition, the dynamic behaviour of the reactive power supply per Q(V) characteristic curve of the grid-forming inverter was recorded in the laboratory and compared with the requirements of the grid code VDE-AR-N 4105. In the next step, the laboratory tests were used to verify simulation models, which were then used to investigate the behaviour of both inverters in a low-voltage grid. The simulations show the effectiveness of Q(V) characteristics in grid-forming inverters in terms of supporting the local voltage. Furthermore, it is shown that the provision of reactive power in parallel operation is not dominated by one of the two inverter control types.

This study examines the dynamic responses of grid-forming converters operating under a hybrid synchronous control strategy, which integrates a power-frequency loop with phase-locked loop like technology. This control strategy aims to enhance the converter's responsiveness to current thresholds, thereby minimizing or shortening periods of synchronization losses. In this paper, a mathematical model is developed, and an analytical investigation is conducted to analyze the dynamic behavior of these converters under the influence of the hybrid synchronous control strategy, particularly after abrupt grid condition changes. The findings indicate that the hybrid synchronous control may prompt erroneous control actions under certain grid conditions and current thresholds. These erroneous actions can occur due to the specific characteristics of the system. As a result, the converter may become trapped in a state of current saturation. These theoretical predictions have been verified through controller hardware-in-the-loop experiments.

In recent years, climate change has led to increasingly severe weather phenomena, which have undermined the reliability of power grids. Considering this, the public is now demanding that grid operators accelerate the energy transition and the integration of new, cleaner technologies, while maintaining or even improving grid reliability. For this reason, Hydro-Quebec has launched a pilot project to install a battery energy storage system (BESS) in a remote village that is connected to the main transmission grid by a 60 km high-voltage transmission line. This line is at the end of its useful life and requires major work. Two of the main functionalities required for the BESS are to function in islanded mode with the local load and to have the ability to perform a cold load pick-up following a blackstart. Numerous EMTP simulations has demonstrated that the BESS can perform cold load pick-up and that its behaviour is different from a diesel generator (DG). The measurements taken during the network test show that the simulation models are fairly accurate for this type of phenomenon.

As renewable energy integration on a large scale continues to expand, the inherent inertia within power systems diminishes, leading to an acceleration in the rate of frequency changes and diminishing the system's ability to promptly adapt to these fluctuations. Consequently, there arises a pressing demand for novel renewable energy installations to provide inertia to the system, a concept termed ‘synthetic inertia’. This research delves into the examination of synthetic inertial response exhibited by an operational solar photovoltaic (PV) power plant situated in Spain, in compliance with the national grid code.In Spain, MO TED/749/2020 outlines the technical standards that generation facilities must adhere to, while the Spanish technical supervision standard, known as the ‘Norma Técnica de Supervisión’ (NTS), oversees compliance with the technical specifications outlined in MO TED/749/2020. This updated Spanish grid code not only incorporates the synthetic inertia requirement but also delineates the methodology that PV power plants in Spain should follow to meet this requirement.In the Spanish grid code, compliance with the synthetic inertia requirement by generating units can be assessed through dynamic simulations, which are mandated to be conducted, in principle, only at the Power Generation Unit (PGU) level. In the current scenario, dynamic simulations were performed using a validated model of a PV power conversion system. The testing is conducted under the following three conditions: 1) At a load ranging from 0.25 to 0.50 times the nominal power (PN) of the PGU; 2) At a load exceeding 0.80 times PN of the PGU; and 3) At a load below PN of the PGU. PN should correspond to the available active power (Pav), which represents the potential power generation based on the primary available resource. In the third scenario, the PGU is operating in a de-loaded control mode. In addition, the three test cases should be studied under both increases and decreases in frequency. The evaluation of the synthetic inertia capability requirement is carried out by analyzing the active power at the PGU terminals.The reaction time -defined as the duration from when the control signal for activating the PGU response is dispatched until the amplitude change reaches 10% of the step height of the measured output variable- measured upon activation of the inertia emulation module is consistently lower in all scenarios. Concerning response time, which measures the duration from the onset of the event - the change in the power response of the PGU- until its value falls within the predefined tolerance band of the target value, the values recorded with the activated inertia module consistently demonstrate lower figures than those when the module remains inactive, mirroring the trend observed in reaction time.Therefore, as a conclusion, it can be asserted that the PV system in question meets the synthetic inertia technical requirement outlined in the Spanish grid code.

One of the main challenges in the design phase of wind turbines is the estimation of power production in the real environment. Although there are some computer-aided simulations, wind tunnel experimental data, and empirical formulas, most of them lack accurate forecasts. In this study, a novel hybrid model, which is a part of a pre-deployment predictive digital twin, is proposed using statistical techniques and machine learning models for accurate and fast forecasting in the design phase of a wind turbine. The statistical model captures the primary dynamics of the wind turbine power curve, while the machine learning model eliminates errors in the model. A logistic function is used as the statistical model for the regression problem, and an artificial neural network with two hidden layers is used for the error model. The model is trained with the dataset available online. The trained model is executed within the digital twin platform, which is built on Unity 3D, enabling the acquisition of both visual and analytical results. The proposed model exhibits 8 percent less root mean square error and 17 percent less mean absolute error compared to the pure statistical technique approach.

The SWFC (Smart Wind Farm Controller) is defined as an active controller for an entire wind farm (WF), consisting of several Wind Turbine Generators (WTG), which is devoted to optimizing the efficiency of the WF, through the establishment of a communication and information sharing connection between each one of the elements (WTGs) composing the WF.The system uses as input the collection of information from all sensorial devices available in each of the WTGs to utilize it to optimize the overall operation of the WF as a whole.This process brings the benefit of having a set of WTGs working towards the maximum performance of the whole WF. This control method is used instead of employing the classical control concept where each of the WTG operate in an egotistical fashion to render its own output higher without taking into account the maximum performance that the overall windfarm could have.A fully automatized SWFC is aimed to be the standard of operation, achieving the capability of self-regulating the necessary individual requirements and subsequent parameters to establish the required connection bridge between each element of the WF and outputting its highest performance.As a demonstrator of the SWFC and its WFC capabilities, wake steering has been chosen as the inaugural wind farm control concept for this project.Wakes provoked by upstream WTGs are one of the most prevalent issues during a WF lifetime, especially in closed spaced WFs, which decrease the performance of the WTGs. Both decreased energy production performance and increased loads due to higher turbulent effects of the wakes are a constant concern, which cause a detrimental effect on operation, maintenance and lifetime of the WTGs. Therefore, wake steering can be employed to purposively misalign certain WTGs, so that these harmful wakes can be diverted from downstream turbines.Although the deliberately misaligned WTG reduced its power output, due to its misaligned operation, the wind speed for the downstream turbines is increased, due to not being affected by the wakes. This trade-off has shown that the benefit for the downstream turbines surpasses the loss from the upstream turbines which are being misaligned, thus increasing the power throughput from the whole WF.A campaign was conducted during 6 months on a UK based windfarm, where 13 WTGs are closely spaced. As a first measure two of the WTGs have been equipped with wake steering capabilities using the SWFC as a basis.During these 6 months the park controller has been toggled ON and OFF so that a quantitative study could be performed, where the energy between ON and OFF situation could be clearly obtained.Results have shown that wake steering shows potential in increasing the uplift (Annual Energy Production) of the WF, since a total of 0.7% of AEP increase (of the whole windfarm) was achieved during this campaign, having only 2 WTGs equipped with the system.

Grid forming (GFM) inverters are expected to play a pivotal role in the successful integration of renewable energy facilities, as integration proves increasingly challenging due to concerns related to low short circuit power, sub-synchronous oscillations, and limited fault tolerance. The integration of these renewable facilities into the transmission network is often facilitated through the use of STATCOM technology. For STATCOM, fundamental grid-forming behavior has been developed based on inputs from ENTSO-E and technical requirements presented in the FNN guideline as a supplement to VDE-AR-N4131. GFM STATCOM technology has already been deployed and is in operation to facilitate the integration of large offshore wind facilities. With the addition of energy storage, the conventional STATCOM has evolved to an Enhanced STATCOM: a technical solution that caters to power system requirements on inertia challenges and active power support.The paper focuses on GFM STATCOM and GFM Enhanced STATCOM functionalities and how these functionalities can be utilized to increase the dynamic stability of renewable inverter-based resources (IBR). A brief overview of GFM STATCOM and GFM Enhanced STATCOM is provided, along with a description of the control structure. The paper elaborates on design considerations for the integration of renewable facilities to reinforce the grid strength and provide stabilizing services at the IBR connecting bus. Unique challenges related to weak grids and sub-synchronous oscillations are described. The capability to damp sub-synchronous oscillations, address phase angle instability, and provide grid voltage and frequency support through their active and reactive power capability is demonstrated via simulation in a software-in-the-loop environment inside a grid with a high penetration of IBR.

The decline of system inertia is a recognised consequence of the increased use of renewable energies that do not drive turbines and, therefore, do not include connected rotating masses. As a result, electrical energy systems are confronted with higher frequency gradients and significant frequency deviations that reduce the system's stability. Nevertheless, systems with a high share of renewables with all their specific characteristics must guarantee the same reliability as conventional power systems. Consequently, new control strategies and security mechanisms for inverter-based resources (IBR) must be developed to prevent substantial disruptions, like system splits with widespread blackouts. While current research focuses mainly on providing additional inertia, this paper aims to investigate which significance long-standing established frequency-dependent power control mechanisms with accelerated reaction times take to maintain system stability of the Continental European (CE) grid. Therefore, a simplified yet realistic model is developed and parametrised to be examined in an exemplary study case. Analysing the dynamic frequency deviation explicitly derivates the influences of providing additional inertia and accelerating frequency-dependent active power control. Thus, it is revealed that both measures are indispensable for future grids and that they must be coordinated to complement each other.

The rapid expansion of renewable generation capacities amplifies uncertainty in power system operation due to their inherent intermittency and challenges in accurate forecasting. Despite this, ensemble forecasts, which quantify weather forecast uncertainty, are not yet integrated into power system planning. This paper addresses the conditions under which utilizing this uncertainty is advantageous, focussing on how the available flexibility to balance forecast errors affects its value. To investigate this issue, a tool has been developed in which a day-ahead dispatch is cleared, and followed by a balancing which settles the discrepancy between dispatch and observation. A deterministic clearing is compared to a novel, stochastic clearing, in which the dispatch is optimised to minimise both day-ahead and anticipated balancing costs. The latter are estimated from a set of scenarios equivalent to ensemble forecast members. It was found that stochastic clearing outperforms deterministic clearing strongly in terms of electricity costs up to a threshold of upward flexible capacity. Due to grid constraints, this value could not be related to the distribution of forecast errors directly. This work has demonstrated how employing weather forecast uncertainty in power systems management may secure the supply, while relying not only on the addition of flexibility.

This work aims to create a model of the Nordic high voltage interconnected electricity system using publicly accessible data. The model includes 220, 300, and 400 kV AC lines, and the data is up to date until 2022. A proposed method allocates bidding zone level load and generation timeseries to the buses in the network. The resulting network consists of 441 buses, 553 lines, and 55 transformers. The model results are validated by comparing 16 cross-border flows from AC power flow modeling with physical flows reported by ENTSO-E. The error in flow is within 5% for 4 borders, around 9%-35% for 8 borders, and 45%-65% for 4 of the 16 borders. Suggestions for improvement include adjusting line impedances in Norway, dynamic line rating and modelling of reactive power compensation as switched shunts. The grid model created serves as an important starting point for the development of a publicly accessible power grid model for the Nordic system.

The integration of renewable hydrogen into industrial processes that demand a constant and stable hydrogen supply is challenging because of the inherent variability of renewable energy sources. To address this, energy storage systems can be used. However, an integrated design approach is necessary to decide installed capacities of energy storage systems, variable renewable energy supply (VRES) and electrolyser plant, to ensure the minimum levelized cost of hydrogen (LCOH) for the power-to-hydrogen plant.In this study, we conducted simulations of the entire hydrogen value chain using DNV’s proprietary software Renewables.Architect to determine the relative optimal sizes of VRES, battery energy storage system (BESS), electrolyser plant, and compressed hydrogen storage system (CHSS) capacities for minimum LCOH. Our simulated framework takes in a normalized renewable energy profile and solves an optimization problem to meet a continuous fixed hourly demand for hydrogen. Our simulations indicate that a design employing both BESS and CHSS yields the lowest levelized cost of hydrogen (LCOH). However, the guarantee of a continuous, uninterrupted hydrogen supply to industry comes at a cost penalty. The magnitude of this penalty is contingent upon the variability patterns of renewable power production and whether the hydrogen is stored locally onsite or sourced from a centralized hydrogen backbone.

Large, interconnected power systems are sensitive to electro-mechanical oscillations and several disturbances can be attributed to poor damping of the inherent oscillation modes of the system. To manage this issue any large synchronous generator is equipped with Power System Stabilizers. Large-scale PV and wind plants in the hundreds MW range are becoming more common in Europe, which requires robust solutions to ensure proper damping. Grid integration of inverter-based, renewable sources may have a deteriorating effect on the power system oscillation damping. Due to the shift towards renewable generation, the European Grid Code for generation enables the grid operators to enforce similar power oscillation damping requirements to inverter-based generation.Therefore, there is a substantial need to investigate the interactions of both synchronous and inverter-based power oscillation damping controls in power systems with a large share of renewable energy sources. The studies should be carried out for a set of various perturbations, such as short-circuit faults, generator tripping, topological changes in the grid, etc., considering the controller limitations and grid code requirements for both control systems of synchronous and renewable energy sources.Most of the renewable power plants are controlled by a central controller which in a large plant may communicate with 100+ individual inverters. Typically, inter-area oscillations may occur in the wide range of 0.1 to 1 Hz, and due to the inherent communication delays between the power plant controller and the individual units it may be a challenge to fulfill the oscillation damping and ensure that it is not deteriorating other control loops performance. Furthermore, due to the slow dynamics, there is a risk that the damping control may conflict with other control modes of the plant.This paper aims to present an optimization method to improve the power system oscillation damping considering the simultaneous operation of traditional control systems (AVR and PSS) of inertial sources and renewable sources-based power oscillation damping solutions. The study is focused on multi-objective optimal tuning of the control systems using NSGA-II evolutionary algorithm. Cost functions for the optimization procedure have been selected to improve power system transient stability and oscillation damping while maintaining the required quality of voltage regulation. The scope of work includes:

• implementation of the power system test models with a significant penetration of renewable energy sources,
• simulation studies of the behavior of the test system in the event of large disturbances,
• identification of control concepts for large-scale renewable plants that fulfill the oscillation damping requirements for a large PV plant without sacrificing other performance requirements implemented both in active and reactive power control loops (POD-P, POD-Q respectively),
• proposal for minimum requirements for the renewable plant controllers to qualify the damping control solution,
• development of evolutionary multi-objective optimization algorithm for the tuning of control systems of synchronous and inverter-based control systems,
• analysis of the performed simulation tests.

The integration of renewable power sources results in more converter-based generation in the grid. To enable a future stable power grid these converters, have to implement control software able to stabilize the power grid during different fault situations. This leads to grid codes for the grid-forming (GFM) control principle, superior to the today mostly used grid-following (GFL) controls. This paper proposes a test method for the identification of the converter’s control based on the performance after different disturbances (e.g. small voltage magnitude jump, voltage phase jump, etc.) without any detailed information from the controller itself. For this purpose, representative controls are implemented in a Power Hardware-in-the-Loop environment and compared with ideal constant current and voltage sources performance. The results demonstrate that system responses, such as for voltage magnitude jumps, can feasibly estimate control implementation and provide insights into voltage control loop usage. Conversely, voltage phase jumps reveal differences in the synchronization methods, with GFL unable to inject additional active phase jump power. These findings validate the proposed methodology for distinguishing between grid-following and grid-forming controllers based on measurements in a Power Hardware-in-the-Loop setting.

This paper explores the damping effect of a grid-forming (GFM) converter on the small-signal stability of a grid-following (GFL) converter during weak grid configurations. The paralleled operation of GFL and GFM converters is considered in this work. It reveals that the stabilising effect of the GFM converter is proportional with its active power production, and the theoretical upper limit to this stabilising effect is set by the steady-state stability limit of the GFM converter. Electromagnetic transient simulations verify the small-signal stability analysis and the theoretical findings.

This paper examines the limits and opportunities of various approaches for specifying and designing power oscillation damping (POD) controllers for power electronic interfaced resources (PEIR) to improve inter-area mode damping.While frequency domain requirements are increasingly recognized as essential for ensuring stability and robustness across a specified frequency range, further efforts are needed to achieve consensus among industry stakeholders regarding suitable compliance criteria and verification methods. At the same time, simulation benchmarks tailored to capture relevant dynamics have proven effective in assessing time-domain performance. Through controllability and observability analysis, the study highlights the significant dependence of the device under test’s (DUT) closed-loop response on the specific settings of the test system.

Grid state forecasting is a common practice at the transmission level for optimising the grid operation and implementing redispatch actions. However, transferring these methods to the distribution grids presents significant challenges, primarily due to the limited availability of measurement devices at this level. Previous research developed a modular grid state forecast for medium and low-voltage grids to address this issue. This approach seeks to optimise the use of limited measurement data and effectively predict imminent grid congestions. One of the critical challenges in this context is accurately forecasting load demand in local grid areas, as this must be done for a small number of customers. Their aggregate effect is not negligible and has a stochastic characteristic. Schedules provided by individual customers or prosumers can be utilised to enhance load forecasting accuracy in grid areas. These schedules are provided by software agents that forecast the stochastic load and its domestic energy systems using physical models. The resulting forecasts are integrated into the mathematical framework for determining the grid area load forecast. Simulation studies and field tests have demonstrated that prosumer real-time scheduling enhances grid area load forecasts and helps to improve the load distribution, especially during periods of high peak loads.

In recent years, the number of inverter-based resources (IBRs) connected to various power systems around the world has grown at an exponential rate, and this growth is expected to continue in the coming years. With the growing share of IBRs connected to a network, the synchronous machinery that has historically provided stabilizing responses to grid disturbances is being displaced, creating a demand for services from IBR. Successful operation of a power grid relies on different grid services at different time scales and locations in the form of energy, capacity, and essential reliability services (including stability services).There have been efforts to identify and categorize the services needed from IBRs in recent years. If IBRs are to be provided an incentive to deliver specific stability services to the grid, then it is important to quantify each service as well as to identify the performance desired as a part of such services, including the time frame, and in some cases the location, during which this performance is expected.In this work, the goal is to examine dynamic voltage, angle and frequency stability issues (i.e. system stability needs) with increasing levels of IBRs in a modeling/simulation framework to answer questions related to IBR’s impact on grid reliability and resilience. If there are negative impacts due to IBRs, then an aspect of this effort is to identify how these can be mitigated. If there are positive impacts how can the value created by IBRs be captured. Further, the operating conditions under which a high IBR grid would operate reliably is also to be evaluated.The intent is to develop a grid services framework and a set of quantifiable metrics associated with voltage, angle and frequency stability and further make use of time domain simulations to evaluate the objectives described above. Results from the analysis can help identify what services are needed in a system with high shares of IBR, how these services might be measured and how they could be procured, whether through interconnection requirements or potentially market/cost-based activities.

Investments in energy projects face various risks that increase the cost of capital. This is particularly challenging for renewable energy projects such as wind power, where most expenses are capital costs. However, risk management schemes, such as contracts for differences and power purchase agreements, have the potential to lower the cost of capital and support the acceleration of renewable energy investments in Europe. The impacts of the weighted average cost of capital (WACC) of wind power are explored within a highly flexible and integrated future power and energy system using the Backbone energy system modelling tool. The modelling setup is based on a soft-linking approach combining capacity expansion planning and production cost modelling stages, and the pan-European dataset used in the model covers multiple sectors and technologies. The results show how the WACC of wind power can have a significant impact on optimised capacities. Moreover, increasing the WACC from 3% to 11% led to a 37% increase in total system costs. On the other hand, the average profits of onshore wind power were typically the highest at a WACC level of 9%, due to a trade-off between the levelised cost of energy and the market value.

Historically, low voltage plan on power system were very frequent particularly in winter when the consumption was very high due to high transit of reactive power in transmission lines.Today, periods of high voltage constraints are dramatically increasing on transmission system (High voltage HV to Extra High Voltage EHV grid). These high voltage periods are caused by different evolutions of the power system: power flow decrease on transmission system network during the night or time of high solar and wind power generation connected to the distribution grid, burying of HV and EHV networks, and changes in the reactive power consumption of loads.In a first part this paper summarizes the reasons of high voltage stresses on transmission network. It gives operational, hardware and functional solutions to solve high voltage stress on transmission networks: such as capacitor bank management, inductance investments, control of Renewable Energy Sources (RES) power factor.Then a complete model of transmission and distribution system is build based on the CIGRE benchmark [CIG14] in the Powerfactory simulation tool to illustrate high voltage constraints and the benefits of the different solutions to solve them. The simulation period considered is one day with a time step of 10 minutes. This allows studying different operating conditions of the electrical system such as low or high consumption and low or high renewable energy generation. For the considered period, high voltage stresses occur during the night between 12 am and 6 am and between 8 pm and 12 am. The impact of operational, hardware and functional solutions is measured through various indicators such as technical efficiency in reducing EHV voltage stress and decreasing tap changers activation of EHV/HV power transformers. The cost of these solutions is estimated through an analysis of additional losses in power system. For example, controlling the power factor of RES connected to the HV network has shown a significant effect on reducing voltage on EHV nodes electrically close. The impacts of each solution on the operating points (active and reactive power diagram) of synchronous generators connected to the transmission network are also illustrated. The paper also highlights the impact of these episodes of high voltage, often combined with periods of low short-circuit power, on the stability of generators connected to the transmission network.The simulation analysis is further completed by on-site measurements taken on thermal generation sites in France. These measurements illustrate the consequences of the high voltage exploitation periods on the generators of EDF's thermal plants.References:[CIG14] « Benchmark Systems for Network Integration of Renewable and Distributed Energy Resources”, Task Force C6.04, April 20142011, IEEE Trondheim PowerTech « U/Q capability diagram of large Turbogenerators – contractual agreements, operation and e-monitoring tools », D. Souque, L. Chatonnet, E. Monnot, F. Duffeau, G. Morales, P. Morel

In high-proportion renewable energy power systems, renewable energy sources such as wind and photovoltaics become the main providers of electricity and power. Due to the stochastic variability of wind and solar resources, the uncertainty of wind power and photovoltaic output increases, resulting in the uncertainty of both supply and demand sides in high-proportion renewable energy power systems. This presents a significant difference from the unidirectional uncertainty of demand in traditional power systems.To ensure the safe and stable operation of high-proportion renewable energy power systems with uncertainty on both supply and demand sides, planning or operational strategies are needed to extract deterministic resources from highly uncertain power sources to meet uncertain load demands. The process of extracting deterministic resources from highly uncertain power sources is the process of planning or operational decision-making. The significant differences in uncertainty among wind and solar resources in different time and space and among different types of load response resources lead to changes in the uncertainty of supply and demand sides with changes in planning or operational strategies, indicating that the uncertainty on both supply and demand sides is decision-dependent.Compared to traditional power systems, while the uncertainty on the supply side significantly increases in high-proportion renewable energy power systems, the characteristics of uncertainty on both supply and demand sides also change significantly, posing a serious challenge to traditional supply-demand balance theories. To achieve supply-demand balance in high-proportion renewable energy power systems, understanding and quantifying the uncertainties on both supply and demand sides are essential.This paper focuses on the uncertainty of supply and demand sides in high-proportion renewable energy power systems, identifies the decision dependency of uncertainty on both supply and demand sides, reveals the mechanism of decision dependency in uncertainty on both supply and demand sides, proposes a quantitative representation method for decision-dependent uncertainty, and realizes optimization solutions using mathematical modeling methods and joint probability distribution theory. Simulation results demonstrate that the proposed method and model can quantitatively represent the decision-dependent uncertainty on both supply and demand sides in high-proportion renewable energy power systems, and the calculated results are highly consistent with actual situations, validating the rationality and correctness of the research methods.

The tests of 3 Heat Pumps (HP) from 3 European manufacturers were performed in controlled laboratory environment, over several days period each. Each HP implemented prototype control rules to modulate its power consumption proportionally to frequency and grid states instantaneous deviations. The outdoor unit is exposed to varying weather conditions—cold, average, and warm—while indoor unit aims to achieve different temperature settings to assess its performance in heating and cooling of a virtual building. The electrical supply to the unit is controlled to replicate typical distribution grid conditions, as in system splits and low-voltage scenarios (load/generation imbalances). Voltage amplitude and frequency are monitored alongside thermal variables like thermal power and hydraulic circuit supply temperature to the virtual building. These experiments’ showed that current HPs in the market implementing such control offer 1%/s modulation speed of rated power, insufficient during fast frequency deviations, and feature several off-nominal modes (e.g., defrosting/oil gathering/ramp-up) during which active power modulation is impractical. Nonetheless, reaction speed’s improvement areas clearly exist for products under development, gradual modulation of HP active power from local grid measurements is shown feasible and able to support grid in enhancing stability with negligible influence on user thermal services.

With the European Union targeting 450 GW of offshore wind capacity by 2050, current emphasis is on the development of offshore wind that not only generate power but also facilitate power transfer between nations using High Voltage Direct Current (HVDC) interconnections. Thus, the energy sector is moving towards AC offshore power islands, i.e., energy islands with power produced explicitly from large offshore wind farms, and HVDC interconnections, for improved control and better management of renewable generation's intermittency. However, even if the design of single-infeed offshore islands has been extensively studied in the past, the multi-infeed HVDC systems, which link multiple stations to adjacent AC buses, improve system connectivity but pose new control, operability, and design challenges. This shift underscores the importance of exploring these systems' control and operation, particularly during transient conditions, to harness their full potential-a topic which has not been adequately studied.Initially, the present work explores the operational challenges associated with multi-infeed AC offshore islands utilising HVDC interconnections, focusing specifically on transient stability during events such as AC and DC faults. It examines the stresses these events impose on the offshore network and assesses their effects on the onshore network, including potential power interruptions and the overall impact on power transfer to the grid. The study also examines the system's response and recovery post-fault, particularly when the capacity of units in grid-forming control mode is limited relative to the system's total capacity. The key findings of this analysis impose the need for in-depth investigation of converter control strategies and architectures, such as grid-forming and grid-following, during transient conditions. Additionally, they emphasise the importance of adapting control functions like Fault Ride Through (FRT) which is, already standardised in bulk grid-connected networks, but not yet for AC offshore islands.Addressing the aforementioned challenges, this paper proposes a control approach that orchestrates HVDC links and wind farms for effective fault management. In particular, it focuses on the determination of the control objectives for the FRT control, and the implementation of a coordinated control strategy utilised to dispatch the appropriate control setpoints (active/reactive power and control mode setpoints) for maintaining system operability during disturbances. The effectiveness of the proposed approach is validated through case studies on a realistic network with three HVDC links, capable of operating in both grid-forming and grid-following modes, and two wind farms in grid-following mode developed in PSCAD/EMTDC. The findings and proposed approach provide essential guidance for controlling and operating multi-infeed HVDC systems with AC offshore wind farm islands.

The energy system has evolved, transitioning towards a more distributed model with an increasing focus on inverter based resources (IBR). While this shift was propelled by policies, environmental concerns, and the advancement and affordability of renewable energy technologies, it also introduces challenges. These encompass ensuring grid stability and reliability despite variable energy sources, incorporating them into the current infrastructure, ensuring protection and safety in a more decentralized grid, and the complexities of energy storage and management. These challenges have been addressed through several approaches, including improved simulation strategies. For instance, generic models of IBRs are commonly used for planning decisions as they are less computationally demanding, and they facilitate the simulation when there is limited information about the system. Additionally, in specific applications, deploying lightweight models can be advantageous for simulating larger systems.IBR vendors frequently provide either simplified models or models containing a compiled version of the original controller source code. However, these models might not be available, or they may be too computationally demanding for real-time or large scale simulations. Thus, the studies usually rely on generic models that might not accurately represent the real system’s behavior. The proposed framework can be applied to enhance the fidelity of generic models without knowing much about its inner structure or in cases where models are not available or provided by vendors.The framework was implemented using a generic type-4 Wind Turbine model. Six PID control parameters across the active power, reactive power and RMS voltage control loops were estimated. These estimations exhibited, on average, less than a 5\% deviation from the original parameters. This outcome highlights the framework's potential in determining control parameters using both time domain and frequency domain data. The framework also offers valuable insights for optimizing control parameters in general. Although PSO was the chosen method, the framework's design allows for the integration of alternative optimization methods.The implementation of the framework was conducted with the automated tools available within the Typhoon HIL (THiL) software toolchain, and simulation data was used. As THiL specializes in real-time simulation, employing this toolchain ensures direct applicability to real-time setups, which facilitates the acquisition of data and the estimation of parameters from actual physical controllers. By employing PSO, each particle represents a simulation characterized by a specific set of parameters and a corresponding optimization cost. Thus, the parameter estimation is driven by the optimization process, which is based on the cost function. This framework is not limited to simulation data. It can use data from real-time simulation setups, such as Control Hardware-In-the-Loop, as well as lab or field data.

This paper explores the capability of grid-forming (GFM) offshore wind turbine generators (OF WTGs) to operate in an islanded mode and to re-synchronize with the grid. The transient stability of the WTG during the onset of the islanding and during re-synchronization is investigated for several islanding durations. Two novel re-synchronization methods are proposed for the GFM OF WTGs while maintaining their voltage source behaviour. The first of the proposed methods enables a smooth power ramp-up during the re-synchronization period following the end of islanding. It ensures transient power-angle stability of the GFM converter with the grid by fixing the islanded GFM converter's phase angle. The second proposed method relies on reconnection followed by a phase-match after a cycle. This method can elongate the overall islanding duration, increasing the power disruption duration; however, it still provides a simple yet reliable way to enable islanding clearance. A comparison between the two methods is also made to investigate their applicability, benefits, and drawbacks. For future power grids such as grid-forming offshore wind power plants (GFM OF WPPs) connected to HVDC grids, these methods provide a potential solution to withstand momentary and longer islanding without imposing severe mechanical and electrical stress on the WTG's mechanical and power-electronic equipment.

As the penetration of wind turbines and other inverter-based resources increase in the system, offline electromagnetic transient simulations (EMT) using black-box user-defined controls are becoming widely available and used in the industry for stability and grid compliance studies. Nonetheless, there are certain challenges when using offline EMT models for tasks that involve large system simulation, testing of protection and control devices (i.e., protection relays), or interoperability analysis of different OEMs and other equipment such as HVDC, STATCOM, etc, mainly posed by simulation time. In this sense, real-time EMT simulations are emerging as important solutions for such challenges, where traditionally, hardware-in-the-loop (HiL) is used, incorporating control and protection hardware and, more recently, real-time software-in-the-loop (RTSiL). This paper gives an overview of RTSiL, illustrating different alternative development approaches of real-time SiL models. The paper starts by defining the domain of applicability of offline EMT models, real-time SiL, and HiL, highlighting the importance and differences between each method. It then proceeds to explain the different methodologies available for black-boxing controls and simulating SiL in different real-time simulators and the advantages and disadvantages of different methods. The paper shows results for the implementation of the real-source code of Type IV offshore wind turbines and power plant control in both offline and online platforms, utilizing PSCAD and the SiL solutions from Real-Time Digital Simulator (RTDS) with GTSOC. The paper ends by discussing important differences between offline and online and the fact that RTSiL, as a new technology, still needs more maturation and verification.

AbstractAlong with the rapid development of utility-scale renewable energy (RE) generation, broadband oscillation incidents have occurred frequently, seriously threatening the safe and stable operation of the power systems. The impedance analysis method has become an effective approach for analysing and resolving broadband oscillation issues. Accurate impedance acquisition of RE power units is a prerequisite for oscillation analysis. The impedance measurement device can effectively obtain the real impedances of RE power units in operation, which is crucial for addressing current and future oscillation issues. This paper puts forward a novel impedance measurement device with the superiority of large power, wide measurement frequency range, and high measurement accuracy for RE power units. The novel impedance measurement scheme, topology and data decoupling algorithm are proposed to accurately obtain the impedances of RE power units ranging from 2Hz to 1000Hz. The impedance measurement device has been applied in several provinces of China to locate the oscillation causes and resolve the oscillation incidents.1 IntroductionThe global energy structure has undergone a significant transition towards green and low-carbon sources over the past two decades, resulting in a substantial increase in renewable energy (RE) generation. The power electronic devices are extensively used in RE generation and HVDC transmission, so the control performance of power electronic devices has an increasingly significant impact on the operating characteristics of power systems. The stability of the systems is gradually dominated by power electronic devices, rather than synchronous generators[1]. Therefore, new stability issues, that is broadband oscillation, have emerged, resulting in tripping off and equipment damage of RE power units and increase of wind and PV power curtailment.In 2009, a sustained oscillation incident at 20 Hz occurred at a wind power plant in Texas, United States, leading to the damage of crowbar circuits[2]. In 2014, oscillation incidents at 250Hz ~ 350Hz occurred in the Borwin1 project in the North Sea, Germany[3]. The filters exploded and thus the system experienced a 10-month outage and hundreds of millions of euros were lost. In 2015, over 100 oscillation incidents around 75 Hz occurred at wind power clusters in northwest China, and broadband oscillation incidents covering tens of Hz to thousands of Hz occurred in Zhangbei HVDC project in 2021, restricted the grid integration of RE power units[4].Recently, the impedance analysis method has become an effective method for analysing and addressing broadband oscillation issues based on small-signal stability analysis. Lots of researches have been carried out on the analytical impedance modelling of wind and photovoltaic (PV) power units[5,6] and static var generators (SVG)[7], which are used to reveal the oscillation mechanism of RE power plants connected to grid.However, the analytical impedance modelling relies on the specific control strategies and parameters, which are usually core techniques of the manufacturers and unknown to researches. Therefore, the simulation scanning method based on the control hardware in the loop (CHIL) is proposed to obtain the impedance curves of RE power units. However, due to the control delay, simulation step size and other non-ideal factors, the simulation scanning results are inaccurate, especially in the medium and high-frequency bands. The non-negligible errors will lead to the misjudgement of oscillation analysis conclusions.The on-site impedance measurement can obtain the actual impedance of RE power units in operation, and the impedance measurement device (IMD) is essential. A 380V/ 10kVA measurement platform is built to obtain the impedance of grid-connected inverters, which verifies the feasibility of impedance measurement[8]. In order to achieve the impedance measurement of MW-scale RE power units, a full-power conversion measurement scheme is proposed to measure the impedance of a 4 WM wind turbine[9]. For this scheme, the capacity of IMD should be much larger than that of the wind turbine, because the IMD serves as both the grid and disturbance source.Along with the sustainable development of RE generation, the capacity of a single RE power unit will be higher and higher, since the capacity of a single RE power unit has already exceeded 10MW for the onshore wind power and 18MW for the offshore wind power. The higher capacity requirement of IMD is desired. Besides, the measurement frequency range should cover 2Hz to over 1kHz, among which the broadband oscillation risks will occur. The wider frequency range brings a challenge to the existing measurement devices. Moreover, the interaction characteristics between RE power units with the grid are different under different grid scenarios, such as AC weak grid, classic HVDC and modular multilevel converter-based HVDC. The impedance characteristics presented by the RE power units vary with the grid scenarios, resulting in inaccurate measurement results when measured on site.Given there are three main challenges, higher capacity, wider frequency range and higher accuracy, for IMD, this paper proposes and develops a novel IMD in terms of a novel measurement scheme, topology and data processing algorithm. The developed IMD has been applied in the practical RE power plants to locate the oscillation causes and resolve the oscillation incidents.2. The Novel Techniques of IMDIn order to realize the demand of large capacity, wide frequency range and high accuracy for impedance measurement, this paper proposes a comprehensive solution, including the coupled plug-in measurement scheme, ripple suppression topology, and multi-frequency decoupled data processing algorithm.2.1 Coupled plug-in measurement schemeThe coupled plug-in measurement scheme is used to connect the IMD in series between a RE power unit and the power grid, as shown in Fig 1.The grid provides the grid-connected voltage for the RE power unit, while the IMD only provides the small-signal disturbance voltage. The output disturbance voltage by IMD is superimposed on the grid voltage through a three-phase coupled transformer. The power generated by the RE power unit is transmitted to the grid via the grid-side windings of the coupled transformer, as shown in Fig 2. In other words, the primary power does not flow into the power electronic converter of the IMD, but only flows through the transformer windings.The power electronic converter of the IMD only provides a little power to inject a small-signal disturbance voltage until a small-signal current response can be observed. Compared with the full-power conversion scheme, the impedance measurement is much more easily realized for a RE power unit with the capacity of over 10 MW by adopting the proposed coupled plug-in measurement scheme. The capacity of the IMD no longer needs to be greater than that of a RE power unit to be measured. Instead, the capacity of the IMD can be very small, less than 5% or less of that of the RE power unit. Therefore, the proposed measurement scheme enables the IMD to be a small horse that can pull a big cart.2.2 Ripple suppression topologyDue to the broadband oscillation risks ranging from several Hz to over 1 kHz, the small-signal disturbance voltage in a wide frequency range should be generated by the IMD. Therefore, the switching frequency should be several times greater than the highest frequency expected to be measured. On the other hand, the capacitor voltage ripple increases as the operation frequency decreases, which makes low-frequency impedance measurement difficult to carry out.In order to satisfy the broadband impedance measurement, a ripple suppression topology is proposed considering switching frequency and capacitor voltage ripple.Multiple inverters are cascaded on the AC side through the grid-side windings of the coupled transformers, as shown in Fig 3. The harmonics ripples at the integer multiples of switching frequency cancel each other out, so the equivalent switching frequency is improved by the level cascade. Beneficial from this, the upper limit of the measurement frequency can be extended to 1 kHz.The multiple inverters are connected in parallel on the DC side through three-phase H bridges, as shown in Fig 4. This arrangement achieves the cancellation of the main ripple components at second-order frequency and disturbance frequency in the DC capacitor voltage via three-phase parallel connection. The stable DC capacitor voltage ensures the waveform quality of the small-signal disturbance voltage and the stable operation of the IMD. Therefore, the lower limit of the measurement frequency can be reduced to 2Hz, resulting in a wider measurement frequency range.2.3 Multi-frequency decoupled data processing algorithmImpedance measurement suffers from frequency coupling phenomena, that is a small-signal perturbation voltage at one frequency excites current responses at two frequencies. The magnitudes of the responses are not only determined by the impedance of the RE power unit, but also affected by the impedances of the IMD and grid. The impedance obtained by the ratio of small-signal voltage and current at the AC port of a RE power unit cannot reflect the actual impedance characteristics, leading to inaccurate measurement results.To this end, a multi-frequency decoupling data processing algorithm is proposed. The relationship between the two frequencies of the current responses excited by a single-frequency voltage disturbance is determined. Therefore, a mirror mapping relationship is constructed by injecting another-frequency disturbance voltage. In this case, current responses with new magnitudes and phases at the same two frequencies will be produced. Combining with the two response relationships under the two disturbance injections, the coupling influences among the RE power unit, IMD and grid can be decoupled, as shown in Fig 5. Therefore, the real impedance of the RE power unit can be obtained.3 Evidence of IMD PerformancesBased on the proposed techniques in the measurement scheme, topology and data processing algorithm, an IMD for RE power units is developed by China Electric Power Research Institute (CEPRI), as shown in Fig 6. The parameters of the IMD are listed in Tab 1. The IMD is connected in series between the grid and the high-voltage side windings of the box transformer, which a RE power unit is connected to. Based on the proposed coupled plug-in scheme, the capacity of the IMD is only 1 MVA, but the IMD can measure the impedance of a RE power unit with the capacity of up to 16 MVA. The measurement frequency range covers from 2 Hz to 1000 Hz in 1 Hz step.In order to verify the performances of the developed IMD, the impedance of a 500 kVA PV inverter is measured by the IMD in Zhangbei Test Base. The on-site impedance measurement results and analytical calculation results based on impedance modelling are compared in Fig 7. As can be seen, the on-site measurement results are highly consistent with the analytical calculation results. The comparison results verify the measurement accuracy of the IMD.4 Engineering ApplicationsIn order to address the oscillation incidents in RE power plants, the on-site impedance measurements are carried out in wind power plants and PV power plants.4.1 Impedance measurement of the wind power unitThere are a large number of outdated wind power units in the eastern regions of Inner Mongolia, China. The proportion of RE plants containing outdated wind power units reaches 56%, and the installed capacity of the outdated wind power units reaches 38%. Due to the loss of the source codes in these RE power unis, it is hard to obtain their impedances and carry out the oscillation risk assessment for the RE power units.In order to address this issue, the IMD has been used to acquire the impedances of the outdated wind power units on August 6, 2023. The developed IMD is mobile and can be transported to the RE power plants. Then, the IMD is connected between the grid and the outdated wind power unit. After the perturbation voltage is injected on the grid voltage, the currents of the wind power unit are recorded. Based on the proposed data processing algorithm, both the positive-sequence and negative-sequence impedances of the wind power unit from 2Hz to 1000 Hz can be obtained. Fig 8 shows the on-site impedance measurement results of a doubly fed induction generator (DFIG) with the capacity of 0.5 MW.With the IMD, the impedance measurements have been carried out since August 2023 to obtain the on-site impedance data of the outdated wind power units. Based on the on-site impedance measurement results, the oscillation risks can be assessed and resolved for the wind power clusters in the eastern regions of Inner Mongolia, China.4.2 Oscillation Mitigation of the PV power plantAs of June 2023, there are three wind power plants with an installed capacity of 400MW and five PV power stations with an installed capacity of 820MW at a 330 kV substation in Ningxia, China. Several oscillation incidents have been recorded in the wind and PV power plants. The recorded voltages and currents show that the 69 Hz oscillation has occurred in the RE power plants, as shown in Fig 9. It is urgent to locate the oscillation cause and resolve the oscillation issue.The impedance measurement tests were carried out by the IMD on August 29, 2023. Fig 10 shows positive-sequence impedance curves of a PV power unit. As can be seen, the curves of the impedance magnitudes of both the PV power unit and grid intersect at 69Hz. The impedance of the PV power unit presents negative damping around 69Hz, and the impedance phase difference between the PV power unit and grid is close to 180°. Correspondingly, the stability margin of the system is only 6.8°. Consequently, there will be an oscillation risk at 69 Hz when the PV power unit is connected to the system.Since the oscillation risk is introduced by the negative damping of the PV power unit, the optimized control strategy is developed to reshape the impedance characteristics for the oscillation mitigation. After the optimized control strategy is downloaded to the on-site controller of the PV power unit, the on-site impedance measurement tests have been carried out again. The measurement results are shown in Fig 11. After impedance reshaped, the stability margin at 65Hz is improved to 65.5°. Therefore, the oscillation issue has been resolved.5 ConclusionTo meet the requirements of broadband oscillation analysis in the utility-scale RE grid-integration systems, this paper proposes a novel measurement scheme, topology and data decoupling algorithm, and develops an IMD for RE power units. Based on the proposed techniques, broadband impedance, ranging from 2 Hz to 1000 Hz, of a RE power unit with the capacity of up to 16MVA can be measured. The coupled influences of the different grid scenarios can be eliminated, so the accurate impedance of a RE power unit can be obtained. Then, the oscillation cause can be located and mitigation strategy can be proposed. The developed IMD has been applied in multiple RE power plants, effectively analysing and resolving practical oscillation issues.

Future power systems may rely only on inverter-based generation. The amount of conventional power plants in the grid will decrease. Renewable generation sources must replace the system services previously provided by conventional power plants. In addition, the large generating capacity of conventional power plants needs to be replaced. Offshore wind energy offers a suitable alternative for substituting generation capacity and providing system services. Typically, offshore wind farms are connected to the onshore transmission grid via High-Voltage Direct Current (HVDC) transmission. The Modular Multilevel Converter (MMC) is the predominant converter topology for HVDC transmission.This paper focuses on providing ancillary services from an HVDC-connected offshore wind power plant. A symmetrical monopole HVDC link with MMCs is used to connect the offshore wind power plant. The proposed operational strategy utilizes mainly the rotational energy stored in the wind turbines (WTs) to respond to onshore grid events. The operational strategy further minimizes the depletion of the energy stored in the MMCs and the DC link of the WTs during these onshore grid events. In addition, this operational strategy does not rely on a communication link.The paper describes the system under investigation first, followed by the modeling and control of the HVDC link. A new control approach that differs from the state-of-the-art HVDC-link control approaches is presented. The WTs are modeled using both an electrical and mechanical model. However, the wind turbines' modeling is not within this paper's scope. The overall system is a full Grid-Forming (GFM) system. All converters in the system have implemented a GFM control on their AC grid side. Each converter's electrical behavior at the terminals and specific control goals are described in detail.Example simulations highlight the implemented control strategies using the rotational energy stored in the WTs to respond to onshore grid events. Electromagnetic Transient (EMT) simulations are carried out in PSCAD. Additional simulation scenarios show the GFM capabilities of the overall system as well as the ability to provide ancillary services. Furthermore, the Fault-Ride-Through (FRT) capabilities for symmetrical and unsymmetrical faults are shown.The introduced operational strategy avoids using the stored energy in the MMCs and wind turbine DC-links to respond to onshore grid events but instead utilizes the rotational energy stored in the WTs. Consequently, a larger virtual inertia constant can be provided by the onshore MMCs GFM control. Besides, the overall system can be operated like a conventional power plant by externally setting a power reference for the GFM control of the onshore MMC. Furthermore, the overall system shows the capability to ride through onshore grid faults without the use of a chopper in the onshore MMC. Additionally, the operational strategy demonstrates the ability to provide ancillary services and GFM capabilities to contribute to a safe and reliable future power system.

Grid-forming converters have been identified as a crucial element in enabling the stable operation of future power grids with a significant proportion of converter-based resources. As grid-forming assets are planned for installation at all voltage levels, it will be necessary to operate multiple devices in parallel without undesirable interactions. Consequently, it is essential to conduct studies to assess the interoperability of grid-forming converters, with the aim of identifying critical scenarios and to establish procedures aimed at preventing unwanted interactions. This experimental study investigates the interoperability of two independently designed grid-forming converters, focusing on parallel operation within a small island grid. The results demonstrate that the two converters can operate together effectively. This is contingent upon maintaining both converters' operating points below their respective limits and ensuring sufficient decoupling. Furthermore, the conducted experiments reveal significant interaction between the converters, particularly when operating in current-limiting mode, underscoring the necessity for coordinated control strategies. The findings highlight both the potential and challenges of integrating grid-forming converters from different manufacturers, paving the way for further research on their functionality in diverse operational scenarios.

For harmonic assessment in accordance with the current procedure of the German technical connection guidelines, harmonic currents at the connection point of a power generation facility are determined based only on type measurements in the lab or field. Various studies have shown that harmonic emissions are not only dependent on the power plant itself (source-driven harmonics), but can also be influenced by grid impedance, particularly in cases in which resonances occur (resonance-based harmonics). In the presence of resonance conditions between the plant impedance and the grid impedance, harmonic currents can be amplified. Consequently, source-driven harmonics and resonance-based harmonics should be distinguished. Laboratory measurements during type testing do not consider the actual impedance conditions that can occur at the grid connection point and, therefore, neglect the resonance-based harmonics. In addition, the conditions in the laboratory or in the field (voltage distortion and grid impedance) have an impact on the measurements of the harmonics.In the working group on harmonic models of the FGW new approaches are being developed to improve the current procedure. One of these approaches is based on a validated Thévenin equivalent or Norton equivalent model of the device under test. This model represents the internal harmonic sources as well as the frequency-dependent impedance. The proposed approach evaluates the source-driven harmonics independently of the resonance-based harmonics.Using a validated Thévenin or Norton equivalent model, the maximum physically possible source-driven harmonic currents of a generating unit can be determined using the internal sources. For the evaluation of harmonic currents of the unit, new limits must be defined. The definition of the limits at unit level must be based on reasonable assumptions for superimposing the harmonics of the individual devices to prevent excessively large emissions at the power generation facility level, without the need to assess the source-driven harmonics at the facility level.A comprehensive power plant model is created for resonance-driven emissions based on the plant topology, including cables and transformers. This allows detailed assessment of source-driven harmonics at plant level against nowadays existing limits as well. Together with the grid impedance at the grid connection point while considering its time variation, resonance points can be detected and evaluated in addition. The damping of identified resonance points must be analysed. If the damping is insufficient, the power plant fails the assessment, unless appropriate countermeasures are taken.Various studies in the field have shown that impedance-based methods for analysing grid interactions can achieve very good results. All parameters necessary to determine the frequency-dependent characteristics of a power generation unit can be determined through measurements or simulations based on a black box model, no simulation models or controller structures need to be disclosed for this approach.

With the recent influence of policies such as carbon neutrality and net-zero, there is an increasing demand for renewable energy sources. Type-4 Wind turbine generators (WTGs) are prime examples of renewable energy sources. However, the increase in WTGs can potentially worsen the frequency stability of the power system. This is because WTGs, which are connected to the power system via converters, are characterized as asynchronous generators. At the same time, WTGs have the potential to improve frequency stability with better control. For example, WTGs with deload control, i.e. where the active power output is regulated at a level below the maximum power point (MPPT) during normal conditions, also hold promise for improving the frequency stability of the power system, the deload control strategy enables WTGs to supply even more power than the temporary maximum power point tracking level additional power during emergencies. It is also noteworthy that WTGs can supply additional power to the system more quickly than synchronous generators. As a result, the WTGs can provide a fast frequency response that synchronous generators cannot provide due to their governor response time. However, in order to implement such a control, it's important to consider the rotational speed of the wind turbine blades. If the rotational speed of the wind turbine blades falls below a certain threshold, the WTGs can stall and stop operating. Taking into account these factors, we propose an active power control method that considers both deload control and wind turbine rotational speed. The proposed method is developed using an original WTG model based on the WECC's generic model.One of the key features of the proposed method is to control the reference active power value within the operating range of the wind turbine. Therefore, the proposed method can prevent the WTGs from stalling. These aforementioned characteristics were verified by numerical simulations. Specifically, we introduced Type-4 WTGs with the proposed method into the EAST10 power system model of the Institute of Electrical Engineers of Japan. In addition, part of the generator was tripped to verify the effectiveness of the Type-4 WTGs with the proposed method in improving frequency stability. After the generator trip causing a frequency drop, Type-4 WTGs with the proposed method supply additional active power to the power system. Consequently, it has been confirmed that the power system's nadir frequency has improved. Furthermore, it was confirmed that even when Type-4 WTGs have a small deload ratio, those equipped with the proposed method remain stable and connected to the power system without stalling, thus ensuring a consistent supply of active power to the system.

Additional reactive current injection is often required in the grid codes from converter-connected power plants to mitigate overvoltages and to increase residual voltages during faults. This paper studies the effect of additional inductive current injection on overvoltages using electromagnetic transient (EMT) simulations with manufacturer-specific wind power plant (WPP) models. The objective of the study is to propose additional inductive current injection and overvoltage ride-through (OVRT) requirements for the next Finnish grid code revision and to study whether additional capacitive current injection requirement can cause overvoltages after fault clearing. The study is conducted by using two grid models: 1) a simple model consisting of few WPP models and a meshed network and 2) a large-scale model representing the western part of the Finnish transmission system. The study revealed that fault ride-through (FRT) mode of the WPPs contributes to overvoltages after fault clearing, due to the pre-disturbance reactive power produced by the wind turbines following voltage recovery. Utilizing additional inductive current injection significantly reduced the overvoltages. Furthermore, additional capacitive current injection magnitude had an insignificant effect on the overvoltage occurring after fault clearing. Based on the results, additional inductive current injection and OVRT requirements were proposed for the Finnish grid code revision.

The transition towards net-zero energy systems requires large-scale integration of wind and solar generation. Recent literature suggests that energy storage, transmission and sector coupling are important flexibility solutions to manage the inherent variability in weather dependent generation sources. Due to the uncertainty in projecting the role of hydrogen in the energy systems towards 2050, there is uncertainty in the role of hydrogen assets in providing the flexibility. The literature highlights hydrogen storage and hydrogen pipelines as important sources of flexibility, with storage enabling flexibility in the operation of electrolysers and pipelines used to transfer hydrogen from where it’s produced to where the demand is. However, the literature does not fully agree on how competitive these solutions are compared to flexibility from the power system side (e.g., transmission lines, pumped hydro) and from the heat sector (heat storage to enable flexible heat production). There is also uncertainty in whether placing hydrogen infrastructure investments onshore or offshore makes most sense, which is a topical question as interest in offshore energy hubs grows. This paper studies integrated energy system model pathways towards 2050 to understand the role of hydrogen storage and pipelines in different scenarios, focusing on the Central and Northern Europe.The analyses are carried out using the Balmorel energy system model. Assumptions on the electrification of the heat and transport sectors and the demand of hydrogen in the hard-to-abate energy sectors (such as industry and maritime traffic) specify scenario with high level of sector coupling. As the sectors are linked in the Balmorel model, the flexibility sources from the different sectors are in competition. The optimal mixtures of the flexibility sources are compared between the sectors, utilising the model run carried out in this paper but also comparing to existing literature to achieve a wider range of scenarios for the comparison. The focus is on what sectors seem to be the most important flexibility sources, how cost uncertainties can impact the results and how optimal onshore vs. offshore hydrogen infrastructure appears under different assumptions.The results indicate that while hydrogen pipelines have a role in highly sector coupled scenarios, electric transmission lines are important in all scenarios. We do not see hydrogen transmission expansion replacing electric transmission expansion. However, the role of hydrogen pipelines varies between different studies, which can be seen natural considering the uncertainties related to the overall role and cost of hydrogen infrastructure in the energy system towards 2050. Hydrogen and heat storage are important flexibility solutions, enabling demand flexibility related to heating and the utilisation of electrolysers; this solution of course assumes that economic use of electrolyser can be achieved with somewhat lower full load hours. Smart charging of electric vehicles is an important flexibility source, whereas the role of dedicated electric batteries is seen limited; however, this role also varies between different studies.

The power system is becoming increasingly volatile due to the rise of variable renewables and electrification of demand. Rather than controlling a small number of large-scale generators tuned to demand, multiple smaller generators and large parts of the demand itself need to be controlled. Many kinds of control algorithms will emerge in parts of the power system that will affect each other, possibly in undesirable ways. This paper presents a case study demonstrating the unintended negative effect that home batteries can have on the grid. The simulations consist of households with a rooftop photovoltaic (PV) system and home battery storage with the goals of maximizing the self-consumption of energy and minimizing the electricity bill. The results of the simulations show that while the goal of the home battery was to absorb the generated PV power and use it to later supply the demands of the household, thus limiting voltage rise and reverse power flows to the grid, in practise the opposite occurred. Triggered by electricity prices, the simultaneous battery charging in winter and simultaneous discharging in summer, even though for shorter periods, resulted in more severe overloading and power reversal than when no batteries were used.

The integration of renewable energy sources in power systems rises the incidence of dangerous frequency dynamics. This paper addresses these challenges by proposing a virtual inertia control system designed based on a previously developed inertia estima- tion tool. The tool enables real-time assessment of system inertia, and the control system, emulating traditional rotating machines, compensates for the lost inertia. The proposed solution is tested in the 4-machine system model of São Vicente island, Cape Verde, yielding promising results. The experiments validate the efficacy of the control system in mitigating the impact of reduced inertia on grid stability during regular operation, showcasing its practical applicability in real-world scenarios. This research con- tributes to addressing the challenges associated with renewable energy integration and provides a tangible and scalable solution for maintaining grid stability in the face of diminishing inertia

The share of solar and wind power in Korea has been steadily increasing, and this trend is expected to continue. As solar and wind power increase, they displace the production of conventional power sources, leading to a reduction in generation costs. However, this also entails additional costs other than generation costs to cope with output variability and uncertainty due to weather conditions.It is therefore essential to calculate these additional costs, known as integration costs, in order to quantitatively assess the cost-saving effects of solar and wind power. However, research on estimating integration costs for solar and wind power in Korea has been very limited.Therefore, we calculated the integration costs of solar and wind power for 2030 and 2036 on a scenario basis using an integration cost estimation method studied at KU Leuven University in Belgium in 2016, taking into account the conditions of Korea's power system. The data for the integration cost calculation was based on information provided in the government's electricity supply plan announced last year.Integration costs for 2030 were calculated to range from $0.9 to $11.3/MWh for solar, $5.4 to $12.2/MWh for onshore wind, and $5.3 to $9.6/MWh for offshore wind. For 2036, integration costs were calculated to range from $4.1 to $16.4/MWh for solar, $8.5 to $18.1/MWh for onshore wind and $8.2 to $15.4/MWh for offshore wind.These results not only indicate that integration costs vary according to the characteristics of the energy sources, but also provide an implication for quantifying the additional costs incurred due to increased system variability and uncertainty resulting from the expansion of solar and wind power considering the future conditions of the power system in Korea.

Renewable energy is one of the most important carbon-free resources for energy transition and net-zero goal. To reduce carbon emission, Korea has planned to supply variable renewable energy focusing on photovoltaic and wind. However, solar or wind energy is inherently resources with high variability and uncertainty depending on weather conditions such as solar radiation and wind speed. Korea has an island system without an electrical interconnection with neighbouring grids, which is expected to have more difficulties with issues about renewable energy compared to other countries. Accordingly, it is necessary to prepare comprehensive countermeasures for expanding renewable energy, in order to stably integrate renewable energy into the power system. Since Korea has considered energy storage system as a key technology and established a plan to expand it, it is important to arrange an optimal plan for energy storage system. In this paper, a study was conducted to estimate the optimal ESS requirement for 2030 and 2036 as target years. We created the renewable energy generation outputs through random sampling by utilizing Monte Carlo simulation and other methods, and forecasted the future renewable energy generation output by region. By analysing the 5-minute Net Load and Net Load Variability data, seven points were selected with the highest possibility of the optimal ESS requirement. We checked the curtailment results through a 5-minute simulation with PLEXOS as the span for the whole day of the points. The requirement was calculated as the amount of ESS when the curtailments disappear by increasing the ESS. This result can be considered as the optimal ESS requirement to respond to the renewable energy variability.

・general scopeOffshore wind turbines are often located far from the demand area, where DC transmission is more advantageous than AC in terms of losses. For this reason, DC transmission models are being considered for offshore wind power applications around the world. In addition, the recent introduction of large numbers of VRE (Variable Renewable Energy) into the grid has led to a relative reduction in the number of synchronous generators connected, which has led to issues such as reduced inertia. For this reason, studies are underway to add frequency regulation by the DC transmission connected to the VRE.In the DC transmission configuration of offshore wind turbines, when a generator stops due to a ground fault or similar event, a part of generation is momentarily interrupted, which can result in transient DC voltage fluctuations. No previous studies have investigated the effect of VRE output change on AC receiving side network frequency fluctuation relating to inertia in such a situation.・relevance of the subject matterIn order to clarify the effect of DC transmission on frequency support at the receiving AC system that contributes to inertial response under the conditions described above, this study examines how voltage fluctuations in the DC transmission section affect frequency fluctuation suppression by droop control. The effects are compared between GFL and GFM inverters.・methods usedFor this study, digital simulations were carried out first. Later, a miniaturized MMC HVDC was built and incorporated to an analogue simulator.　The rated capacity of the bridge is 300 MVA, and it connected to 275 kV on the receiving bulk power system.A DC transmission model with a two-terminal configuration is used as the model system and two types of controls are implemented at the receiving converter: the one is a GFL type and the other is a GFM type at the receiving side. A droop control is added to the receiving converter control as for frequency control. The combination of GFM and the droop control gives better frequency support at the receiving ac system.・main results obtainedExperimental results show that the GFL type converter fluctuates the active power output to the AC system with the same polarity as the change in DC voltage because the constant current control works and the current does not change even if the DC voltage fluctuates up or down. It has been confirmed that even if the frequency is reduced in cases where the DC voltage decreases, the frequency fluctuation suppression effect is reduced because the active power output is reduced by the reduction in the DC voltage. On the other hand, for the GFM converter, it was confirmed that the active power output to the AC system also fluctuates up and down rerating to the capacitor voltage fluctuates up and down, but the frequency fluctuation suppression effect is not affected, it is recognized it is advantage of the GFM converter.・major conclusions drawnIn the present study, the effect of varying the direct current (DC) voltage on the frequency sway suppression effect was compared between GFM and GFL.The GFL converter type in DC transmission may reduce the frequency fluctuation suppression effect. On the other hand, the GFM converter type may not affect the frequency fluctuation suppression effect.

HVDC transmission has become prominent for offshore wind integration. While today’s systems are built as monopolar point-to point links, several network development plans foresee to transition to 2GW bipolar multi-terminal systems, radially connected on the offshore DC-side. To increase immediate post-fault redundancy, it is discussed to couple the P and N pole of the bipolar system on the offshore AC-side, to enable an active power transfer between the poles. This power transfer can be achieved via a droop control of the offshore converters. Alternatively, the grid forming control (GFM) can be shifted to the wind turbine generators (WTGs) in the offshore wind power plant. This paper therefore compares different operational modes for immediate DC post-fault power transfer by means of EMT simulation. The focus lies on the load flow control via the AC coupling, while maintaining stable system operation. It is shown that GFM WTGs are capable of providing a faster load flow redistribution than the droop control. Furthermore, the post-fault load flow redistribution even works when the HVDC system is connected to a block load, with minor impact on the WTGs, requiring a DC-chopper activation for a few milliseconds for high and low-wind situations.

The decrease in physical inertia within AC grids may lead to more serious frequency deviations caused by power imbalances. To address these challenges attention has been paid to the potential of converter-connected resources to reduce frequency deviations. Since grid development plans aim to integrate a large capacity of hydrogen electrolyzer plants (HE) into the power grid, the analysis should be extended to include the ability of these loads to reduce frequency deviations.This paper performs a systematic review to evaluate the state-of-research on the potential of large-scale HE to reduce the rate-of-change-of-frequency and maximum frequency deviation. Current literature states a high potential of HE to counteract frequency deviation. Furthermore, various control approaches for delivering frequency ancillary services have been investigated. However, the paper identifies a research gap concerning applicability of the control approaches to large-scale HE considering resulting fluctuation in the flow rate of hydrogen production.

In consequence of the accelerated expansion of wind power in China, power systems comprising a significant proportion of wind energy have been established in the "Three North Regions." It is an inevitable consequence that this will result in a reduction in the synchronous support capacity, which in turn will jeopardise the safe and stable operation of the local power system. In this context, grid forming control has emerged as an effective solution, offering grid support capabilities comparable to those of synchronous machines. Accordingly, a small signal model for grid-forming wind turbines is initially constructed. Thereafter, the broadband dynamic characteristics of grid-following/grid-forming control wind turbines are analysed based on eigenmode. Subsequently, the stability and active support performance of grid-following/grid-forming control wind turbines are elucidated through root locus and amplitude-frequency characteristic curves. Ultimately, the simulation, hardware-in-the-loop test, and field test are provided to demonstrate the transient and steady-state characteristics.

This paper compares the aggregated model of a large-scale hydrogen electrolyzer plant, represented by a single electrolysis stack and converter system, to the detailed representation of the individual electrolyzer modules, each consisting of a converter system and electrolysis stack. The purpose of this study is to determine in which scenarios the aggregated model of a hydrogen electrolyzer plant can provide sufficient results for grid integration studies, specifically frequency control and small-signal studies. The response of the aggregated and detailed models to frequency events is evaluated through real-time electromagnetic transient (EMT) simulations. Impedance analysis is carried out to compare the plants small-signal characteristics over a broad frequency range. The models of the electrolysis stacks are parameterized using data obtained from a real 10 MW PEM electrolyzer plant. It is found that the aggregated model provides accurate response to frequency events under the assumption of an even set-point profile of the electrolyzer modules. The small-signal characteristics are accurately represented by the aggregated model for high frequencies, but can differ in the subsynchronous frequency range. The study is useful to determine the necessary modelling detail for frequency control and small-signal studies of large-scale hydrogen electrolyzer plants.

This paper presents a comprehensive analysis of power quality measurement for grid-connected inverter based resource plants in the Western Region of India. An overview of the power quality assessment carried out in Western Region as mandated by the technical standards for connectivity regulation in India is introduced in the paper. The paper also talks about the process followed by the testing agencies for carrying out the field measurement of power quality (viz. harmonics in current and voltage, flicker and DC current injection). The characteristics of harmonics observed in various cases by the testing agencies differed from each other like higher harmonic content in only current waveform or only in voltage and the combined presence of both current and voltage harmonics distortions varying based on type of grid interconnection, generation and technology, the paper highlights the interpretation of these results. Various aspects which need to be taken care during measurement period, like the generation level of the plant, occurrence of fault/disturbances (if any) in the system affecting measurement results etc. are also briefly covered. The paper makes an investigative approach including both measurement based and simulation based results, to ascertain the harmonic sources for highlighting the power quality issues.

In the recent years the Finnish power system has experienced a rapid increase of converter connected production, especially wind power. Large part of the wind power plants is located on the western coast of Finland, creating a converter dominated area where special consideration to the converter driven stability phenomena must be considered also in outage planning. This paper presents the experiences of Finnish transmission system operator (Fingrid) in using large-scale electromagnetic transient (EMT) simulations as part of the outage planning.Due to the large share of wind power, the outages in the 400 kV main transmission network in the western coast area can drop the equivalent short circuit ratio (ESCR) in the area significantly. During the outage the N-1 principle must also be fulfilled, meaning that the system after a contingency must also be stable. In these scenarios, the ESCR values can be exceptionally low in large areas, thus requiring the use of different methods to manage the stability.The paper will discuss the use of ESCR screening method, need for EMT simulations and the feasibility of RMS dynamic simulation. In one case, the RMS dynamic simulation model replicated a converter driven instability event, but in the other case, the instability is observed only with the EMT model. It was concluded that when the ESCR values were sufficiently low, the RMS dynamic simulation cannot replicate the real behavior of the converter connected production. However, the EMT simulation is significantly more time consuming compared to RMS dynamic simulation. Therefore, Fingrid has developed a screening program that automatically calculates the ESCR values for the scenarios after different contingencies to help in identifying when EMT simulations are required.The paper will present the process of managing the converter driven stability issues in outage planning. The studied scenarios are first identified with use of ESCR screening method, and additional studies are performed to find optimal mitigation method if risks are identified. The different operational methods can be used to improve the stability of the scenarios, such as changing the control modes or by limiting the maximum active power output of the wind farms. The EMT model for each planned outage is built by converting an RMS model of the outage into an EMT model using a commercial conversion tool. The used EMT simulation model currently includes the whole 400 kV network and large part of the western coast 110 kV network, with total of over 800 busses and over 80 wind farm models.Finally, the paper will present how Fingrid is enhancing the stability of the system and enabling high penetration of converter connected production with new investments on grid supporting devices, grid code requirements and improved simulation capabilities.

ScopeDue to the elimination of conventional power plants, congestions will have to be managed by a large number of DERs across different voltage levels in the future. An example of this is the Redispatch 2.0 process introduced in Germany in 2021, where all DERs with a rated power Sr>100 kW must participate in congestion management. This raises the question of how to manage a large number of DERs across different voltage levels and grid operators. One way of dealing with this task is to aggregate the feasible active and reactive power operating ranges for each grid level at the interconnection point to the superordinate grid with the aim of representing the subordinate grid as a ‘controllable generation unit’ with a grid-specific capability chart. This tool is called Feasible Operating Regions (FORs). In the FOR calculation both, limits of DER and limits of the network, are considered.FORs are highly dependent on the grid topology and are therefore particularly difficult to estimate at the HV level. Both, the meshing of the HV and EHV levels have a strong influence on the resulting FOR. This paper focuses on the influence of the superordinate grid on the subordinate grid and aims to answer two questions: What is the influence of the superordinate grid on the FOR of the subordinate grid? And how can the accuracy of the calculation be increased, assuming that the subordinate network operator has little information about the superordinate network?MethodIn the first part of the paper, the influence of power flow fluctuations and topology changes on the FOR of the subordinate is quantified in a synthetic EHV/HV-Grid with three interconnections by a Monte-Carlo-Approach. The second part of the paper deals with the improvement of the accuracy of the calculation of FORs by replicating the behaviour of the superordinate grid with only few data. Three concepts are compared with the results of an overall EHV/HV-model: The superordinate grid representation as a single slack bus, which is the current literature model, the representation as a distributed slack bus and the representation as an Extended-Ward equivalent.ResultsThe first part of the paper shows that the FORs of the HV grid are highly sensitive to power flow and topology changes in the superordinate EHV grid. It is thus concluded that an accurate calculation of the FOR requires the superordinate network to be modelled adequately.The second part of the paper builds on these results and compares three different grid replication techniques (Single Slack, Distributed Slack, Extended-Ward) as a representation of the transmission grid. It is shown that the modelling by a distributed slack and an Extended-Ward equivalent are sufficient ways to increase the accuracy while using only few data. It is also shown that the most used representation in the FOR calculation in the TSO/DSO-literature – the single slack bus representation- leads to high deviations in comparison to the FOR calculation in the overall EHV/HV model. Therefore, this model is not suitable for the FOR calculation.

The high rates at which hydrogen electrolysers will need to be installed threaten the electricity grid's stability if specific grid connection requirements are not fulfilled in an analogue manner to generation plants. However, their flexibility may offer significant potential for covering electricity system demands. In addition, the transformation to a climate-neutral electricity grid leads to structural changes in providing system stability demands, such as inertia. This poses the research question: what systemic potential do electrolysers have to cover the inertia demand, and how does their grid-forming control affect regular operation? The systemic potential depends on the total installed electrolysis capacity and the realisable synthetic inertia of the plant. The latter, in turn, is influenced by technology-specific and plant-specific dynamics, partial load capability, overload capability, duration of generation, and the market share of capable plants and electrolysis types. Electrolysers offer a significant theoretical potential, particularly in the northern German federal states. In addition, inertia power is only generated at high-frequency gradients. Hence, the inertia provision in the European grid is less than 1 % for a significant part of the year, depending on the synthetic inertia constant. Suppose a high dynamic in the inertia time range can be realised with regard to the plant design. In that case, electrolysers can contribute significantly to grid stability while having a low impact on normal operation.

Grid-forming control concepts are often based on the dynamic behavior of synchronous generators. While this approach offers beneficial properties from a power system stability perspective, such as inertia provision, it also introduces negative aspects associated with synchronous generator-dominated grids, such as a tendency to participate in power system oscillations. However, converter-based power oscillation damping countermeasures are often structurally inspired by countermeasures originally developed for synchronous generators - although utilizing the fast controllability and additional capabilities of converter control. The effects of these countermeasures on the behavior of converter-based systems are not always immediately apparent but can significantly impact the converter's performance if not properly addressed. This paper demonstrates these unintended effects through simulations and system theory analysis, with a particular focus on inertia provision. Additionally, modifications to these countermeasures are proposed to mitigate the identified and potentially undesirable effects while preserving the beneficial damping characteristics. The paper thus highlights limitations and possible constraints in the development and parameterization of grid-forming converter control and is of particular interest to both manufacturers and grid operators.

The growing integration of renewable energy sources into the European power grid, along with the increased use of power electronics-interfaced devices, necessitates the development of advanced control strategies. Grid-forming control approaches have emerged as promising solutions to meet the future demands of the power system. To ensure these control methods adhere to network code requirements, rigorous validation is essential. This study provides an experimental validation of a discrete-time implementation of a virtual synchronous machine (VSM) converter control method, alongside a virtual impedance for current limitation, using a hardware-in-the-loop (HIL) test bench. A detailed analysis of the virtual impedance’s behavior during fault-ride-through events revealed limitations in subtransient current control. These limitations were attributed to the control system’s low bandwidth in discrete-time operation. To address this, the control system was enhanced with a current saturation mechanism and a fault mode employing gain scheduling, leading to improved system stability and better subtransient current limitation. The findings emphasize the importance of experimental validation in discrete-time systems to resolve transient behavior challenges and improve control system performance.

The aggregation of wind power forecasts to grid areas, such as transmission system operator (TSO) control zones, provides grid operators with valuable information for the planning of grid operations. In particular, as the share of renewable energies continues to increase, improvements in forecast quality are becoming increasingly important. When forecasts at reference wind parks are projected to all wind parks in total and aggregated to grid areas of known installed capacity, a broad distribution of reference parks is advantageous for accounting for local weather situations. This often conflicts with the availability of measurement data for training accurate models. In this R&D project, we propose an approach that uses publicly available wind park master data as well as local weather forecasts as input into a zero-shot learning model. This model generates additional, locally distributed forecasts that are used in the projection process to the total of all parks. For reference park forecasts, we employ a combined multi-task and transfer learning approach. In this approach, measurement data is leveraged to train a multidimensional park embedding, which characterizes the park's behavior. This park embedding is part of the model’s input feature set. The zero-shot model is based on the same multi-task learning artificial neural network architecture and is trained on a portfolio of reference parks. Instead of a trained embedding, master data such as hub height and rotor diameter are employed to embed each park into a characterizing embedding space. This approach enables the zero-shot model to generate forecasts at new locations without training when provided with local master data. As a result, it provides a much more comprehensive coverage in the forecast projection process to the total of all parks. The projection is achieved through an inverse-distance-weighting of wind parks to grid areas of known installed capacity, followed by an aggregation to TSO control zones. Experimental results with field data demonstrate that in terms of forecast accuracy at control zone level, our approach outperforms methods that only use reference wind parks in the process. Additionally, we observe that the zero-shot learning approach enhances forecast quality compared to physical models when generating forecasts at additional locations. Furthermore, we illustrate how our approach can be integrated with optimization techniques regarding the projection process to further improve overall results.

Integrating renewable energy sources into power grids poses challenges for manufacturers and grid operators. Accelerated production and time-to-market phases require effective testing aligned with current standards. Conventional field testing is simple and allows testing complete power generation units (PGUs), while hardware-in-the-loop (HIL) test benches offer shorter testing periods, reproducible conditions, and greater flexibility via real-time simulations. Studies show that PGU behavior on test benches can match field behavior, usually validated by fault ride-through tests. However, when field measurements are unavailable or new testing methods are developed, the accuracy of HIL simulation concepts may be questioned. This paper proposes a method for validating power HIL (PHIL) testing using vector-based measures. Physical quantities are collected in generalized vectors, allowing the application of Euclidean vector norm and cosine similarity. Unlike methods based on symmetrical components that require filtering, the proposed vector-based approach is valid for both steady-state and transient assessments. Applying the concept to three-phase PHIL simulations in wind turbine testing, the paper discusses advantages and limitations through three example applications. It demonstrates how the method can be used to validate requirements on test equipment, compare test bench and field measurements, and evaluate PHIL simulation quality when benchmark data is unavailable.

ScopeThe integration of renewable energy sources leads to a reduction of inertia in the electricity system due to the shutdown of conventional power plants and the associated loss of synchronous generators (SG) and their ability to provide system services. In the future, this inertia and system services will have to be taken over by inverter-based generation (IBG) resources, such as wind and solar power plants.Due to the rapid development of power electronics devices (PEDs) and control theory, the capabilities of converters are increasing. As a result, the electrical behaviour of IBGs is highly dependent on the control used. There are several approaches to the control of IBGs. In general, they can be distinguished by the terms "grid following (GFL)" and "grid forming (GFM)" control. While the GFL control follows the grid with a phase-locked loop (PLL) and feeds its reference power into the grid, the GFM control emulates the behaviour of SGs by determining the frequency based on the active reference power and the actual active power fed into the grid, as well as the active power reference based on the frequency (Fast Frequency Response, FFR).MethodsThis paper investigates a popular inertia emulating GFM control, the droop control, and its frequency response. Therefore, a GFM controlled IBG is tested in a single machine testbench. The test bench consists of a DC-AC converter with a constant DC voltage, while the AC side voltage of the converter is modelled by an Average Value Model (AVM). The converter is connected to a LC filter with its inductance L_f and capacitance C_f, which is connected to a transformer followed by the point of common coupling (PCC). A constant load, a switchable load and a SG are connected to the PCC to investigate the frequency response of the SG and IBG. To gain further insight into the active power setpoint change of the IGB the synchronous generator can be replaced by a constant voltage source.The GFM control of the IBG converter is performed by a droop control, followed by a cascaded voltage-current controller. Its frequency response is then examined for different load steps. Depending on the response of the converter control to these events, different changes are made to the converter controls. The main focus of this work is to investigate why the converter control is unable to respond appropriately to a load step and to enable the converter to do so. This is done by introducing a current based power setpoint change to ensure a correct frequency response to load changes and a current feed forward control to enable a higher active power adjustment. Finally, the influence of the current feed-forward control on the GFM control is investigated to evaluate the active power change abilities of an IBG.ResultsDuring the investigations the results showed that two main control changes to the GFM-control have to be made:

• A power reference change based on the current behaviour of the IBG to ensure a proper frequency reaction to a load step.
• Adding a d-axis current feed-forward control to enable a higher active power change after a load step.

The second version of the European Regulation 2016/631, which establishes a network code on grid connection requirements for generators (RfG V2), was recently submitted to the European Commission by the Agency for the Cooperation of Energy Regulators (ACER). It contains non-exhaustive requirements for grid forming capability (GFM) applicable to Type B, C and D Power Park Modules (PPM). To streamline implementation at national level and promote harmonisation, ENTSO-E plans to launch works on an Implementation Guidance Document (IGD) by the end of the year. Meanwhile, a Task Force on Dynamic Performance of GFM Capability (TF DyPeGFC) has issued preliminary recommendations (Phase I). Phase II is scheduled to start in May 2024 and aims to gather feedback from stakeholders before proceeding to the formal drafting phase.This work builds on the findings of the TF DyPeGFC and focuses on compliance verification procedures. Specifically, this paper first outlines the proposed exhaustive requirements by technology, namely batteries, wind and solar (WPP and PV). It then describes the performance-based Key Performance Indicators (KPIs) applied, including details of their calculation methods. Specific benchmarks, operating conditions, events and compliance criteria are then defined for the various dynamic performances associated with the expected 'voltage source behind an impedance' behaviour. Typical results are illustrated by time-domain simulations in the phasor domain using generic models representing different control solutions investigated in WP3 of the Migrate project, in particular the filtered droop and virtual synchronous machine (VSM) controls. The parameters of the control strategies are modified to assess and highlight their impact on the compliance criteria. The paper concludes with the challenges associated with scaling up compliance assessment from the unit to the plant level in the case of PPM and highlights the essential considerations for extending the verification procedures from a simulation framework to on-site testing. The need for validating RMS open models with respect to more accurate proprietary models, is also emphasized while also acknowledging the limitations of the former. The developed Modelica models and benchmarks will be made publicly available in the Dynawo project repository.

The stability of electrical grids is crucial for reliable power delivery, yet traditional compliance assessments often overlook the nature of changing grid characteristics over time, leading to potential instability issues due to insufficient compliance monitoring. In Europe, while some efforts towards lifetime compliance monitoring have emerged, implementation remains limited. Today compliance repeat plans have been established in countries like Germany, Denmark and outside Europe, United Kingdom, Australia and South Africa. Demonstration of post-commissioning compliance is still mainly focusing on equipment settings (e.g., protection relay settings), auxiliary power supply and generator functionality, rather than generator performance. In this context the industry is facing uncertainties how to treat lifetime compliance obligations with changing grid characteristics such as short circuit ratio (SCR). Standardized robust frameworks to sufficiently cover all compliance aspects in the course of compliance monitoring is needed.An important connection requirement is voltage control. The correct dynamic response of the reference response or disturbance rejection is depending on the voltage sensitivity dV/dIQ, which can be derived from the SCR. For areas with a high penetration of inverter-based resources (IBRs), the equivalents of the SCR like Equivalent SCR (ESCR) and Voltage Control SCR (VCSCR) can be used to quantify the voltage sensitivity of the aggregated systems. Prior research conducted by FINGRID & Vestas identified VCSCR as a great candidate for handling the issues with multiple plant influencing the voltage at the point of connection (PoC). However, existing solutions are predominantly static and simulation-based, lacking adaptability to evolving grid conditions. Vestas is exploring a novel approach to address this limitation through real-time grid estimation, focusing on non-intrusive methods for assessing voltage sensitivity and dynamics. This approach utilizes power meter measurements at PoC to evaluate grid voltage sensitivity, aiding Transmission System Operators (TSOs) in optimizing parameters and solutions in collaboration with generator owners and equipment manufacturers to ensure grid stability over generator lifetime. Validation studies conducted using Vestas source code based models (PSCAD), particularly in grids featuring Thevenin equivalents, have yielded promising results. Nonetheless, addressing the scenario of multiple nearby plants contributing to voltage stability remains a topic requiring further discussion.The forthcoming paper will give an overview of today’s compliance monitoring practices and insights from simulations addressing ongoing efforts to enable robust grid stability

With the transition to renewable energies and higher transportation power, the inertia provided by the synchronous generators in the grid decreases. Every possible contribution has to be realised in the future. This paper analyses the potential of inertia from a battery storage system (BBS) in the low-voltage grid due to a grid-forming inverter. Resulting instantaneous power adjustments are first calculated and then simulated. These are determined for different frequency requirements, inverter start-up time constants T_A and grid connections. The higher the frequency gradient, the more power adjustment is required. With a higher T_A, more inertia can be provided. The grid connection in the low-voltage grid only plays a minor role, as this is not a parameter that affects the calculation of the power adjustment. There are minor effects on the control response, as a maximum fluctuation margin of 1.3 % for the jump height. The provision of inertia should be possible from different grid connections. The higher the value for T_A is set, the more potential is available to provide inertia from BSS in the low-voltage grid and to cover the inertia gap proportionally. However, the configuration is limited by the possible overload and the operation strategy of the BSS.

This paper presents the modelling and grid-forming controls for Type 4 offshore Wind Turbine Generators (WTGs). It seeks to highlight relevant properties of the controls and the operational strategies that are used in the context of the research project “Offshore Wind Farms as Power Plants” (“OffWiPP”). In the addressed project, the depicted WTGs are combined with a newly controlled High-Voltage Direct Current (HVDC) transmission system, which also utilizes a grid-forming control in the onshore converter station and, therefore, provides system services at the onshore grid connection point with the aid of the wind turbines. Furthermore, an overcurrent limitation strategy is implemented, which similarly works for balanced and unbalanced low-voltage faults and phase-angle steps in the grid.

This paper proposes a novel topology for photovoltaic (PV) systems in grid-connected applications utilizing current source inverters (CSIs). In the proposed topology, a DC-DC Buck converter is employed between the PV array and the CSI to enhance the low voltage ride-through (LVRT) capabilities in compliance with grid code requirements. By leveraging the fast and linear control of the DC inductor current in the Buck converter, along with current setting in the CSI, the system enables direct power control of the grid. Additionally, a novel Maximum Power Point Tracking (MPPT) algorithm is introduced, allowing the PV array to generate the maximum active power in response to grid voltage dips, while maintaining power balance between the converter’s input and output according to the power rating of the grid inverter. Furthermore, both grid-following and grid-forming control strategies are implemented in the system and compared under severe LVRT scenarios in a strong grid environment. The system is also evaluated for LVRT and phase jump performance using grid-forming control in a weak grid condition. The test results are derived from simulations performed using Plecs software.

The paper presents a comprehensive review of challenges for relay protection functions highlighted in academic literature and research papers in recent years. These challenges are examined within the context of the increasing share of converter-based renewable sources in the power systems. The main features of converter dominated system which are crucial for protection operation are discussed. Grid code requirements essential for relay protection study are introduced. The paper offers a detailed analysis of each compromised protection function and extends these findings to assess protection functions in offshore wind power plants (OWPP) with different types of grid connections. The review identifies both the similarities and differences in protection challenges across various scenarios.

Flexibilities in terms of controllable electricity consumers are essential for a reliable and efficient operation of energy systems with a high proportion of weather-dependent energy sources like wind and solar power. Heat pumps are a key technology for the energy transition. On the one hand, because their operation can be adapted to the volatility of weather-dependent production. And on the other hand, because heat generation using heat pumps driven by renewable energies (RE) contributes significantly to the decarbonisation of the heating sector.To be able to efficiently provide flexibility from RE driven heat pump systems optimized intraday and day-ahead forecast systems are indispensable. Forecasts of weather-dependent generation (mainly wind and solar) but also forecasts of heat pump operation are needed to create cross-sectoral operational plannings. Wind and solar forecasting systems are now well researched and established in the energy industry. In contrast, there is very little knowledge in the development of forecasts for an optimised heat pump operation with regard to the provision of flexible power. The ‘FlexLearn’ project has set itself the task of solving this problem.The main aim of the public funded project ‘FlexLearn’ is to develop models to forecast the operating behaviour and flexibility potential of diverse heat pump technologies with the help of fundamental models and transfer learning approaches. Last mentioned approaches are especially transferred to heat pumps with insufficient measured operating data in order to be able to derive general artificial intelligence (AI) models for heat pumps for different technologies but also different sized measurement data sets. Meta and operating data from several thousand differently structured and parameterized heat pump systems are available for modelling within the project.Within this talk we will start with an overview about the underlying database with focus on the characterisation of the available operating data that has been used to classify the different heat pump technologies. Subsequently we will show an analysis of the simultaneity in the electricity supply of spatial distributed heat pumps. This information is of high importance for grid operators. We will end the talk with an overview about the generated heat pump forecasts to give answers to the following questions: To what extent can the operating behaviour of individual heat pumps be predicted? How effectively can forecasting models be applied to heat pumps for which little or no historical operating data is available? How to synchronise wind and solar forecasts with heat pump forecasts? How and how accurate can the flexibility potential of heat pump systems be predicted? What uncertainties remain and how can these be minimized through spatial aggregation of heat pump systems?

Large-scale integration of wind power plants into the transmission system has altered the traditional generation mix. To performan accurate stability assessment of the power network, transmission system operators (TSO) require a detailed small signal modelthat accurately represents the original equipment manufacturer’s (OEM) specific control system dynamics. This paper outlinesthe process of converting an OEM-specific converter code into state space matrix form. The methodology to accurately modelcontrol functionalities and non-linearities has been discussed. The resulting small signal model is implemented in the SSAT®tool. The accuracy of the small signal model has been validated with time-domain responses from a detailed PSCAD® model ofa wind turbine. Furthermore, a small signal model of a wind power plant containing multiple wind turbines has been validatedfor plant-level studies.

The energy transition with increasing integration of large offshore wind farms (OWF) poses significant challenges to the power transmission network. One of the challenges is an increase in the short-circuit (SC) current when SC fault occurs in the network. In the Netherlands, this challenge is foreseen in the extra high voltage (EHV) 380 kV network.The Dutch government issued the OWF plans with the ambitious target to approximate 21 GW installed capacity by 2030 and 29 GW by 2035. These additional capacities are substantially high as compared to the existing Dutch electricity system and will require the significant expansions of the network transport capacity, as well as a number of synchronous compensators. Moreover, the increasing SC contribution from the cross-border EHV interconnections and from the high voltage (HV) network to the EHV network are expected due to the similar development. Consequently, the prospective SC current in the Dutch EHV network can increase beyond the existing SC withstanding limit of 63 kA. To realize the OWF target, meticulous network planning is essential; therefore necessitating a careful calculation of the maximum prospective SC current. This paper address the prospective maximum 3-phase SC current in the future Dutch EHV network in 2031 and 2035, considering the following important impact factors:1. Calculation methods: the IEC 60909/VDE 0102 Part 0/DIN EN 60909-0 and Superposition methods. 2. SC contribution from OWF based on two control modes: k-factor control and voltage dynamic support. The Dutch OWF plans predominantly include 2 GW OWF projects using High Voltage Direct Current (HVDC) technology, in which these two control modes are required as per the Dutch Grid code (regarding the requirements for the HVDC-based OWF).3. Network topology: Meshed and non-meshed topology.4. Number of the (conventional) synchronous power generators in operation: all or few.5. SC contribution in the cross-border EHV interconnections. In this paper, the impact factors on the SC current are quantified in form of a sensitivity analysis, using a detailed Dutch EHV and HV network model in the DIgSILENT PowerFactory with the cross-border EHV interconnections and the simplified neighboring countries’ network. The results show an increasing trend of the prospective SC current for 2031-2035. In different scenarios, the prospective SC current changes but can still exceed the withstanding limit of 63 kA in some cases. The mutual interaction of the considered impact factors on the SC current is analyzed, where a compensation effect is identified.To deal with the SC limit exceedance, a preliminary investigation of the potential mitigating measures is also included, which can be grouped into: operational measures (i.e., the substation splitting and the power generation redispatch), control measures (i.e., two SC control modes for HVDC-based OWF), and hardware measure (i.e., fault current limiting reactors). The pros and cons of the mitigating measures are also discussed. The sensitivity analysis and the preliminary investigation provide the insights for further studies regarding the upgrade of the SC withstanding limit to a higher value than 63 kA (e.g., potentially to 80 kA) and the mitigation measures.

While warm desert climates typically provide excellent conditions for photovoltaics, there are also desert regions with very good wind power resources. Due to its different generation profile, wind power could complement photovoltaics and batteries especially in large scale power grids where wind power can enjoy economies of scale. However, there is a need to insulate the turbines from dust and sand as well as prevent excess heat. Since stock wind turbines have not been designed for sandy conditions, and there is no readily available information on the additional costs caused by maintaining wind turbines in desert conditions, this article explores the scenarios under which wind power could be an important part of desert power systems. The case study concerns a system from the middle of Algeria in the Sahara Desert, a power grid serving eight cities with a peak load of 400 MW. The system has sufficient gas-based generation capacity, so PV and wind power are profitable only if their investment costs can be compensated by operational cost savings from the gas power plants. The model minimized total investment and operational costs and yields a least cost system portfolio. Under a large variation of assumptions, wind power remains the most cost-effective source of energy with the exceptions of the most extreme scenario.

The increasing integration of renewable energy sources into power grids has introduced significant challenges in maintaining system stability, particularly with regard to frequency, voltage, and oscillation stability. Among various grid forming control strategies, the Virtual Synchronous Generator (VSG) control has emerged as a promising solution for enhancing grid stability by emulating the dynamic characteristics of traditional synchronous generators. This paper focuses on the role of VSG control in mitigating oscillation instabilities, which are critical in power systems with high renewable penetration. Through modal analysis and time-domain simulations, the effectiveness of VSG control, particularly when augmented with a Power System Stabilizer (PSS), is demonstrated in damping inter-area oscillations. The results underscore the potential of VSG control as a key technology for the reliable integration of renewable energy into modern power grids.

Grid-forming control is considered to be essential in the transition to renewables-dominated power systems. However, grid-forming Type-3 wind turbine generators present unique challenges due to their electromechanical coupling with the grid and the limited kinetic energy in their drive-trains. This prevents active power control methods that emulate synchronous-machine behaviour from delivering robust and stable performance in Type-3 turbines. These limitations become more evident during recovery from severe grid disturbances. To overcome these limitations, this paper proposes a lead-compensator (LC)-based approach for synchronisation and active-power control as an alternative to virtual-synchronous-generators (VSG). The proposed approach is intended to demonstrate that the system damping and the overall transient stability can be improved solely by altering the control structure. Therefore, several time-domain studies have been conducted under different grid-strength levels and current-limitation mechanisms, and the comparison of post-fault recovery performance of the two controllers are presented. The results show that excessive active power oscillations and rotor speed deviations observed with VSG control are substantially mitigated using the proposed LC approach. More importantly, this is achieved without compromising inertia and droop settings, or utilising frequency measurements. Reduced turbine mechanical stress and enhanced robustness are among the benefits of this approach.

The increasing integration of inverter-based resources and the related reduction in the number of synchronous generators lead to a decrease in the inertia available to the power system. One potential solution for providing virtual inertia is the application of grid-forming control methods to inverter-based resources. This paper presents a comparative analysis of two distinct methods, both of which fall within the category of virtual synchronous machines (VSM). The two methods are compared and parameterised on the basis of a small-signal model and evaluated in electromagnetic transient (EMT) simulations using selected benchmark scenarios in accordance with the preliminary requirements of a German transmission system operator (TSO), TenneT. Both methods comprise cascaded control loops. This paper focuses on the different active and reactive power controllers that serve as main controllers. The identical secondary current control loops are employed for both methods in order to provide an indispensable current limiting function. It is demonstrated analytically and in EMT simulations that the investigated methods can be parameterised in a way that they show an identical transient response and that they can successfully meet the preliminary requirements for grid-forming inverters of the German TSO in the considered scenarios.

This paper focuses on the impact of gigawatt-scale offshore wind farms to the Brazilian Interconnected Power System. The paper presents a case study on the connection of 3 GW to a single point in the Brazilian system considering a planned scenario for the year 2032. The selection of the point of common coupling is chosen according to the strength of the point given by its short-circuit ratio, and by the location of the wind farm projects envisaged by TotalEnergies EP Brasil S.A.. AC transmission is considered. Positive-sequence and phasor-domain load flow and transient stability analyses, considering the whole Brazilian system, indicate overvoltage problems at the point of common coupling and its vicinity, particularly when the wind sags and there is too much headroom in the subsea cables. The paper shows strategies to mitigate the overvoltage problems that considers fixed and controlled onshore reactive power compensation, the possibility of cable disconnection in low-offshore-wind scenarios, and the operation of the wind farms with a lagging power factor. The paper shows a computational framework to automate the computation of short-circuit capacity of candidate hosting substations, and to automate the onshore generation redispatch to accommodate the gigawatts injected by the offshore wind farms, in selected system future scenarios. The framework uses a Phyton script that coordinates the call of two commercial-grade tools officially utilized by the Brazilian planning and operating entities. The paper also introduces an optimization framework, utilizing a combination of metaheuristics methods, designed to create a computational tool aiding planners in selecting the optimal configuration for connecting offshore wind farms to the Brazilian system.

The increasing share of inverter-based resources and the decrease of conventional inertia provided by generators lead to the demand of grid-forming control approaches and their profound testing and validation in a realistic environment. This contribution introduces an European 9-Bus benchmark grid model as base for validation and testing of these converters and their control by means of detailed EMT simulations. The grid model is based on the IEEE 9-Bus Benchmark Model and adapted to European grid conditions. To demonstrate its feasibility and suitability the Synchronverter as grid-forming converter control approach has been tested and validated under various grid conditions and for several fault scenarios considering all sources as inverter-based.The EMT simulation results of the European 9-bus grid evince the Synchonverter’s capability to operate not only incombination with other grid-forming controlled inverters but also in combination with a great share of grid-following controlled resources.

The global shift towards renewable energy, particularly wind energy, is a crucial step towards achieving carbon-neutral power systems. However, this transition poses challenges for grid stability due to reduced system inertia, especially with the growing use of inverter-based resources like wind turbines. The grid-forming (GFM) control mode, intended to replace traditional synchronous generators, is expected to play a key role in addressing these stability issues.Given the vast potential of wind energy, ensuring that wind turbine generators (WTGs) comply with GFM control standards is essential. However, integrating GFM into wind energy systems presents significant challenges, including the complex control dynamics within WTGs, the intermittent nature of wind, and the resulting limited energy reserves. Therefore, the design of GFM control systems tailored specifically for wind energy is imperative.This paper investigates the GFM capabilities of Type IV WTGs, with a particular focus on the interactions between grid-side and machine-side control dynamics. A simplified small-signal model is developed to efficiently analyse the coupling between active power and DC-link control, highlighting how GFM parameters such as droop, inertia, and DC voltage controller bandwidth influence system stability. Time-domain simulations are conducted to validate the proposed tuning guidelines and to examine the distinct WTG response characteristics under varying wind speeds and grid contingencies. These simulations use an electromagnetic transient model that incorporates a full-scale back-to-back converter, a grid-side converter employing GFM techniques, a machine-side converter for DC-link control, and a PMSG coupled to a wind turbine aerodynamic model.Contributions of this study are twofold:• Analysis of direct active power coupling: A simplified small-signal model is proposed to analyse mutual interactions between grid and machine-side controllers. This model can be adapted to other back-to-back converter systems, aiding in basic controller design and tuning.•Investigation of distinct characteristics of GFM-WTGs: The study explores unique instability mechanisms and additional considerations required for implementing GFM techniques in WTG systems, providing insights distinct from those in GFM-BESS scenarios.In conclusion, these findings provide a foundation for the development of robust GFM control designs, essential for the stable integration of wind turbines into high-renewable power systems.

Stationary battery systems, and in particular large-scale battery storage systems (BESS), are increasingly being used for a variety of applications in different markets. A deep understanding of the efficiency behaviour of LBSS is crucial for the development of new operating and bidding strategies for single and combined or multi-use applications. Depending on the application, and thus on the power and state of charge (SOC) ranges in which an LBSS is operated, the efficiency of the inverters in the system will vary significantly. This study proposes two methods for the data-driven characterization of inverter efficiency curves for BESS based on operational data of the 6~MW~/~7.5~MWh research focused hybrid LBSS M5BAT (Modular Multi-Megawatt Multi-Technology Medium Voltage - Battery Storage System). These efficiency models were developed for their application within the digital twin of M5BAT and are meant to be a practical approach for BESS operators. The first method uses a quadratic function to model the relationship between AC and DC power of the inverter. Using neural networks, the second method predicts the efficiency of inverters based on the AC power and battery voltage. The results show that both models are sufficient for the simulation of BESS operation in constant power phases. This is especially useful when simulating spot market trading with BESS, where the error contributed by ramping phases is minimal. For the purposes of the digital twin of M5BAT, the developed models are sufficiently accurate in order to simulate and plan power delivery schedules in spot markets. Finally, the proposed methods are useful in order to determine the maximum efficiency operating points of the inverters. This is important for the operation of the BESS, as the power at which the maximum efficiency is achieved can be used to optimize the operation of the BESS. The curves can be implemented in power distribution algorithms to increase efficiency by considering the battery voltage. It is also possible to use different curves for charging and for discharging, as the curves show different shapes and points of maximum efficiency.

Based on findings from LINDA 2.0, the research project "Fuchstal leuchtet" aims to investigate whether a stable grid operation in a converter-based network can be maintained without directly coupled, rotating electrical machines and therefore no inertia in the system. Using the living lab of the "Energiezukunft Fuchstal", it attempts to ensure system stability, considering factors such as frequency and voltage stability without relying on overarching network communication. A key aspect of the study is to achieve an active and reactive power balance in the system and investigate the interaction between gridforming and grid-following inverters. Therefore, accurate simulation models of the PV systems in the local network are required to develop a stable operating concept, which will be validated in field tests. PV systems in Germany exhibit different grid behaviors due to varying commissioning dates. Of particular interest is the provision of reactive power for voltage stabilization, frequency-dependent reduction of active power, and the requirements for protection tripping and grid resynchronization. Therefore, it is essential to differentiate between the currently valid grid codes for PV systems connected to the low-voltage grid, since each places different grid operation requirements. A dynamic simulation model is developed using the DIgSILENT Power Factory simulation software to accurately replicate these various technical standards. Due to various parameterization options including the selection of the valid grid code and reactive power procedure, as well as the precise setting of standard parameters such as shutdown thresholds, time constants of plant protection or the progression of characteristic curves, the PV system can be precisely parameterized according to the applied standard. The generated simulation model allows the integration of various PV systems, which display different normative behaviors, into simulation networks, thereby enhancing the accuracy of replicating grid behavior in different scenarios. The full paper discusses in detail the normative aspects to be considered within the simulation model regarding the active and reactive power behaviour and the protective devices of grid-following inverters. The simulation model and in particular its frequency dependent behaviour is validated with measurement data generated during field deployments.

Equipment redesign is needed to decarbonise energy-intensive industries, such as the glass and aluminium industries. In this context, hydrogen is proposed as fuel instead of natural gas for high-temperature heat supply. This paper presents an optimisation-based methodology to size different microgrid elements including photovoltaic (PV) power, electrolyser, compressor, hydrogen tank, and burner. Therefore, it aims to minimize the total costs of the system based on its operation, considering active and flexible management of generation, and costs for CO2 emissions. Furthermore, the contracted power can also be optimised. Moreover, it can also delimit the penetration of renewables and the hydrogen fraction. This methodology is used to analyse the role of hydrogen in an industrial case study.

Renewable energy sources are widely installed in power grids as a countermeasure to global energy resource depletion and global warming. Offshore wind farms (WFs), in addition to onshore WFs, are promising technologies for carbon-free power generation.From an economic point of view, high-voltage DC transmission (HVDC) systems are more suitable than AC transmission systems for long-distance submarine power transfer since the HVDC system consumes no reactive power and needs small-capacity submarine cables. The HVDC system is the best way to send power from remote offshore WFs to onshore power grids.A three-terminal HVDC system can supply power from one offshore WF to two individual onshore power grids. It can also be used as an interregional connection line to exchange power between the two onshore power grids using the DC submarine cable's power transfer capability when the offshore WF has low output power.This paper proposes a power control method for the three terminal HVDC systems to stabilize the sharing of the WF power output between the onshore power grids and inter-regional power exchange between the two grids. In the proposed control method, a power controller with a DC-voltage droop function is provided to an onshore HVDC terminal, and another onshore terminal is equipped with a DC-voltage droop function. A constant-AC voltage and constant frequency controller is used for the offshore terminal.Simulation studies were carried out using PSCAD software to validate the proposed power control method. The simulation model is a 1GW bipolar three-terminal HVDC system with a rated DC voltage of +/-500kV. Each AC/DC converter is modelled by two-level PWM inverters. The controller for the AC/DC converter is designed based on a dq-axis vector control principle.The simulation result confirmed that in the case of a sudden change of the WF power output from 1 GW to 700 MW, the power received by the onshore terminal 1 with the power controller with the DC-voltage droop function was successfully kept to a commanded power of 100 MW. As expected, the power received by the onshore terminal 2 with the DC-voltage controller with the power droop function changed from 900 MW to 600 MW.The full paper will describe the simulation results to demonstrate the operating performance of the three-terminal HVDC system, including the condition that the two onshore terminals share the WF power output and simultaneously exchange inter-regional power.

Type 5 wind turbines drive synchronous generators which are directly grid-connected, just like conventional power plants. The generator is the self-exciting electromagnetic type controlled by an automatic voltage regulator (AVR), capable of the same amount of system strength (being fault current at more than 3 times rated (3 pu) for fault and post-fault conditions) as thermal and hydro turbine-generators. Historically, system strength from conventional power plants has ensured system stability.However, the mainstream of the wind industry is dominated by Type 3 and Type 4 wind turbines, with inverters capable of only 0.4 pu (typically) and 1 pu respectively. The degradation of system strength because of wind and solar inverter-based resources (IBRs) is a major concern facing the zero-carbon transition. As renewables’ penetration increases, synchronous condensers are increasingly being required to avoid curtailing IBRs.The directly-connected synchronous generator of Type 5 wind turbines avoids the need for separate synchronous condensers. There are three main Type 5 designs, which use different mechanical variable-speed (VS) systems so the generator can run at synchronous speed. This paper describes recent research into these three systems and compares their levelized cost of energy (LCOE) against Type 3 and 4 systems, and against each other.

Ｍicrogrids with renewable energy sources as the main power supplies have been attracting attention as a countermeasure to environmental and energy problems. However, the microgrid has problems with supply-demand imbalance, frequency and voltage fluctuations, and securing reserve power, with an increase in the installed capacity of the renewable power sources.A countermeasure to these problems is to operate a diesel generator (DG) installed in the microgrid. However, the DG requires fuel transportation costs and emits CO2 gases. Dependency on the DG must be reduced as much as possible.In the case of a microgrid on a remote island, another option is to send power from a mail land to the remote island by submarine cable power transmission. From an economic point of view, a high-voltage DC transmission (HVDC) system is more suitable than AC transmission for submarine cable transmission over a distance of 50 to 60 km since the HVDC system needs no reactive power and transmits power by a small-capacity submarine cable.This paper proposes a grid frequency control method for the HVDC system connected between the mainland and the remote island microgrid. The proposed control method is designed to coordinate with governor control of the diesel generator in the island grid and suppress frequency fluctuations caused by the renewable energy source in the island grid. The island-side HVDC terminal basically has a constant AC voltage and constant frequency control. However, in the proposed control method, the frequency is adjusted by the power deviation between the HVDC power output and the HVDC reference power commended by an energy management system (EMS) inslatted in the iland microgrid.Simulation studies were carried out to validate the proposed frequency control method using a Simulink model running on a real-time simulator OPAL-RT. The remote island microgrid has a load, a diesel generator, a solar power plant and a wind farm. The HVDC model includes two converter circuits and control blocks. The actual solar irradiation and wind speed data were used to determine the solar power plant and wind farm power outputs. 24-hour simulation studies were conducted using a calculation time step of 100 microseconds.The simulation result confirmed that the microgrid frequency was successfully kept in a range from 49.8 Hz to 50.2 Hz by coordinated control by the HVDC frequency controller and DG governor controller, even when the weather repeatedly changed from sunny to cloudy, and the solar power plant output had severe changes. The update interval of the HVDC power reference value sent from the microgrid EMS and a gain from power deviation to the frequency reference in the HVDC controller were selected as parameters for the simulations.The final paper will describe an optimal solution to the frequency control method for the remote island using the HVDC system. In addtion to the remote island microgrid, the power and frequency fluctuations of the manland grid will be taken into consideration.

The Doubly-Fed Induction Generator (DFIG) has become a key technology in wind energy generation due to its ability to generate electricity at nominal frequency across various rotational speeds. Traditionally, Grid-Following (GFL) vector control has been used to control the DFIG, but the increasing integration of renewables has presented new challenges. Grid-Forming (GFM) control techniques have been proposed to address these issues, though their application in DFIG systems is still underexplored. This study examines the effects of implementing GFM control in both the Machine Side Converter (MSC) and Grid Side Converter (GSC) of DFIG systems, focusing on their interactions and impact on system stability. Additionally, a novel MSC control structure is introduced to enhance GFM management. The research aims to guide the integration of GFM into DFIG systems, improving performance in the evolving energy landscape.

Grid-forming (GFM) inverter-based resources (IBRs) are gaining attention as a viable mechanism for supporting significantly higher penetration of renewables as conventional synchronous generators are being retired or displaced in bulk power systems. To facilitate interconnection of these GFM resources, grid requirements and services are being drafted to establish baseline performance expectations for the technology. Certain desired GFM characteristics can be quantified by its small-signal response to changes in grid voltage. Various technologies have differing capability of meeting the desired frequency response characteristics. For example, some grid-following (GFL) resources with non-standard or stability-enhanced controls may be able to meet specific small-signal response aspects that are associated with GFM performance. Further, equipment hardware constraints may limit the response of GFM assets at certain frequencies but otherwise provide the desired response outside of this constrained region (for example, wind turbines with mechanical resonances). This paper focuses on the capabilities and limitations of GFL and GFM assets to achieve the expected frequency response. Guidelines for small-signal performance requirements and services are also provided that achieve the desired grid benefits and avoid excluding various technologies that can contribute to providing these grid stabilizing benefits.

The development of renewable energy generation in Poland is progressing very quickly - recent years have seen primarily the development of low-voltage prosumer photovoltaic generation (13 GW, 1.1 million installations). The next group with the highest increase in installed capacity are PV installations with a capacity below 1 MW (4 GW, 4,000 installations). For large PV facilities with capacities ranging from several dozen to several hundred megawatts, development is mainly of a "paper" nature, manifested in connection agreements signed with network operators. Onshore wind energy, after years of political blockade, is expanding with new facilities, and support for the development of offshore energy (and a guarantee of power connection at the level of 11 GW) is provided by the appropriate government act. On the other hand, the increase in energy demand has not yet shown the expected dynamics, despite forecasts assuming its increase by as much as 50% by 2040. Thus, several sunny days in March and April 2024 brought about the need to curtail the power of photovoltaic sources. In particular, on weekend days (including April 27), the reduction affected large and medium-power PV installations that are subordinated to remote control systems. In most cases, the curtailment at the level of 2,000 - 4,000 MW was carried out through zero-one control consisting of complete shutdown of individual facilities. It is estimated that due to the shutdowns, the annual loss of generation in the first quarter amounted to 0.7%, and the following months may bring a result of 2-3%.The question arises what may happen in 2030 and further in 2040, given various types of blind conditions (the condition of conventional facilities powered by coal and gas, the dynamics of development of offshore wind energy, progress in the construction of a nuclear power plant, installed capacity and storage capacity) - whether the loss of generation in level of 20-30% may be a signal to weaken the dynamics of investments in renewable energy sources, in particular in large PV installations?The article proposed to be presented at the conference tries to answer these questions, presenting the risk of a possible level of restrictions, adopting various assumptions regarding the increase in power in the source sector. As in the articles presented in 2022 and 2023 (The Hague and Copenhagen), the basis of the analysis are the actual load and generation processes recorded for the full annual cycle (8,760 hours) and scaled for the years 2025-2030-2040. From the results obtained, significant levels of generation reduction in renewable energy sources can be expected, unless there is a breakthrough in the development of long-term storage. Investors should take this level of risk into account in their business calculations. On the other hand, there is also a visible need to lower the threshold of conventional generation referred to as "must run" and to develop "grid forming" inverters. On the other hand, it seems that the level of abandonment of sources powered by fossil fuels will not be possible as quickly as climate advocates see it, unless we agree that the value of an indicator such as LOLE (Lost of Load Expectation) does not rise to values unacceptable by society.

The ongoing transition from conventional to renewable energy sources is leading to an increasing number of converters in the power grid, resulting in a grid that is becoming more converter-dominant. Traditional energy sources, driven by synchronous machines, inherently provide inertia and damping, which are gradually being lost as these machines are replaced by renewable energy sources like solar and wind turbines that rely on converters. This loss of inherent inertia and damping has introduced various grid stability challenges. To address these issues, grid-forming converters can be equipped with virtual inertia and damping mechanisms. This paper focuses on the damping capabilities provided by grid-forming converters. As the passive damping traditionally offered by synchronous machines diminishes, there is a pressing need for additional damping solutions. In this study, a grid-forming converter integrated with a power system stabilizer (PSS) is employed to mitigate power system oscillations. The paper explores the impact of the PSS on power system stability in conjunction with the grid-forming converter, highlighting its effectiveness in damping oscillations in a power system.

The traditional method for electrical model validation of Wind Turbine Generators (WTG) relies on full-scale field prototype turbine testing. Model validation based on full-scale field testing is, without argument, the most reliable and robust way, but it also presents limitations. Major limitations include the scope of faults, controllability of events, time and ultimately cost. There are events such as phase jump, fast frequency change, single-phase-to-ground faults, etc., that cannot be performed on full-scale field testing, and the availability of the turbine for testing is also heavily dependent on the weather/wind conditions. To address these limitations, this paper proposes a strategy, backed by the results from Part 1 of the paper, that utilizes EMT models and test rigs to enhance the testing and validation robustness of a new WTG. The proposed strategy includes three pillars: using EMT models for assessment before testing, conducting test rig testing for grid compliance and model validation, and finally, testing and verification on the full-scale field turbine. By including additional steps prior to testing in the field prototype WTG, this strategy aims to build a more robust testing and validation strategy for developing better models to be used in studies during the design and operational life cycles of WPPs. The results presented in the paper show that this process can speed up model delivery while improving robustness. The paper further highlights that grid compliance can be tested and validated in different ways, and flexibility on the requirements to Original Equipment Manufacturers (OEMs) shall be present to allow more innovation in the processes while ensuring that model validation and model quality, as the main objective, is maintained.

1. IntroductionPhotovoltaic (PV) power generation systems (hereafter referred to as "PV") are being installed in large numbers in Japan. From the viewpoint of electricity supply and demand, PV should generate electricity only during the daytime, and supply from other sources (e.g. thermal power in Japan) should be reduced during that time. Thermal power plants need to plan the next day's operation by the evening of the previous day. Therefore, information on the PV output forecast for the next day（day-ahead forecast） is necessary. In actual operation, the results of the numerical weather prediction model (NWP) are used. The PV output forecast is greatly affected by the forecast of solar radiation. It is also important to use ensemble forecasting to improve the accuracy of forecasting and to understand the uncertainty of forecasting in advance. In this paper, we present the results of a case study analysis of solar radiation forecasts (for the Hokkaido Electric Power Company area) by weather conditions using the meso-ensemble forecasting system (hereafter referred to as MEPS).2. Meso-ensemble forecasting (MEPS)The Japan Meteorological Agency (JMA) has started the actual operation of MEPS, which calculates forecasts four times a day (00, 06, 12, and 18 UTC) up to 39 hours in advance. The basic model is a meso-model with perturbations for initial and boundary values. The number of ensemble members is 21. The results of the analysis of the JMA model specifications are available on the JMA website (https://ds.data.jma.go.jp/tcc/tcc/products/model/index.html).3. resultsIn the case of May 31, 2021 (after a low-pressure system passed through the area, low-level clouds were confirmed from visible and infrared images taken by the meteorological satellite Himawari,), the solar radiation forecast was found to be far off the underpredicted side for the entire Hokkaido Electric Power Company area. In the case of underprediction of solar radiation, the actual amount of solar radiation (PV output) is higher, so it is necessary to control the PV output in some cases. On the other hand, the accuracy of the MEPS irradiance prediction is high for clear days, and the results are quite close to the actual values. In addition, the variation among the ensemble members is small, indicating that the predictions are highly accurate. Similarly, in the case of optically thick clouds with precipitation during the passageof a low-pressure system, the ensemble variations are small, and the predictions of solar radiation are also close to the actual values. At the time of the presentation, we plan to show detailed results for the case of large forecast failure of low-level clouds. Hokkaido is also a region with a large amount of snow cover in winter. The presentation will also include a case study of the observation of snow accumulation over solar power generation.Acknowledgments: This study is conducted under the New Energy and Industrial Technology Development Organization (NEDO) project "Development of Technology for Predicting Solar Radiation for the Next Day and Beyond" (FY2021-2024).

The integration of renewable energy sources like wind and solar into future power systems requires increased flexibility. The hydrogen market in Europe and Germany is ramping up, including domestic hydrogen production via electrolysis.The flexible operation of electrolysers could contribute to the integration of renewable integration through market mechanisms, but also potentially through grid congestion management (redispatch). The latter is highly sensitive to their location and can result in deviations from the planned hydrogen production. The works present and compare three different methods to allocate electrolysers in the German transmission system for the year 2030 using a substation-sharp transmission grid model and hourly time series profiles from a market simulation. Additionally, it is differentiated between cases where electrolysers can or cannot be adjusted by the transmission system operator during redispatch. Consequently, a mathematical redispatch optimization problem is formulated and applied. The results of the redispatch optimization are presented and compared for the different methods. It can be concluded that an integration of electrolysers into the redispatch process could have positive system effects, provided that the process is not too generic and can take the specific requirements of different business cases into account.

Electric power systems all over the world were built based on the characteristics of power plants and their synchronous machines. With advancing transition towards distributed, inverter coupled power generators, the question, how grid stability can be maintained in future has been widely discussed.In order to maintain grid stability with very high shares of inverter coupled power generators (and even without synchronous generators if necessary), there have to be new approaches to provide fundamental system services formerly provided inherently by synchronous machines. Characteristics related to synchronous machines like inertia, voltage source behaviour and high short circuit current contribution never had to be called for but had to be dealt with.However, since power electronic based converters do not have those inherent characteristics, a proper description of capabilities required from power generators or grid assets has to be developed that takes into account the system needs of the power system as well as potentially totally different characteristics of the grid users (generators, storage and consumers).Grid Codes have been developed continuously in the past 20 years in order to increase the converter’s robustness against grid events and regarding grid supporting control capabilities.While in Island grids grid forming capabilities have been used now for several years, for grid forming operation parallel to the transmission or distribution system in public grids experiences are still rare. Such experiences are crucial for setting up appropriate technical rules for the industry and power system operators. The industry and grid operators are still at the beginning of the learning curve.With regard to grid forming capabilities, the converter’s controls and characteristics have to be modified substantially. Depending on the characteristics of the application or primary energy source (PV-Generator, Wind Turbine, Battery, Capacitor…) the implementation may be more or less challenging and impacting existing converter and generator design. It is important to set up technical rules and regulation in a way that on the one hand the capabilities required by the power system are provided reliably and on the other hand in an efficient and cost-effective way.There are different regulatory approaches to bring grid forming capabilities to the power system, e.g. by specific grid forming assets, by market based approaches and by minimum technical requirements in grid codes that have to be complied with by every resource connecting to the grid. All of these approaches have different pros and cons that have to be taken into account.Regardless the regulatory approach, one challenge is to define grid-forming specific parameters in order to quantify grid forming capabilities as a basis for compliance evaluation.In this paper, based on actual developments these approaches and requirements definitions are discussed from a manufacturer’s point of view, technology specific technical challenges are discussed and recommendations are given for future development of the regulatory framework towards stable power systems based on renewable energy resources.

Wind turbine generators (WTG) use grid following (GFL) converter control, which can track its power reference (e.g., from a maximum power point tracking - MPPT - algorithm) quickly and accurately. On the other hand, grid forming (GFM) has better and faster grid support capabilities, which is especially relevant for power grids with low inertia. However, having two converters (one GFL and one GFM) in one WTG would be ineffective, especially in terms of cost. This paper proposes a single hybrid-controlled converter (HCC), which produces exactly the equivalent behaviour of the GFL and GFM converters in parallel. The HCC was applied to the grid-side converter of a Type IV WTG, which was modelled in PSCAD. Simulation results are presented to show the advantages of using HCC as part of the WTG control system. This approach aims to have a WTG that, in steady-state conditions, operates as a GFL converter guaranteeing MPPT, if its active power reference is the MPPT power, and during a disturbance in the grid, operates seamlessly as GFM providing frequency and voltage support, similarly to a synchronous generator. This project was supported by TotalEnergies.

Increased penetration of renewable energy into the power system has led to the utilization of energy storage facilities, including pumped storage hydropower plants. Unlike conventional generators, pumped storage hydropower plants have the ability to store electrical energy by absorbing energy from the power system and releasing it at another time. Furthermore, to capture the value of energy storage facilities, it is necessary to consider the effect of increasing social welfare by combining the supply and demand of electricity at different times. One of the major problems is the nonconvexity of the range of possible outputs that exists for both pumping and generating operations. The method of calculating market prices using the partial derivative by demand of the Lagrangian function, which is well known as the locational marginal price, does not reflect the value of power supplied via pumped storage generators when there is a period of pumping operation at the minimum load. As a result, if settlement is processed at the calculated locational marginal price, the operation of the pumped storage generator will have a negative balance and there will be no incentive to comply with the ordered operating schedule. Therefore, out-of-market settlement through uplift will be required. This paper describes the formulation of a pumped storage hydropower plant to internalize pumping losses into the power market. The proposed formulation is designed as an optimal transmission switching problem based on the concept of treating pumped storage hydropower plants as transmission assets. First, losses during charging and discharging operation of the pumped storage hydropower plants are considered as well as transmission losses. Furthermore, the upper and lower output limit constraints of the pumped storage hydropower plants and the upper and lower limit constraints of the amount of energy that can be stored are also taken into account. Finally, the developed formulation will be compared to the existing pumped storage hydropower formulation in a numerical simulation using the power system data of Hokkaido region in Japan. The effectiveness of the proposed formulation will be evaluated based on the utilization and revenues of pumped storage hydropower plants. The evaluation of the proposed formulation shows that the charging and discharging losses of the pumped storage hydropower plants are internalized into the electricity market and the benefits of the pumped storage hydropower plants that absorb the surplus power are linked to the power transmission service of the power system operation. The results show that the proposed method is partially able to integrate the value of time-transportation of pumped storage generators into the electricity market. The results also show that pumped storage hydropower plants can be considered as power transport facilities within the optimization period and that they are effective as power transmission services in power system operations when the share of natural variable sources increases.

Some existing grid codes for inverter-based resources (IBR) require active current priority control during grid disturbances with the intention of improving grid frequency stability. This active current priority control deprioritizes reactive current injection used to support voltage stability. Analysis presented in this paper shows the impact of active current priority control on voltage stability as compared to other types of control. Analysis is carried out using quasi-steady state calculations as well as time-domain simulations to demonstrate the effect of using different type of IBR controls during faults. The results indicate that active current priority control may have a significant adverse impact on voltage stability of IBR plants. Further, system electrical physics may prevent simultaneous compliance of both active current priority requirements and existing low-voltage ride through requirements. This study mainly focuses on the in-fault response of the system to different type of controls.

A novel approach for optimal sizing of energy storage for hybridizing a wind power plant (WPP) is proposed in this work. The formulation aims to find optimal trade-offs between economic and environmental net values due to addition of storage. The formulation uses historical WPP production data to improve the quality of the results and includes the determination of an optimal storage dispatch schedule already during the plant sizing process. The proposed approach is demonstrated on the optimization of a Li-ion battery system used for hybridizing an existing WPP. When compared to existing standard sizing approaches, it was found that improved results are obtained when an optimal battery schedule is considered already during the sizing stage. Additionally, results indicate an increase in the economic net value with increasing battery size, thanks to the access to multiple revenue streams beyond the simple sale of the electricity generated by the WPP. Further economic and environmental benefits are obtained by a proper balancing against battery degradation enabled by the use of PORFC. Interestingly, results however also indicate a decrease in the environmental net value with increasing battery size. This result, which is made possible by the multi-objective approach, highlights the importance of striking a correct balance between economic and environmental aspects when hybridizing a WPP.

Motivation:Hydrogen electrolysis is quickly becoming a key vector to combat climate change by replacing standard fossil industrial and chemical processes with green hydrogen produced by renewable energy. Especially the petrochemical and fertilizer, steel manufacturing and mobility are areas with currently very high levels of CO2 emissions. By replacing fossil energy with renewable energy and traditional processes in these industries with green hydrogen substantial CO2 emissions can be avoided. Green hydrogen requires large scale multi-megawatt electrolysis plants typically ranging from 5 MW to over 1000 MW. Such plants when installed in already congested power networks, represent substantial challenges to power quality, grid stability and network loads, especially when connected via traditional SCR Rectifiers. Whether harmonics, power factor, voltage control, frequency management or grid stability in typical FRT situations, traditional SCR rectification will result in unacceptable levels of grid disturbance.The paperKey to a successful implementation of green hydrogen production and consequently significant and economically viable reduction of CO2 emissions is to ensure electrolytic hydrogen does not disturb power grids beyond acceptable limits.The paper presents a potential pathway for grid integration of large-scale hydrogen electrolysis using advanced power electronics. Not only will such electronics reduce the potential impact of such plants but also will be able to provide active grid services such as frequency support, voltage support, reactive power support and active FRT support when designed right.The paper describes how electrolyzers react to grid disturbances and how transistor-based power electronics will be able to support the power networks utilizing active power factor control and dynamic grid support. Especially for very large electrolysis plants the combination of rectifiers providing DC-Power to the electrolyzers with fast acting energy storage systems can significantly improve reliability, reduce system stress and maximize lifetime.A critical aspect of electrolyzer operation is the system behavior during Fault Situations. It will be demonstrated that with partial FRT functionality electrolyzers can remain on-line and immediately return to operation after fault clearance. For congested power grids in rural areas or countries like Australia this may not be enough, and it may also be required to provide reactive power during grid faults to stabilize voltage. The paper will show that this can be achieved using sophisticated algorithms and advanced functions available when using IGBT power conversion systems.In conclusion the paper will demonstrate how real electrolysis projects have successfully shown grid friendly behavior and functions such as dynamic power factor control or voltage control are increasingly required by customers also in stressed industrial networks maximizing network utilization and efficiency.

As thermal power plants make way for an increasing penetration of offshore wind in Great Britain (GB), transmission owners and National Grid Electricity System Operator must consider how low carbon technologies can deliver ancillary services once provided by conventional generation. With practical applications of grid-forming control emerging on converter-based resources, black start capability is a potential functional specification for future offshore wind power plants (OWPPs). Much of the literature has investigated black start feasibility of OWPPs in both AC and DC-connected point-to-point configurations. However, it is proposed that in future OWPPs in GB will share transmission assets, connecting to the onshore system through integrated offshore network topologies. In this paper, the feasibility of coordinated black start solutions based on a future offshore network scenario is studied. The work is undertaken by means of electromagnetic transient simulation in RTDS/RSCAD. A three-ended multi-terminal HVDC (MTDC) network, of bipolar configuration, is developed for the study, which incorporates two OWPPs and a co-located onshore BESS. The study sets out to investigate start-up requirements of the offshore AC island and the MTDC system. Coordinated energisation scenarios are then studied to evaluate the benefits of the network arrangement to the onshore system during restoration. Benefits include supporting the onshore system from multiple points of infeed simultaneously, power sharing, faster restoration, and reduced vulnerability to local wind variability.

The renewable energy expansion towards a carbon neutral emissions world requires a variety of systems to be implemented. To accelerate this energy transition, photovoltaic (PV) systems that optimally use the current grid infrastructure are of vital importance. This work will summarize the state-of-the-art benefits that vertical PV installations can provide to the renewable energy landscape.The first benefit of vertical bifacial (VB) Agrivoltaic systems esp. proposed by the manufacturer Next2Sun is the contribution to maximize the utilization of the grid infrastructure. VB systems oriented with the module surface towards east and west (E/W) therefore have two generation peaks one in the morning and another in the afternoon. This allows to shift the typical production peak of conventional (C-)PV systems (tilted and south oriented) from noon to the daily edge hours to generate electricity when it is typically most needed and most of the capacity of grid infrastructure is unused. Additionally, a system combining both orientations E/W (52%) and conventional south tilted (48%) would provide a more balanced generation behavior and therefore could enable further grid serving properties. Further analyzing the contribution of different orientations of the VB systems would provide a deeper insight on the better seasonal power generation distribution and thus a more optimized and resilient supply of the future energy system. A further benefit of VB is that, in locations with latitudes higher than around 50°, VB systems are typically reaching higher specific PV-yields than C-PV, which makes them besides their synergetic behavior reg. snowfall events in particular of interest for Nordic countries. The longer sunset and sunrise times and the average lower sun heights on those high latitudes are the main reason for the higher specific electricity yield of VB systems compared to C-PV systems. The bifaciality factor from the PV modules used in the VB systems is highly affecting the electricity generation of VB systems. Improving this factor could potentially further reduce the latitude where VB systems reach higher specific yields than C-PV. Therefore, VBPV could generate higher revenues on higher latitudes compared to C-PV. Additionally, countries with a high capacity of C-PV systems already installed would especially benefit from VBAV due to the more demand-oriented energy production outside of the midday peak of the C-PV systems which might under certain circumstances lead to negative electricity prices. Another technology advantage of the vertically installed PV modules would be the temperature transfer behavior studied by Carr et al. where they found that the heat transfer coefficient is nearly double, and the VB modules operate at a much lower temperature, leading to 2.5% higher annual energy yield and higher performance ratio.In this work we would like to present and discuss the abovementioned topics referring to the studies found in literature where simulations of the different PV configurations were done to predict how a better utilization of the current grid infrastructure could be reached using a variety of of PV installations like the vertical bifacial agrivoltaics systems.

This study presents an optimization algorithm for residential households with photovoltaic system, battery storage, and electricvehicle, focusing on the dynamic, power-dependent efficiency of electric vehicles and its impact on grid power exchange. Wedeveloped a mixed-integer linear programming model using Gurobi optimizer to enhance household energy management bystrategically managing energy distribution and storage based on vehicle battery charging efficiencies, which vary with powerinput levels. The dynamic efficiency function for vehicle charging impacts energy distribution strategies by maximizing solarenergy utilization during peak times. The model adapts to fluctuations in solar output and household consumption, optimizingeconomic outcomes. Simulation results using real-world data demonstrate improved energy flow management between solar panels,batteries, vehicles, and the grid. The approach minimizes grid feed-in during peak times, maximizes on-site solar utilization,and aligns vehicle charging with excess solar production, thereby reducing costs and enhancing grid stability.

This paper observes potential stability and power quality conditions that may emerge during energy augmentation of Battery Energy Storage Systems (BESS). The term “energy augmentation” describes methods used to maintain contracted energy capacity of BESS projects over the lifetime of the project as battery health degrades. Some BESS vendors may achieve this purely through DC side modifications such as replacement or addition of batteries. However, for logistical reasons, some vendors may choose to augment the project on both the AC and DC sides by delivering integrated systems with additional transformers, converters, and batteries. These additional AC side components change the physical impedance characteristics of the project, which may create new interactions between the project and the system that were not observed in prior study processes. Both positive-sequence phasor domain and electromagnetic transient (EMT) time-domain methods are shown to be inadequate or time consuming to apply to a large number of cases, which makes them inappropriate to assess performance sensitivity to changing designs. The paper addresses these modelling challenges through application of frequency-domain analytical methods to screen for sufficient design margin to maintain desired stability and power quality across the evolving project and system impedance conditions.

Nations around the world are progressing in adding renewable sources of energy to their grid as an attempt to meet CO2 emissions targets and provide power to increased demand. The higher portion of intermittent renewables and solar and wind to the grids have created a need for technologies that can not only provide the resilience to the grids but also have low green house gas footprint. Long Duration Energy Storage (LDES) technologies are currently under development to fill this gap. Of the many LDES technologies, Hydrogen based systems is proposed as viable energy storage system for very long periods, including intersessional periods, where hydrogen is stored in salt caverns.In this paper we describe an alternative LDES system based on hydrogen, where hydrogen is stored subsea. Subsea storage provides a safe location for a large mass of hydrogen to be stored at a stable temperature environment, while requiring a reduced footprint on land, and geographic flexibility.The subsea hydrogen LDES system can fit a space where power can be provided for 10-100 hours, or more depending on the application performing an economical mean to integrate renewables to a grid, or to enable a full renewable based grid to be sustained in locations as grid isolated islands.

Due to the transition in energy production, many PV-systems and wind turbines are installed in German distribution grids. Upgrades to the distribution grids can be necessary in order to cope with the resulting higher shares of renewable energies. To estimate the generation power in a specific area, solar and wind potential maps are available, and the future installed power can be calculated. However, this approach does not provide any information about the resulting infeed to the grid. This work presents an approach to estimate the future infeed of renewable energy sources. For this purpose, historical operation data is used to correlate real weather data and the installed generation capacity in the area under consideration.To estimate the PV-infeed in a specific region, a PV-reference system located in this area is used. Based on the measurement data of the reference system synthetic infeed series, calculated with the PVGIS simulation tool for the suitable orientation, is scaled. In addition, determined roof area potentials are included in the estimation to simulate a PV expansion in accordance with the existing building structure. It shows that the use of reference systems allows a detailed simulation of PV infeed that shines through its simplicity compared to a general PV model based on global radiation and other complex input values.To estimate the infeed of wind turbines, a characteristic curve is calculated using the real measurement data of different wind turbines and publicly available wind speed data. The measured wind speed is available from the database of the German weather service at different locations of the analysed area.Due to redispatch, maintenance work and the marketing on the electricity market, the power infeed of wind turbines does not always correlate directly with the measured wind speed. In the full version, a solution is presented to cope this problem and to develop a characteristic curve for the area under consideration. Furthermore, an approach is given to take the hub height of the wind turbines and the height of the wind sensor used for the wind speed measurement into account. Finally, the resulting characteristic curve for the infeed of wind turbines is compared with real characteristic curves of wind turbines to validate the procedure.The resulting methodology can be used to define different infeed scenarios as input for the future grid planning and infeed forecasting during grid operation. The simulation of a future scenario for the year 2045 shows the expected infeed from wind and solar generation in relation to the installed generation power and the resulting simultaneity factors.

Buildings account for a significant share of the overall energy consumption. Currently, their components are becoming increasinglyintelligent and controllable. However, a significant proportion of energy consumption remains uncontrollable. Accurateforecasting of this uncontrollable portion is crucial for effective system planning. To address this, forecasting models based onthe gated recurrent unit (GRU) architecture were trained using 52 real-world datasets. The GRU architecture is known for deliveringhigh accuracy while maintaining lower complexity than similar architectures like Long Short-Term Memory (LSTM). Modelevaluations indicate superior accuracy compared to persistence models, with further accuracy gains observed as data resolutionand aggregation levels increase.

Background and objectiveIn Japan, the revision of the 7th Basic Energy Plan has begun targeting the energy mix in 2040. In the transition to carbon neutrality, a power system has a critical role in zero-emission energy supply, energy efficiency, electrification, and support of new demands.The penetration of variable renewables have been impacting an operation of a power system of 10 interconnected areas of Japan. The generation curtailment has been increasing due to penetration of variable renewable, inflexible operation of the existing thermal generation, shortage of energy storage in various time-frames.In this study, we analyze the benefits of flexibility from traditional generators, distributed generators, demand responses and energy storages.Methods usedThe method used is a production cost simulation tool “MR” with network constraints using real demand and supply condition of the future power system of Japan.MR has a capability to set the requirement for the various flexibilities and to define supply capability of various sources including traditional generation and distributed resources to optimize the generation dispatch, flexibility dispatch and demand shift to minimize the operational cost. MR also has a capability to optimize the operation of m-days to take n-days results, to optimize the operation under the transmission capacity constraints, and to analyze short circuit capacity of the nodes in the transmission system.Main results obtainedAt first, we estimate the future requirements for flexibilities (FCR, S-FRR, FRR, RR, and RR-FIT) from the current requirements in the flexibility market which restarted from April 2024. The current requirement data were calculated using the data from the actual operation of the power system of Japan. The results of the analysis showed that the all the performance indices of curtailment ratio, generation mix, operational cost CO2 emission, and detailed balancing flexibility supply and change according to the study cases.The effectivnes of balancing flexibility supply from DER can change as demand and supply condition such as generation capacity mix, DER capacity, technical performance, and applicability based on the institutions and operational rules.The results imply that it is crucial to be ready for the utilization of flexibilities from DER through two aspects: the first is that different technologies such as dedicated batteries and demand response with characteristics of different response time, energy limit (duration time) and certainty of control can share the requirements for balancing flexibility, The second is that the flexibility requirements can be rationalized and minimized.

The ongoing transformation of the electrical power system in various parts of the world raises the question of how and to what extent inverters with grid-forming capabilities can be installed ensuring power system stability at very high share of inverter-based generation. While a systemic need for a certain portion of grid-forming power plants is widely confirmed, the method to determine the exact need and the quantification and testing of the grid-forming capability is under discussion. Germany has chosen a two-stage approach to meet the systemic demand for grid-forming capabilities as quickly as possible. In a first step, Germany plans for the new market-based ancillary service “inertia” by the TSOs from 2025. In a second step, based on the national implementation of the European network code “requirements for generators” (RfG2.0), a certain minimum inertia capability is expected to become a mandatory requirement for newly connected large power plants from 2027/28. The inertia market is considered a vital means and incentive for rapid establishment of grid-forming capabilities in the grid. It shall allow for the fast achievement of essential core properties such as voltage source behaviour or phase jump power from inverter-based grid-forming power plants while procuring power reserves to encounter power deficit and surplus in the grid, based on positive and negative inertia products, respectively. The German approach to translating the indistinct term “grid-forming” into such inertia products is presented, and their quantification and validation are elaborated upon by giving an overview of technical requirements, as well as corresponding verification procedures as prerequisites for participation in the inertia market.

Large-scale battery storage systems are increasingly being used for a variety of applications, including system services in the power grid. The performance and lifetime of large-scale battery storage systems are strongly influenced by the health and consistency of individual battery cells. This study presents a comprehensive evaluation of cell variations within the large-scale battery storage system M5BAT to identify issues and optimize performance. M5BAT is a 5 MW/7.5 MWh hybrid research storage system mainly used for frequency containment reserve (FCR). It features different battery technologies such as lithium-titanate-oxide (LTO) including high-resolution measurements. Within this study, the cell voltage deviations were evaluated to determine the current state of balancing (SOB). Quasi-open circuit voltage (qOCV) field measurements and differential voltage analysis (DVA) are used to identify shifts in cell state of charge (SOC) and differences in cell state of health (SOH). The SOH could be identified to be in the range of 90 %, while the cell imbalances were found to be at around 40 % for the LTO battery unit. The reduction of 40 % in usable capacity reduces the overall system performance and must be taken into account by the energy management system. Using the LTO battery unit as an example, the imbalance could be reduced to about 18 % through a manual balancing process, thus increasing the proportion of usable capacity. Furthermore, different SOC states can result in aging differences and thus reduce the service life. Therefore, effective cell balancing algorithms are particularly important in a large-scale battery storage system. With the insight gained in this study it is possible to improve the development of algorithms to address the issue of cell imbalance during operation and optimize the operation of large-scale battery storage systems, thereby contributing to the widespread adoption of sustainable energy solutions.

As renewable energy sources, such as wind and solar, integrated with storage systems, have become more prevalent in the electricity sector, their role has become increasingly important. These resources are termed as inverter-based resources (IBRs), which are based on power electronics and provide rapid response capabilities to grid disturbances, present both opportunities, and challenges. While they offer environmental benefits such as reducing CO2 emissions, the increasing penetration of IBRs can lead to significant stability and protection issues. Japanese regional grids such as Kyushu and Hokkaido with high penetration of IBRs are currently encountering some of these issues such as reduced system inertia, limited short-circuit current contributions, and congestion due to less power transfer capacity. To address these challenges, the government plans to install HVDC lines with a capacity of up to 2 GW by 2030 leading to System Non-synchronous Penetration (SNSP) of 62%, to transfer power from Hokkaido to mainland regions. However, the anticipated increase in stress on the Hokkaido grid, due to both high IBR penetration and HVDC integration, may lead to stability issues such as sub-synchronous oscillation.To accurately predict future situations, it is essential to enhance power system planning and assessment techniques that can adequately include the detailed dynamics of IBRs, which necessitates the use of advanced modeling and simulation methods. The accurate stability analysis requires high-fidelity models of IBRs of grid-following (GFL) control to emulate instability and then mitigate stability issues associated with large-scale grids with substantial RES penetration. Moreover, IBRs with grid-forming (GFM) control can stabilize grids by dynamically adjusting active and reactive power to control voltage, current, and frequency.We proposed a high-fidelity modelling framework as GFL control for existing RES and GFM control for future IBRs. The novelty includes GFM IBRs embedded with flexible synchronization control, virtual inertia support, oscillation damping, virtual admittance, droop support, filter dynamics, and fast current control with limiters to adapt to large disturbances. The framework includes detailed processes for programmatic modeling of the grid from admittance data and it has flexibility to time-domain analysis with a time step of 0.1 ms and small-signal stability analysis.Finally, as results, first we simulated the capabilities of the GFM IBRs under phase jump, frequency ramp, and step voltage change in MATLAB/Simulink. Second, we performed a simulation of the 113-bus synthetic grid of Hokkaido modeled from public data, which demonstrated significant grid instability under certain fault conditions when all IBRs were modeled with GFL control in an increased SNSP of 62%. Third, a simualtion case of potential solution by strategically placing some of the IBR with GFM control demonstrates stable operation with a 72% IBRs as generator in the grid.

In the next years the most countries globally must intensify their efforts towards reduction of greenhouse gas emissions. Green hydrogen, produced sustainably through water electrolysis using renewable energies, is anticipated to play a vital role in this transition towards clean energy. It is estimated that by 2030 a global installed capacity of around 350 gigawatts for water electrolyzers is necessary.The central component is the rectifier, which provides the DC power for the electrolyzer itself. Especially in large-scale electrolyzer units with very high DC current levels rectifiers based on thyristors and diodes are often utilized, which in turn generate large values of harmonics to the supplied voltage and current.The primary goal of this investigation is to minimize the Harmonic Current emission of Electrolyzer plants. This will be achieved by focusing on the optimal design and layout of the Electrolyzer units and their grid components under different operating conditions related to their loading capacity.Modelling of the Hydrogen Plant and its components which are responsible for generation of the harmonics, in DigSILENT PowerFactory and performing simulations in Frequency domain using the Harmonic Load Flow tool and that was the methodology for this investigation. The rectifier of the Electrolyzer units, which seem to be the major source of Harmonic Current emissions are modelled as balanced Harmonic Current sources. For the fundamental frequency and each harmonic order, the current emissions are provided with their magnitudes and phase angles. The harmonic voltages at the different busbars are calculated with the harmonic impedances at the respective busbars.Four main scenarios with respect to the used electrolyzer units and its plant internal grid configuration were developed and furthermore a larger number of operational cases considering the electrical operational limits of available electrolyzers were elaborated.In all scenarios the Electrolyzer plant has a nominal capacity of 80 MW, consisting of different numbers of Electrolyzer units rated either 1 MW or 5 MW. The Electrolyzer plant is located within a short distance to a 120 MW windfarm. Both plants (Electrolyzer and Windfarm) are connected to the HV distribution network via one joint grid connection point (PCC).The large number of simulations run for the different scenarios and operational cases using 12-pulse bridge rectifiers have clearly identified the configuration of each scenario with minimal Harmonic Current emissions on the transmission line to the PCC. This configuration seems to be also optimal using another rectifier technology with different harmonic current spectrum.This investigation demonstrated that the harmonic current emissions of Electrolyzer plants could be strongly reduced using an optimal design and layout of the Electrolyzer units and their grid components, which may lead to better performance, less losses as well to easier connection to the public grid.Further research topics seems reasonable by:

• Modification the semiconductor technology and type used in the rectifiers of the electrolyzer units.
• Implementing measured Current Harmonic spectra of real Electrolzer plants.
• Improving the Electrolyzer model by adding its auxiliary equipment.
• Utilization of a dynamic instead of a static Electrolyzer model.

The currently ongoing shift of electricity production from fossil fuel sources to intermittently available renewable energy sources such as wind and solar power requires the development of highly efficient and cost-effective energy conversion technologies and their deployment on a large scale. In this regard, electrolysis technologies can be key to achieve sector coupling and seasonal energy storage by storing the excess energy in chemical energy in form of hydrogen or synthetic fuels. Among the different technologies, high-temperature solid oxide cells (SOCs) display by far the highest electrical efficiency and and are for this reason a promising technology for clean hydrogen production.However, SOC mainly consist of brittle ceramics and are vulnerable towards mechanical damages due to thermal stresses. Thus, one of the challenges of operating a SOC reactor is to find operating conditions with minimum spatial temperature gradients, e.g. isothermal, and to maintain such conditions in dynamic operation with different inputs to the system. This search can be quite expensive, both in terms of time and cost, if done only via experimental analysis. In addition, operating outside the optimal conditions can lead to irreversible damage to the SOC cells. For these reasons, a simulation framework can be used to find the optimal operating points and define strategies for maintaining such conditions under a plethora of different inputs.At the Institute for Engineering Thermodynamics (TT) of the German Aerospace Center (DLR), a unique test environment for SOC reactors with multiple stack was built, with a maximum electrolysis power of 150kW. In addition, an in-house simulation framework has been developed and validated, which allows to predict accurately the behavior of the reactor and implement complex and potentially risky operating strategies.In this study, we present an algorithm to maintain isothermal operating conditions in a SOC reactor. This algorithm has been created in the aforementioned simulation framework using a 24 stack model for different transient operating conditions, tuning the current demand of the reactor based on the fluctuating supply of fuel. Following, the simulation outcomes are validated in the experimental investigation, where the SOC reactor is operated dynamically, simulating a coupling with fluctuating energy sources. In the manuscript, the cardinal equations of the algorithm, and both simulative and experimental results will be shown in detail, eventually leading to a diminished temperature change of the SOC reactor of maximum 10 K. Ultimately, this approach leads to a faster response from SOC reactors in transient conditions, and can potentially drive a more widespread usage of the technology in combination with fluctuating energy sources. Analysis of the results will be presented to showcase a possible coupling between a SOC reactor and a renewable wind and/or PV source.

In context of energy transition, investigations into wind generation units are becoming increasingly important. Requirements for generators and generator capabilities are evolving and (expected) behaviour of the systems is therefore directly related to connection level and connection year. Capabilities and behaviour of individual generators and wind farms are of increased interest in this context, while high-resolution modelling is faced with high complexity and computing time. Various modelling, clustering and aggregation approaches are therefore used. However, while compressing information this can also cause loss of meaningful data. The german core energy market data register (MaStR) offers publicly available open data containing information on generators, such as rated power, type, wind farm affiliation, voltage level and location. Even more properties like FRT capabilities can be attributed via correlations.In this paper, different cluster and aggregation approaches are applied to the MaStR data and compared. Available information is analysed, the relevance of data and correlated characteristics assessed and data quality evaluated. Methods such as k-means and DBSCAN, as well as combinations of aggregation and clustering are compared. Exemplary models are parameterized and examined in an overvoltage event simulation. The study offers insights for selecting suitable modelling approaches for wind generators and system stability assessments.

ScopeIn recent decades, the share of renewable-based generation has grown rapidly, changing the energy mix of the electric power system. However, the day-to-day operation, especially the provision of ancillary services, still relies on conventional generators due to their on-demand availability. A specific area where the inverter-based resources (IBRs) are still underutilized is the power system restoration (PSR) process. The authors are involved in a research project that aims to provide a decision support system, which includes frequency stability, transient overvoltage, and converter-based stability phenomena. The latter phenomenon is the focus of this paper, more specifically the small-signal modeling of a small network including synchronous generators, transmission lines and cables, and a PV plant.MethodsThe sequence impedance-based small-signal method is used to model the network. The elements are described only in positive sequence, where:

• The transmission lines are considered by their ABCD (frequency dependent) parameters,
• The PV farm impedance is described by the aggregation of 5000 inverters and the collection network characteristics,
• The synchronous generators are considered with constant excitation, while the mechanical dynamics are omitted.

All the impedances are formulated analytically and are validated by frequency scans in Matlab Simulink simulation environment. Based on the impedance model of the entire network, the Bode criterion is used to evaluate converter-grid stability, thus indicating potential resonance problems in several switching states of the network.Main resultsThe stability analysis is performed in each defined switching state of the network. Results show that there are possible operating points where high-frequency resonance occurs. The instability can be avoided by modifying the converter control delay (by carefully selecting the sampling time and the PWM switching frequency), or by fine-tuning the parameters of the LCL filter. The resonances are also validated by EMT simulations.Relevance of the subject matterThe PSR process in conventional generator-dominated networks usually does not take IBRs into consideration, because the operation of most units is weather-dependent and therefore unpredictable. Moreover, reliable IBRs, such as batteries, have not been widely available until recently. However, with the ever-increasing share of renewable energy and storage systems, the PSR process could benefit from such resources.Major conclusionsThis case study shows that under the right environmental conditions, the PSR can rely on IBRs, although the order in which the restoration is performed must take into account the converter stability. These results justify the inclusion of this phenomenon in the aforementioned PSR decision support system.

With the increasing share of renewable generation and inverter-based resources, new providers of grid services like black start capability are required. This paper presents a plant level control concept of a battery energy storage system which allows for an easy and efficient integration of project specific information into one generic controls software. While many black start solutions to date are very project specific and not easy to re-use, this approach enables scalability, reliability and a faster project delivery of black start applications. Based on three different configurations (single busbar, bus coupler and double busbar), the control concept itself as well as the implementation in the Fluence Operating System will be introduced and validated on a hardware-in-the-loop setup. This includes self-supply, black start and hybrid operation modes as well as swapping algorithms for State of Charge balancing.With the increasing share of renewable generation and inverter-based resources, new providers of grid services like black start capability are required. This paper presents a plant level control concept of a battery energy storage system which allows for an easy and efficient integration of project specific information into one generic controls software. While many black start solutions to date are very project specific and not easy to re-use, this approach enables scalability, reliability and a faster project delivery of black start applications. Based on three different configurations (single busbar, bus coupler and double busbar), the control concept itself as well as the implementation in the Fluence Operating System will be introduced and validated on a hardware-in-the-loop setup. This includes self-supply, black start and hybrid operation modes as well as swapping algorithms for State of Charge balancing.

Wind farm control is crucial for maintaining grid stability as it balances power supply and demand, ensuring consistent electricity delivery despite fluctuations in wind conditions. By optimising turbine output and coordinating them as a system, variability is minimised, and grid reliability is enhanced. Advanced control strategies also reduce turbine stress, leading to predictable maintenance schedules and extended lifespans, which further support grid stability. Additionally, maximising power yield ensures full utilisation of renewable energy, reducing reliance on less stable, polluting backup sources.This paper explores the combination of axial induction control (AIC) and wake redirection control (WRC) to address aerodynamic interactions among turbines, such as wake effects that reduce wind speeds for downstream turbines. We examine how these techniques scale with an increasing number of turbines and describe the simulation environments used for validation. Employing the Koopman Model Predictive Control (MPC), a multi-objective controller utilising thrust and yaw control is introduced.Several models and simulation tools are employed:

1. The Jensen/Park and Gaussian/Bastankhah wake models offer simplified representations for initial assessments of the benefits of AIC and WRC.
2. FLORIS software simulates wake effects and optimises yaw control to maximise wind capture by downstream turbines.
3. FAST.Farm integrates higher-fidelity aerodynamic modelling with control solutions, analysing turbine interactions and mechanical loads.
4. WFSim is a control-oriented dynamic model that simulates turbine behaviour under various conditions, supporting the implementation of control algorithms for combined AIC-WRC.

Comparisons of the Jensen and Bastankhah models, along with FLORIS, indicate that WRC provides superior outcomes for a two-turbine setup and scales more effectively when the number of turbines is increased. AIC shows potential improvements ranging from 4% to 19%, while WRC shows improvements from 8% to 30% for a row of turbines facing the wind, with the number of turbines increasing from 2 to 10. Open-loop simulations in WFSim highlight power increases of approximately 10% for a two-turbine wind farm. However, a downside of WRC is an increase in side-by-side moments at the tower base from 2,000 kNm to 14,000 kNm in an open-loop FAST.Farm simulation with two turbines.By combining AIC and WRC, substantial improvements in power reference tracking are demonstrated in WFSim, validating the effectiveness of the Koopman MPC approach. This approach shows a decrease in the root mean square of the tracking error by a factor of 3.9 when compared to an AIC design, from 166.61 kW to 41.77 kW, while producing an average of 2.9 MW in our test scenario.Future work will focus on refining this strategy through extended simulations and integrating machine learning for adaptive control, aiming to enhance scalability to larger farms under complex conditions.

Renewable energy sources (RES) have been installed widely to counter global warming. Since RES are connected to power grids by electronic grid-connected inverters, increased RES may worsen power system stability due to decreased power system inertia. Moreover, RES being installed even in power grids with very low short-circuit capacity may cause interaction problems between the power grids and grid-connected inverters. Grid-forming (GFM) inverters are being researched in many countries worldwide to solve these inertia and interaction problems.The GFM inverter can support power system stability even during power grid disturbances by using the inverter controller's virtual inertia function. However, since the GFM inverter is a voltage source inverter, power system faults may cause an inverter overcurrent, interrupting inverter operation.The authors have proposed an overcurrent suppression control method for the GFM inverter. The proposed control method uses a three-phase AC current controller with three sets of current limiters. The current controller is provided at the output side of the virtual inertial controller. Simulation studies confirmed that the proposed controller effectively suppresses overcurrents in the event of power system faults. However, it was found that the proposed control method causes waveform distortion in the GFM inverter AC currents.This paper proposes a new overcurrent suppression control method and examines the performance of the proposed control method. The new control method uses a multi-loop type GFM controller, which has a current controller and a voltage controller, both designed on a dq-axis base. The current controller uses two sets of current limiters to suppress overcurrents.MATLAB/Simulink simulation studies were conducted to confirm the proposed overcurrent control method. In the simulation model, a GFM inverter is connected to an infinite bus through a harmonic filter and a transmission line. The power system disturbance is a three-phase-to-ground fault at the middle point of the transmission line.Simulation results showed that the GFM inverter current is effectively suppressed at the limit (1.5pu) or less during the ground fault. Moreover, the waveform distortion of the GFM inverter current observed in the previous control method was eliminated. On the other hand, after the overcurrent, the GFM inverter's active and reactive power outputs tend to diverge. The estimated reason is a loss of phase synchronization. The phase angle calculated in the GFM inverter main controller may not follow a rapid change in the grid side voltage's phase angle during and after the fault.The full paper will propose improving the multi-loop type overcurrent suppression control method to maintain phase synchronization.

Power-to-liquid (PtL) fuels will be vital in achieving carbon neutrality. This study uses the newly developed energy system optimisation model EMPRISE-Chile to analyse the market-based export potential of PtX fuels from Chile on the path to 2050. EMPRISE-Chile is a sector-integrated energy system model instance for the cost-optimisation of capacity expansions in five-year steps. Our analysis shows that under the assumptions made, Chile is able to phase out the use of fossil resources and significantly export Fischer-Tropsch fuels in 2030, 2040 and 2050 at competitive national market prices. The study focuses on the impact of exogenously predetermined export volumes, CO2 budgets, and expansion limits for 2030, 2040, and 2050. The achievable export volumes and corresponding prices are discussed from a European perspective. Finally, it is presented that the necessary expansion rates for Chile’s wind and solar power plants must be significantly higher than historical values in all cases.

Accurate modeling of existing and future renewable generation is essential for planning the European energy system. Current models often neglect or oversimplify the physics of wind farm generation. While detailed modeling is possible, it is impractical for representing the entire fleet of thousands of wind power plants.This study addresses these challenges by implementing a generic wind farm surrogate model within Correlations in Renewable Energy Sources (CorRES) tool, capable of simulating all existing wind farms in Europe over a 40-year period with hourly resolution. The model incorporates a single turbine power curve that accounts for turbulence intensity (TI) and time-varying air density, alongside other relevant parameters such as specific power and rotor diameter. The wind farm power curve and wake losses are modeled to also depend on turbulence intensity and air density, as well as other key parameters like plant installation density and the number of turbines in a farm.A comparative analysis is conducted between previous generation simulations of CorRES and those incorporating time-varying air density and fixed turbulence intensity, differentiating between offshore and onshore wind farms. The results demonstrate that incorporating time-varying air density enhances the capture of seasonal variability, which is crucial for energy system models to effectively meet electricity demand for heating and cooling with renewable energy sources.

Accurately determining the contribution of short-circuit currents (SCC) from different sources is crucial for preventing protection relay mis-coordination, equipment damage, and blackouts. However, standards often provide a simplified view or lack information when it comes to inverter-based resources (IBRs). For instance, the response of conventional grid-following inverters during faults may vary considerably from expected values in standards due to factors such as terminal voltages, sequence component priority, and grid code requirements. Furthermore, recent working groups have proposed the use of look-up tables (LUTs) provided by manufacturers to represent the short-circuit current. From an original equipment manufacturer (OEM) point of view, the use of such look-up tables can be complex and also cause errors in the current estimation. To address this, a method has been proposed to provide more accurate SCC estimates during steady-state conditions using a black-box IBR current calculation component developed in collaboration between a Type IV Wind Turbine Generator (WTG) OEM and a short-circuit and relay coordination software provider. This method utilizes a steady-state phasor-based network solution and involves the use of a dynamic link library (DLL) provided by the OEM to compute and return the expected three-phase IBR injection currents, which are then used to re-compute the terminal voltages in an iterative process. Simulations in EMT domain were performed to validate the results, and the paper discusses the general possibilities and limitations of this methodology.

As the penetration of renewable, inverter-connected energy sources increases, the relative inertia of the power system decreases. Consequently, there are indications that the frequency quality, the ability to keep the active power balance, is declining. During normal circumstances, primary frequency control is the ancillary service the system operator uses to contain the frequency within a nominal band. Traditionally, the providers of primary frequency control are synchronous generators, but recently, new providers have begun to enter the primary frequency reserve market. Thus, it is essential to study how the service-providing units' properties affect the power system's frequency quality.In this study, several performance metrics are defined to describe the step and impulse response, as well as the stability margin, of a power system with a primary frequency control unit and a low inertia power system. These performance metrics quantify the unit's properties. The correlation between the defined metrics and frequency quality could be calculated by studying the frequency quality when a stochastic power imbalance is added to the power system. The study found significant correlations between metrics derived from the closed-loop system and frequency quality, where metrics for the activation speed correlated with frequency deviation and metrics for oscillation reduction were correlated with the rate of change of frequency.

Integrating offshore wind farms into existing power systems raises significant challenges, particularly in maintaining voltage stability. In this context, conventional on-load tap-changers provide essential voltage control. However, they are limited to steady-state adjustments due to the motor-driven response time. Therefore, this paper introduces a voltage control method that enhances on-load tap-changers by incorporating power electronic fast-switching modules. The proposed solution enables rapid and flexible transformer tap ratio adjustment, significantly improving the voltage stability of offshore wind farms during high-voltage ride-through events under strong and weak grid conditions. The fast-switching module demonstrates enhanced performance in minimizing voltage deviations and reducing the risk of disconnecting wind turbine generators related to overvoltages.

Distribution grids are facing significant changes. Investigations into power quality (PQ) phenomena are necessary to ensure a reliable and disruption-free power supply. There are generally few PQ measurement devices installed in lower voltage levels and installation is event-related or temporary. Future scenarios, which will affect connected devices, equipment, grid operation and customer behaviour are not represented in measurement data. Simulations are necessary to depict these changes. Electromagnetic Transient (EMT) simulations are suitable to map the influence of individual components, controls and dynamic relationships and simulate the entirety of phenomena. However, large-scale EMT simulations require significant computational effort, even though most time step results are quasi-stationary. Here we present a concept for combined three-phase timeseries power flow and EMT simulation to investigate power quality. To model the supply task with high temporal resolution and phase accuracy, considering e.g. self-consumption optimization or dynamic price incentives, power flow simulations are used. Based on these results, periods indicating power quality violations or non-quasi-stationary behaviour are identified. The operating points of the decentralized components within these identified relevant grid usage cases (including power flow results) and the time ranges are then used to initialize detailed EMT simulations.

This contribution aims to examine the large-scale impact of renewable energy communities (RECs) on the distribution grid based on Austrian legislation. Despite RECs recent growth, a critical level in total load has not been reached and the behaviour of energy communities is therefore not accounted for in grid planning. However, with expected further progress, RECs most likely need to be taken into consideration and it is of absolute neccessity to examine their grid impact.Questions to be answered are whether RECs influence the grid's state in the first place and subsequently, if a positive or negative grid impact is observed.Moreover, a large-scale sensitivity analysis considering the integration of renewables and flexibilities is performed.To investigate stated questions, this work adheres to the following methodology. At first, several deterministic scenarios are constructed. To allow for a differentiation of the grid impact, a community case shall consistently be compared to a non-community case. For the community case, the flexibilities and the community internal trading shall be optimized with the objective of community-wide minimization of total expenditures. The non-community case, on the other hand, is optimized with an individual minimization of each households cost. To perform a grid analysis, these load profiles then undergo a static, iterative load flow calculation based on representative real-world grid models in both rural, suburban and urban areas with terminal voltages, lines and transformers thermal loading as output variables. First of all, the grid impact and scenario clearly correlate: With increasing renewable and flexibility installation and a "de-urbanization" of the scenario the deviation between the community and non-community case grid parameters increases. In general, it can be said, that the RECs internal assets are typically loaded more when compared to the non-community case while the RECs residual load is slightly lowered. However, the communities impact greatly depends on externalities such as the scenario and meteorological circumstances. Therefore, RECs neither automatically aid nor harm the grid.

Integrating inverter-based resources (IBRs) is becoming crucial in transitioning to more sustainable and renewable energy sources. The increasing integration of IBRs into the power system leads to complexity and challenges regarding ancillary services, reliability, and power system operation. Hence, through grid codes, obligatory regulations have been introduced to be pursued by customers to impose control capability on IBR plants. A power plant controller (PPC) plays a vital role in managing the output of IBRs to comply with grid code requirements. Unlike traditional grid-following controllers, which rely on the presence of a stable grid and may not provide very effective ancillary services during disturbances, a grid-forming PPC can establish and maintain grid stability independently and fulfil the grid code requirements at the point of common coupling (PCC) even under weak grid conditions and during disturbances. Therefore, this paper concentrates on the innovative concept of grid-forming PPC to enhance grid stability and compliance by integrating battery energy storage systems (BESSs) in a large-scale photovoltaic (PV) power plant. Grid-forming PPC coordinates the production of individual IBR units, adjusts their output in response to grid conditions and faults, and actively contributes to grid stability by regulating voltage and frequency.

The process of returning the power post-blackout, Blackstart, can be achieved through the use of grid forming resources, such as generators, battery energy storage systems (BESS) and other systems which do not require grid power. Black start capabilities are a necessary part of supporting efforts to transition to renewable power generation, as these capabilities help increase resilience in renewable dominated grid networks. This is also important in remote areas like Scottish islands which are not connected to the national grid. In many cases, they use renewables as a primary source of electricity, while still having a heavy reliance on fossil fuels for heating and transport. Hydrogen has been a promising alternative fuel option, which can be obtained from renewable sources such as wind powered electrolysers. However, wind powering electrolysers is a unique challenge, as wind power fluctuates while electrolysers are designed for constant power sources. As a result, it is beneficial to have a system in more remote areas with black start capabilities to enable complete restart if required. This paper explores the energisation process for a small scale isolated wind farm connected to an electrolyser, using a turbine with grid forming control (GFM) to perform blackstart.

The transition towards smart grids necessitates advanced information and communication technology to manage the increased complexity of energy systems, where households are evolving into prosumers by both consuming and producing energy. The German government has accelerated the deployment of smart metering systems through legislative measures, introducing the Smart Meter Gateway (SMGW) to collect data and facilitate communication between local systems and external market participants. This paper examines how the German smart meter infrastructure, within its existing regulatory framework, can be leveraged for peer-to-peer communication.Smart meters in Germany are governed by high standards and detailed use cases as outlined in the Technical Guideline TR-03109 from the Federal Office for Information Security (BSI). Various actors, including Gateway Administrators (GWA), Controllable Local Systems (CLS), and External Market Participants (EMP), are involved in the system. CLS operate within the home area network (HAN), while EMPs function in the wide area network (WAN), receiving and utilizing data from the SMGW. An EMP becomes an active External Market Participant (aEMP) when it communicates with CLS via the SMGW.Two critical communication scenarios, HAN Communication Scenario 3 (HCS3) and Scenario 4 (HCS4), establish the CLS-Proxy function, enabling communication between the HAN and WAN. HCS3 involves a CLS initiating communication to an aEMP, while HCS4 allows an aEMP to request a communication channel to a CLS through the GWA. These scenarios can be used to support peer-to-peer communication between two separate CLSs connected to different SMGW within the existing regulatory framework but require complex intermediary steps and introduce potential points of failure.To enhance direct communication between CLS devices, a new concept is proposed. This involves a time-limited announcement phase enabling SMGWs to accept connections from each other directly, thus reducing dependency on the aEMP and improving communication efficiency. This approach simplifies the process by allowing SMGWs to establish connections directly, enhancing privacy and reducing complexity.Implementing this extension requires regulatory adjustments, including modifications to the Protection Profile and Technical Guidelines to allow SMGWs to act as servers in the WAN. These changes would enable secure, certificate-based client authentication within the SM-PKI framework, facilitating more efficient and secure peer-to-peer communication.This study underscores the potential for existing smart meter infrastructure to support advanced communication scenarios, thereby enhancing the functionality and efficiency of smart grids. It highlights both the challenges and opportunities in evolving the regulatory framework to enable direct, secure, and efficient communication between distributed energy systems. By addressing these challenges, the proposed enhancements can significantly contribute to the development of a more resilient and intelligent energy system.

Due to their fast controls, inverter-based resources (IBR, incl. HVDC VSC/MMC) can interact with the network impedance as well as with other converters or rotating machines in a wider frequency range, compared to conventional synchronous generators. This increases the risk of resonances which might be well damped, poorly damped or even unstable at sub-synchronous as well as super-synchronous frequencies. The impedance-based stability analysis approach is a suitable method for investigating the small signal stability of grid connected IBRs in the frequency domain. For the investigation of larger IBR-dominated power systems, network analysis software tools are required for a system-wide analysis considering different relevant operating points, switching statuses of the network including planned outages or unplanned contingencies.This paper focuses on the approach of using the frequency sweep function of a power system analysis software’s power quality assessment toolbox in the frequency domain. The pros and cons of deriving the frequency-dependent power system impedance in the frequency domain versus impedance scan via EMT simulation in the time domain are discussed.The frequency sweep function, which is typically used for power quality assessment in the frequency domain, is able to determine resonance frequencies and to predict whether a resonance is stable or unstable, as will be shown and explained in the paper. Provided that suitable frequency-dependent impedance characteristics of IBRs and rotating generators are given (or can be derived), the frequency sweep function is straight-forward to use, is comparably fast and easy to handle. Results can be obtained even if the power system model is not sufficient for load flow calculation or EMT simulation.For complete stability analysis however, the frequency sweep function has to be extended in order to determine stability margins by analysing the loop gain function of IBRs with the network through the Nyquist criterion. Such extensions by additionally implemented Python scripts for SISO (single input single output) and MIMO (multiple input multiple output) systems have been exemplary realised. With this, the stability analysis of a single IBR connected to an existing stable grid for grid connection compliance studies, as well as the analysis of a complete power system as a MIMO system at once are possible. The authors discuss the advantages and challenges for practical application from their perspective and experience, illustrated by examples, which can include grid-following and grid-forming IBRs as well as synchronous generators. The discussion includes considerations related to input data quality regarding the frequency resolution, frequency ranges of provided impedance characteristics, and operating point dependency, as well as aspects for large power systems.

Integrating energy storage in solar PV plants holds significant potential to enhance revenue streams by optimizing energy dispatch and capitalizing on peak electricity prices. While the initial investment costs for storage systems can be substantial, the ability to store excess solar energy and release it during high-price periods can lead to higher profitability. Moreover, Solar-to-X (SOLARX) is emerging as a promising renewable energy source to mitigate the impacts of climate change by integrating and synergistically managing a single facility that produces heat, electricity, or other energy vectors based on demand and prices. Thus, exploring further storage options, more efficient photovoltaic (PV) cell technologies, and alternative revenue streams in SOLARX is critical, especially as it expands to include hydrogen and heat energy vectors. This paper investigates the feasibility and profitability of solar and battery hybrid power plants in Northern Europe. The study conducted for Northern Europe demonstrates the potential for improved profitability of solar plants through the inclusion of battery energy storage and other energy vectors such as hydrogen.

The risk of blackouts caused by voltage instability grows with the continuous expansion of renewable energy sources (RES) in the system.This paper addresses the changing requirements for ensuring voltage stability resulting from the transition to inverter-dominated networks. Using the well-known Nordic Test System modifications from 0% to 35% and 50% share of RES in the total energy mix were made.The test network is built in DIgSILENT PowerFactory.Various key performance indicators (KPIs) are used to analyze and compare the different RES expansion scenarios.A dynamic system analysis has been carried out and evaluated in the test systems with different proportions of RES concerning the effects on voltage stability. Countermeasures are proposed utilizing additional reactive power sources as STATCOM devices to overcome the emerging stability issues.

The accurate modelling of underground power cables in medium voltage (MV) grids within the frequency domain is essential for ensuring a quality computation in the frequency domain. This is particularly crucial in renewable power generation systems, where MV reticulation plays a key role in integrating various energy sources into the grid. This paper delves into the critical aspects of frequency-domain modelling for MV power cables, emphasizing the characterization of their electrical properties and the influence of frequency-dependent parameters on power transmission. The study addresses the mathematical formulations, physical parameters and cable construction characteristics required to represent cable impedance and admittance.This is part of a research project, which is based on original analysis and mathematical formulation derived from existing literature. We explore a theoretical approach to develop comprehensive models that ensure a good quantification on the frequency domain cable behaviour across a broad frequency spectrum. Various modelling techniques are evaluated for precision and effectiveness, including lumped parameter models, distributed parameter models, and more complex models. Through detailed case studies, the practical implications of these models are demonstrated.Our findings provide valuable insights into how to model a power system effectively, considering the length of the cable and determining the most suitable model for different cable lengths. These results are crucial for optimizing cable design.

Across Europe the expected hydrogen ramp up is accelerating while current standards and requirements regarding controllable loads are insufficient to guarantee system security. European legislation to implement new rules can’t keep up with this dynamic.For instance the German government's targets envisage an expansion of electrolysis plants in the order of several gigawatts of demand capacity to the end of this decade.In order to ensure rapid expansion of electrolysis capacities and in the same time continue the secure operation of the grid, technical requirements for connection to the German high and extra-high voltage grid must be met. The four transmission system operators in Germany have formulated a consolidated position on these basic requirements for electrolysis facilities, which will be needed in the future to ensure system stability.The system requirements and functions relate to the point of connection of the electrolysis facility. This means that it is also possible for facility operators to fulfil the requirements with additional equipment. These requirements will likely have an impact on system security and electrolysis facility design which will extend beyond borders.

This paper discusses the upcoming challenges for the Ireland and Northern Ireland power system due to the significant integration of solar photovoltaic (PV). The Irish Government has set a target for 8 GW of solar capacity, both utility-scale and embedded, by 2030. The small island nature of the system, coupled with limited HVDC interconnections and an expected summer midday demand of 6.5 GW in 2030, presents considerable operational complexities. This paper identifies four potential challenges for the all-island power system: minimum operational demand, ramping effect, short-term variations, and post-fault behaviour. In 2030, with 2.5 GW of embedded PV capacity, sunny days may result in very low demand conditions, imposing challenges to maintain system stability. The paper also highlights potential ramping risks during daily load trends and rare events. Additionally, increasing short-term solar generation variations pose challenges like frequency fluctuations and voltage degradation. Post-fault distributed PV (DPV) tripping also poses risks for system security. This paper examines the risks and outlines recommendations for addressing these issues in light of the All-Island power system’s unique characteristics and developments.

In anticipation of the future interconnection of large-scale wind power plants, grid interconnection regulation that limits the output ramp rate limit of domestic wind power plants to "10% for 5 minutes" came into force in 2020. The authors have previously clarified the impact of the output ramp rate limit on the frequency fluctuation of the power system through numerical simulations using the EAST 10-machine System Model developed by the Institute of Electrical Engineers of Japan. However, the EAST 10-machine System Model was not necessarily suitable for steady-state frequency analysis, and further analysis using a generalized model was necessary. In this paper, we conducted a similar study using the AGC30 model which was also developed by the Institute of Electrical Engineers of Japan, a standard analysis model for frequency simulation that can simulate frequency fluctuations in more detail than the EAST 10-machine System Model, and clarified that there was no significant difference depending on whether the output ramp rate limit for wind power plants is applied or not, and that it is important to distinguish between having the function and utilization.

During an offshore wind power plant (OF-WPP) development, various equipment vendors such as STATCOMs and synchronous condensers provide a full-scale black-boxed model of their components to prevent their intellectual property and to avoid unwanted changes in the internal control structure and parameters. Such models are utilized for various time-domain studies; however, insights into small-signal and converter-driven stability miss out due to the lack of small-signal models. In order to perform a small-signal stability study of the entire OF-WPP with the possibility of extracting stability information from the black-box model components, advanced methods such as vector fitting are required. Vector fitting estimates the state-space model of the black-boxed system component from which the overall state-space model of the OF-WPP can be built, thus facilitating an overall small-signal stability analysis, which can provide insights into the source of system instability via modal analysis. This paper presents the application of vector-fitting methods on various OF-WPP components from their immittance scans to estimate the small-signal model of the component. A validation of the vector fit results against EMT-based and frequency domain model (FDM) based immittance scans are provided to demonstrate the accuracy of the proposed method. The results show that crucial model information can be extracted from the immittance scans of the black-boxed component models without the vendors needing to provide IP-protected internal model parameters explicitly. The extracted model information can be utilized for the overall small-signal stability analysis of the WPP.

The integration of high shares of renewable energy in the EU poses challenges such as grid stability, congestion, and balancing intermittent supply. A key issue is the costly and time-consuming need for grid upgrades to accommodate high renewable infeed. This paper proposes co-locating green hydrogen production with wind and solar plants as a solution, optimizing grid capacity use and reducing reliance on extensive grid expansions. The major contribution of this paper is the analysis of the technical and economic benefits of co-locating GW-scale green hydrogen, wind, and solar facilities. This approach enables direct balancing of renewable generation with hydrogen consumption, minimizing grid impacts. However, challenges arise from the interaction of power electronics converters, which can affect power quality and grid stability. The paper provides a detailed assessment of the electromagnetic transient (EMT) impacts of such co-location, highlighting the need for improved grid-following/forming technology and addressing dynamic stability issues. The findings offer critical insights into the design of integrated renewable energy systems and recommend further research to ensure safe and efficient operation during normal and fault conditions.

A decade ago, the discussion of “wind integration” focused on how to integrate 10% or more of wind in an otherwise unchanged power system. The target for a decade from now is for wind and solar to produce about 80% of the energy generation and be the backbone of the energy system in Europe and other areas in the world. Forecasting for the weather-driven energy system is pivotal to the success of integrating the amounts of wind and solar generation necessary to reach these goals. However, understanding the time-scales of prediction models in order to develop and apply the most suitable forecasting tools and input information for each type of energy system application is a challenging task. In order to address this, the inter-disciplinary and international group operating under IEA Wind Task 51 has started to interact with other IEA Tasks and Technical Cooperation Programs (TCPs) within the IEA to improve forecasting for all aspects of the weather-driven energy system.The goal is to improve the performance and use of wind and solar power generation forecasts from the minute-scale to the seasonal scale, and thereby increase the value obtained from them while minimizing the risk of variable generation to energy systems. The challenges and limitations that come with these methodologies is crucial for an energy system whose role is steadily expanding to meet the needs of a society that is rapidly increasing its use of data and artificial intelligence tools while it is targeting a carbon-neutral status. The Task 51 program is organized across 3 work packages (Atmospheric Physics, Conversion to User Variables, End Use) and spans 13 work streams, e.g. minute scale forecasting, seasonal forecasting, decision-making under uncertainty, data quality assessment, data sharing, the value of forecasting or extreme power system events.At the end of 2022, the IEA Wind Recommended Practice for the Implementation of Renewable Energy Forecasting Solutions was released as an OpenAccess book, which is freely available in the electronic version to ensure that the industry has access to the recommendations, also in the underserved markets and for newcomers to renewable energy integration.The Task 51 activities are closely connected with industry and academia to ensure that recommendations are proven and a precursor to an industry standard. This can pave the way for industry to move in the direction of adopting best practices based on what has been learned from the experiences of the industry’s first movers.To address the wide range of forecasting time-scales necessary for the energy system applications, the focus is on seasonal and on minute-to-second-scale forecasting as well as data-driven methods (AI). We will summarise the results from three recent workshops on these topics to initiate a discussion on future requirements for an energy system in which renewable generation resources will provide in the excess of 50% of energy consumption in many regions.

In 2018 a new working group has been formed under IECRE, the IEC System for Certification to Standards Relating to Equipment for Use in Renewable Energy Applications. It’s task was to establish an internationally accepted certification scheme on the electrical characteristics of renewable energy (RE) power generating facilities in the domain of wind, solar and marine energy with respect to respective grid connection requirements on these installations. Such requirements are typically documented in grid codes which are specified by power system operators, but also on legislative basis (e.g. the European Network Codes, ENC) or by standards (e.g. EN 50549-1/-2).As until 2023 such certification schemes, formally aligned to the accreditation standards ISO/IEC 17065 and ISO/IEC 17067, only existed on national level, i.e. in Spain and Germany, or as house schemes by individual certification bodies. Accordingly, there was also a high interest by European stakeholders like ENTSO-E and on industry level on how such an international approach by IECRE may be facilitated for the benefit of equipment certificates as introduced by the ENC.It is correspondingly pleasing that the working group has reached a first milestone in late 2023 when the certification scheme has been published as OD 009 within IECRE. This scheme is in its actual version applicable to RE power generating units (PGU), like wind turbines, PV inverters or respective marine energy converters. An extension to components of such systems is in the scope of the current work.It has, however, to be noted, that for formal reasons the scheme may not be applied for the conformity assessment with respect to single national grid codes, as these do not provide an acknowledged standard. Instead, the scheme provides a formalized option for the so-called capability certification, which, basically, provides a conformity statement that the capability of a PGU in terms of its electrical characteristics comply with the declaration as stated by the PGU’s manufacturer. Based on these capability certificates a conformity assessment with respect to individual grid code requirements can easily derived, e.g. based on a simple gap analyses. Hence, the OD 009 certification scheme provides an efficient way for the wind, solar and marine energy industry to serve different national grid code provisions. This is insofar good news, as also the EN standard 50549-10 provides a scheme on capability testing.The presentation will introduce the certification scheme OD 009 as well as the general framework for certification within the IECRE. It sketches how capability certificates under OD 009 may be extended to national grid code certification. It outlines the current work to extend the scheme with respect to component certification, model validation and family grouping. Finally, it provides an outlook how the scheme may be linked to the coming up requirements on equipment certificates as stipulated in the available drafts on the ENC revisions.The author is the convenor of the respective WG 010 within IECRE.[Note to the reviewer: the full paper may be submitted by a consortium of FGH, EFAC, WindEurope and possibly other stakeholder associations – however the votes on this could not be concluded in due time so far]

This paper investigates the transient performance of grid-forming (GFM) converters during power reference regulation. It is revealed that implementing fast power control induces a rapid fast voltage source behavior, which, however, compromises the GFM capability. Furthermore, the decoupling control of active and reactive power responses leads to larger voltage magnitude fluctuations, thereby sacrificing the ability to maintain a stiff voltage source. To address those trade-offs, an adaptive control strategy is proposed, which is activated only during power reference regulation to achieve fast and decoupled power control. The GFM converter, utilizing the proposed control method, successfully achieves fast power regulation while minimizing the power coupling. Both simulation and experimental results validate the theoretical analysis.

In recent years, there has been a growing recognition of the largely invisible yet crucial role that synchronous machines play in forming the grid voltage and maintaining synchronism among generators. Consequently, given the increasing contribution of renewable energy sources (RES), integrating grid-forming (GFM) controls into wind turbines, PV power plants, and batteries is considered essential for achieving (near) 100% renewable energy targets, given their capacity to deliver a wide array of system services vital for maintaining system stability and ensuring reliable power system operation. However, power converters face limitations related to their overcurrent capacity, which contribute to the gradual weakening of power systems over time. While solutions such as upscaling GFM converters, or deploying synchronous condensers are proposed, they entail substantial costs.To address these challenges and enhance the economic viability of wind power amidst the increasing share of RES, evolving dynamics, and GFM requirements, this paper explores the application of hydrostatic transmission (HST) technology in wind turbines. A specific focus is placed on Type 5 hydrostatic transmission-based wind turbines (HSWTs), and this research investigates how replacing traditional mechanical gearbox and power converter setups with robust HST systems to drive grid-connected synchronous generators offers a transformative shift in wind turbine design. Potentially, HSWTs not only enhance reliability, reduce maintenance requirements, and extend operational lifespans, but also exhibit inherent capabilities similar to synchronous machines. These capabilities are crucial for ensuring system stability and flexibility in high-RES integration scenarios. Additionally, HSWTs can operate as synchronous condensers to regulate reactive power and stabilise local voltage levels during low wind conditions, thereby diversifying revenue streams by offering various system services. Moreover, the integration of a hydraulic accumulator for short-term energy storage further enhances system service capabilities while reducing maintenance needs. HSWTs have lower efficiency compared to power converter-based wind turbines, particularly at partial load operation. However, advances in fluid power technology have renewed interest in their potential.Despite the potential benefits of HSWTs, limited research has been conducted on their comparison with power converter-based wind turbines. Therefore, this paper presents a comparison of the available technologies, covering key aspects such as design, efficiency, and maintenance. Maintenance implications specific to HSWTs are also presented, focusing on constraints relating to accumulator charge/discharge depth and other critical internal parameters. Finally, an evaluation is conducted on potential future system services offered by HSWTs, highlighting their capability to address gaps that converter-based generators may lack, such as fault current contribution, fast post-fault active power recovery, and dynamic reactive response. By addressing maintenance considerations, fine-tuning internal parameters, and anticipating future service capabilities, this research aims to advance HSWT technology and position these turbines as important assets in the transition towards sustainable RES integration, ultimately contributing to the realization of net-zero power systems.

In Germany, wind energy is reshaping the electricity landscape, notably by increasing energy input in the northern regions. This renewable energy must traverse the occasionally saturated electrical networks to the south, testing the system's capacity limits. An effective solution to this problem of limited transmission capacity is Dynamic Line Rating (DLR), which makes it possible to increase the load on the power lines under certain weather conditions. Numerical weather predictions (NWP) are used to forecast the potential grid load for the weather-based DLR and predict critical parameters such as wind speed and temperature for the downstream processes. However, the accuracy of the forecasts is sometimes impaired by the complex topography and dense vegetation along some power lines. To enhance these predictions and tailor them to local nuances, a post-processing method has been developed. This post-processing model works universally, i.e., it can be applied at any location. A two-stage method is used: First, ordinary kriging performs a downscaling from the model grid points to the prediction point. In the second step, a universal machine learning model (ML model) is trained that integrates not only weather model forecasts, but also static terrain information such as terrain position index (TPI), slope inclination, land cover classes and wind statistics. The forecast horizon for the evaluation refers to the following day. We investigated and tested various approaches to develop the optimal ML model: A simple artificial neural network (ANN) with only one hidden layer served as a reference model. To better account for terrain characteristics, an advanced model in the form of a Long Short Term Memory (LSTM) was tested and fine-tuned through hyperparameter optimization. The quality of these models is verified using independent measurement stations.This presentation covers the complete forecasting process, encompassing pre-processing, the training phase with model selection, and the achieved results.

In modern power systems, distributed energy resources will be increasingly demanded to provide dynamic ancillary services. Renewable energy resources with many decentralized generation plants feed, as opposed to large centralized conventional bulk power plants in the grid. To formalize the requirement for the desired dynamics from the grid operator's point of view for the provision of fast frequency response and voltage maintenance for power plant operators, a method of aggregation and suitable de-aggregation was proposed in [1]. Experimental validation was presented for a specific setting in [2].The core concept of that approach is to initially combine a sufficient number of distributed generation plants into a virtual power plant concerning the available average power. A reference model quantitatively describes the desired dynamic behavior of all distributed energy resources in an aggregated form for this setting. The entire transfer function is then divided into partial transfer functions that describe the desired dynamics of the individual generation plants of the virtual power plant. These partial desired transfer functions form the initial point of model reference control of photovoltaic and wind power plants presented in this study.In the model reference method, the desired closed-loop system is specified. In this case, with the distributed power plants, the transmission behavior between the reference active power and reactive power and the fed-in power is first determined. The controller coefficients are then calculated based on a given plant model and the structure of the control system. This paper shows how controller coefficients can be calculated for a generic model of a type 4 wind turbine and photovoltaic power system to fulfill the requirements for the partial reference models. Using the wind turbine as an example, the coefficients of the model controller are calculated using a set of proposed LMI conditions. The design process is described in detail, including a controller performance test under different wind speed conditions.[1] Marinescu, B.; Gomis-Bellmunt, O.; Dörfler, F.; Schulte, H.; Sigrist, L.: Dynamic Virtual Power Plant: A New Concept for Grid Integration of Renewable Energy Sources. In: IEEE Access, 2022, doi: 10.1109/ACCESS.2022.3205731\\[2] Andrejewski, M.; Häberle, V.; Goldschmidt, N.; Dörfler, F.; Schulte, H.: Experimental Validation of a Dynamic Virtual Power Plant Concept Based on Multiple-Converter Power Hardware-In-the-Loop Test Bench. In: Proceedings 22nd Wind and Solar Integration Workshop. Denmark: 2023.

Australia is preparing to build, connect and operate its first Renewable Energy Zone (REZ). This consists of the construction of transmission network infrastructure and supporting components in order to connect at least 4.5 GW of renewable energy generators and storage across 16 points of connection to the REZ (a maximum of 11 GW may ultimately be connected). Under existing regulations, lengthy and costly simulation studies are necessary to connect any renewable generator project to the Australian network. For example, time-domain based assessment of generator stability for an indeterminate number of operating scenarios is a common prerequisite for connecting generators, often in response to varying requirements being requested by the operator. Such requirements have caused substantial delays in the time required to many projects and in turn, increased necessary expenditure by the proponents. The intending network operator, ACEREZ, has developed a revision to the existing processes, in an effort to reduce complexity and time/cost required to be committed by the proponent. The proposal involves the use of frequency domain modelling for the purposes of screening and identifying operational scenarios that may lead to controller small-signal stability concerns between each of the generators and the wider system. Further, such activities aims to support the assessment of harmonic emission levels throughout the REZ and provide a detailed representation of network, its connected generators and the wider Australian network in the frequency domain. ACEREZ has been engaging with generators, OEMs, consultants and supporting engineers in order to deliver the proposed process and align outputs with the required data to undertake detailed assessments. This presentation will present the challenges of the existing process of assessing generator stability, provide an overview of the process being implemented, detail early findings and outcomes to date, provide an overview of the remaining work to be completed and challenges identified.

Panel Discussion of Forecasting and Data Needs for the Weather Driven Energy System

Inspirational Short-Talk: Standard for Forecasting and Evaluation of Wind and Solar in an Energy System with 100% Renewables

Panel Discussion on Needs and Interests for the Development of a Standard

Review of the Minute-Scale Forecasting Workshops and Resulting Activities

The ongoing transformation of the electrical power system in various parts of the world raises the question of how and to what extent inverters with grid-forming capabilities can be installed ensuring power system stability at very high share of inverter-based generation. While a systemic need for a certain portion of grid-forming power plants is widely confirmed, the method to determine the exact need and the quantification and testing of the grid-forming capability is under discussion. Germany has chosen a two-stage approach to meet the systemic demand for grid-forming capabilities as quickly as possible. In a first step, Germany plans for the new market-based ancillary service “inertia” by the TSOs from 2025. In a second step, based on the national implementation of the European network code “requirements for generators” (RfG2.0), a certain minimum inertia capability is expected to become a mandatory requirement for newly connected large power plants from 2027/28. The inertia market is considered a vital means and incentive for rapid establishment of grid-forming capabilities in the grid. It shall allow for the fast achievement of essential core properties such as voltage source behaviour or phase jump power from inverter-based grid-forming power plants while procuring power reserves to encounter power deficit and surplus in the grid, based on positive and negative inertia products, respectively. The German approach to translating the indistinct term “grid-forming” into such inertia products is presented, and their quantification and validation are elaborated upon by giving an overview of technical requirements, as well as corresponding verification procedures as prerequisites for participation in the inertia market.

The Impact of Variable Renewable Energy (VRE) on the Power System Stability – The Renaissance of Synchronous CondensersThe energy transition, i.e. the strategic change from fossil fuels to renewable energy sources, entails a fundamental transformation of the transmission and distribution grids. The electric power system is in transition which shifts from a rotating mass-dominated system to a power converter-dominated system. Without the appropriate measures, this will have a negative impact on power system stability. This report describes the implications of the transformation of the electric power system on voltage stability and frequency stability, it compares Synchronous Condensers (SynCon), SVCs (static VAR compensation) and static synchronous compensators (STATCOM) with regard to the different grid needs. SynCons, which have been used for reactive power compensation since the early 20th century, and have been replaced by other technologies in the meantime, are experiencing a renaissance in transmission and distribution grids.

Inverter-based resources (IBRs) are pivotal in modern power systems to meet the net-zero carbon targets. The rapid integration of IBRs such as solar photovoltaics, wind turbines, and battery storage has introduced complex dynamic behaviours that challenge conventional power system stability paradigms. Unlike traditional synchronous generators, which are governed by standardized, physics-based models, IBRs are control-defined and feature vendor-specific models that operate across multiple overlapping time scales. This results in unique dynamic interactions in IBR-dominated grids with multiple causalities, giving rise to oscillatory phenomena not previously encountered. This paper provides a review of IBR-driven oscillations, emphasizing on their classification and current research efforts in oscillation tracing and mitigation. Two classification framework based on time-scale separation and causality, are explored to categorize IBR-induced oscillations, highlighting the challenges in the categorization process. The critical role of data, tools and methods for tracing oscillations is discussed, and current mitigation measures are outlined in the context of IBR-dominated system. Additionally, some open research questions related to the evolving landscape of IBR-induced oscillatory phenomena are discussed.

Control Architectures for the Interoperability of Hybrid Power Plants

Co-location of wind, solar and energy storage opens new opportunities for developing renewable energy plants and providing a better electrical energy product. In a European context rightsizing of technologies purely based on a techno-economic optimisation is hardly possible as many different factors needs to be considered.The objective of this presentation is to discuss various aspects influencing hybrid plant design to help focusing research.

The evolution of technologies has led to the exploration of more efficient mechanisms in power generation systems. Currently, wind energy converters provide an efficient alternative for obtaining electrical energy; however, the location of the wind farms and the size and weight of the components are significant limitations. Implementing hybrid generators is an effective alternative for these systems since they could reduce the electrical and electronic elements. Hybrid generators have two fundamental parts: the permanent magnet and wound field rotor components. The terminal voltages of the generator can be adjusted by modifying the wound field current. However, it is essential to establish detailed studies in which the operating region of this generator is determined. This work provides a reference framework for establishing phase current and output power limits under different rotor speeds and DC-link voltages; this information could offer an operative region of the hybrid generator to ensure the lifetime and the implementation of these generators according to the availability of electronic devices.

IEA presentation on VRE Integration

This presentation gives a brief overview of the methodology used for the creation of a long-term capacity expansion plan for an island network using the open source software PyPSA. The methods used by Energynautics to carry out this study include time-aggregation using the novel Multi-Chrono method. This method is based on Chrono-Clustering and allows for a significant reduction of timesteps and computational efforts, while maintaining a high representation of the original data. Several new constraints were developed to allow for a more realistic modelling of the buildout and the dispatch of conventional power plants. These include the discrete buildout of units and the modelling of a efficiency curve and a lower operational limit. The employed methods allow for a more realistic modelling while keeping the computational efforts within realistic limits.

Emerging Challenges in the Future Swedish Power System