Inverter-based Generation Research Articles

A crucial remark on the importance of considering transient configurations on the optimal coordination of directional overcurrent relays in power systems with high penetration of inverter-based generation resources

A crucial remark on the importance of considering transient configurations on the optimal coordination of directional overcurrent relays in power systems with high penetration of inverter-based generation resources

Identifying interaction boundary of inverter-based generation in assessing system strength of power grids using relative electrical distance concept

The increasing use of inverter-based generation (IBG) in power grids raises concern about system strength. This is partly due to the inherent interactions among multiple IBGs in close proximity to one another. This paper proposes an approach to identifying the existential boundary of interaction in a network using the relative electrical distance (RED) concept. The mathematical formulation of the RED concept to address the interaction problem among the IBGs involved utilising the power system network’s admittance matrix to capture its structural characteristics. An interaction matrix derived from the RED values of all IBG pairs was then developed to identify the interacting IBG groups. The proposed approach was demonstrated using the IEEE 39-bus system and a practical 72-bus Nigerian power grid. Results showed that RED values effectively group interacting IBGs, with values closer to 0 signifying higher interaction levels, values closer to 1 indicating lower interaction, and a value of 1 denoting no interaction. Time-domain simulations confirmed the accuracy of the approach, demonstrating that the effect of control interaction propagates proportionally to neighbouring IBGs based on RED values. However, fault currents can influence the impact of control interactions. This approach, which requires less computational effort, provides a quick identification tool for potential areas of concern based on the degree of interaction, enhancing the reliability of power grids with high IBG penetration.

The Impact of Replacing Synchronous Generators with Renewable-Energy Technologies on the Transient Stability of the Mangystau Power System: An Introduction to Flexible Automatic Dosage of Exposures

Since the creation of the first parallel electrical power systems around the world, the rotor angle stability of synchronously operating generators has been one of the most crucial and challenging problems. In modern electricity networks, including in Kazakhstan, where renewable energy technologies are rapidly emerging, the issue of stability takes on even greater importance due to the technical shortcomings of inverter-based generation. In this framework, an analysis of rotor angle transient stability was carried out when replacing existing synchronous generators with doubly fed induction generators under a certain pre-emergency mode. A critical proportion of active power generation by DFIG units was identified at which transient stability can still be maintained due to the sufficient stored kinetic energy of the synchronous machines remaining in operation. In addition, two simple solutions were investigated to improve transient stability, such as an increased time of the automatic reclosure operation and the use of special load-shedding automation. Finally, this paper proposes a novel type of flexible smart-grid automation that is capable of monitoring the main operating parameters and issuing control actions depending on inertia, the availability of wind resources, and the load of the system as a whole. For this analysis, a real power system from the Mangystau region in Kazakhstan was considered, and the PowerWorld software 23 was used.

Investigating the impact of solar PV and wind energy systems on the strength of a longitudinal power grid

The integration of inverter-based generation (IBG), such as solar photovoltaic (PV) and wind systems, presents unique challenges for power grid strength, especially in regions with limited conventional generation capacity. This study investigates the impact of such integration on the strength of Nigeria's power grid, focusing on sparsely connected northern region with abundant renewable resources. Using the network response short-circuit ratio (NRSCR) metric, which accounts for interactions between IBGs, we assess grid strength in three case studies. Simulations were conducted with the Power System Simulation for Engineering (PSS®E) software. Static analysis reveals inherent weakness in the northern region, characterized by low short-circuit capacity. Integrating IBGs at nine strategic locations shows varying responses: strong buses (NRSCR > 10) adapt well, while weak buses (NRSCR < 10), particularly in Kano and Katsina, constrain the operational capacity of the IBGs. Furthermore, close interaction among IBGs at these locations significantly impacts the system's dynamic response, although planned addition of conventional generators offers marginal improvement. This work highlights the potential of renewable resources to address energy shortages but also underscores the crucial need for detailed design studies at each point of interconnection (PoI), considering the longitudinal grid layout in the northern region and potential limitations imposed by IBG interactions. The findings also offer a structured approach that can be applied to power grids with comparable IBG integration levels, similar to the energy landscape of Nigeria.

Load Flow Assignments’ Definition from Day-Ahead Electricity Market Interconnection Power Flows: A Study for Transmission Networks

The mass introduction of renewable energy sources (RESs) presents numerous challenges for transmission system operators (TSOs). The Italian TSO, Terna S.p.A., aims to assess the impact of inverter-based generation on system inertia, primary regulating energy and short-circuit power for the year 2030, characterized by a large penetration of these sources. The initial working point of the Italian transmission network has to be defined through load flow (LF) calculations before starting dynamical analyses and simulations of the power system. Terna 2030 development plan projections enable the estimation of active power generation and load for each hour of that year in each Italian market zone, as well as cross-zonal active power flows; this dataset differs from conventional LF assignments. Therefore, in order to set up a LF analysis for the characterization of the working point of the Italian transmission network, LF assignments have to be derived from the input dataset provided by Terna. For this purpose, this paper presents two methods for determining canonical LF assignments for each network bus, aligning with the available data. The methodologies are applied to a simplified model of the Italian network, but they are also valid for other transmission networks with similar topology and meet the future needs of TSOs. The methods are tested at selected hours, revealing that both approaches yield satisfactory results in terms of compliance with the hourly data provided.

Modal propagation analysis with participation factors of complex frequency variables

This paper proposes the use of participation factors of complex frequency variables to study the propagation of oscillations in power systems. The method combines the recently proposed concept of complex frequency with modal participation analysis to derive a novel metric that locates the sources of oscillations in the system and tracks their spatial propagation. The proposed approach allows isolating the variables more sensitive to oscillations, bus voltage or frequency, thus facilitating the selection of corrective actions. The validity of the theoretical results and the scalability of the method are supported with extensive simulations performed for test networks of various sizes and with both conventional and inverter-based generation.

Potential Revenue from Reserve Market Participation in Wind Power- and Solar Power-Dominated Electricity Grids: The Near-Term, Mid-Term, and Long-Term

As electricity systems become increasingly dominated by variable inverter-based generation (such as wind and solar photovoltaics (PV)), additional sources of variability appear, while the share of dispatchable thermal power plants decreases. Maintaining a stable grid frequency requires new sources of inertia to slow the frequency changes, as well as new sources of reserve power to counter the imbalances. This work uses a linear optimization modeling approach to analyze the reserve market of the electricity system during the transition to a carbon-free system with high shares of variable electricity generation. The modeling is performed for three regional contexts and with varying degrees of available flexibility technologies. As for the reserve supply, batteries, electrolyzers, electric boilers and heat pumps for district heating, curtailed wind and solar power, and hydropower and thermal power plants are all included. The results indicate that of these suppliers of reserves, the introduction of grid-scale batteries into the system drastically reduces the reserve market size. Only early in the transition is revenue from the reserve market greater than 5% of the total revenue for any technology. While the demand for reserves increases as the share of solar PV and wind power increases, the modeling reveals that access to flexible loads, storage units, and emulated inertia from wind power also increases. Depending on the choice of flexibility measures available, demand-side participation could play a major role in minimizing the cost of grid stability in the future.

The impact of load placement on grid resonances during grid restoration

As inverter-based generation is being massively deployed in the grid, these type of units have to take over the current roles of conventional generation, including the capability of restoring the grid. In this context, the resonances of the grid during the first steps of a black start can be concerning, given that the grid is extremely lightly loaded. Especially relevant are the low frequency resonances, that may be excited by the harmonic components of the inverter. A typical strategy to avoid or minimize the effect of such resonances relies on connecting load banks. This was fairly feasible with conventional generation, but given the limited ratings of inverters, the amount of load that can be connected at the beginning is very limited. In this paper we consider the energization of a transmission line, and investigate the optimal location of a load along the line in order to maximize the damping in the system. By analysing the spectral properties as a function of the load location, we formally prove that placing the load in the middle of the transmission line maximizes the damping ratio of the first resonance.

Plausibility and Implications of Converter-Driven Oscillations Induced by Unstable Long-Term Dynamics

For decades, synchronous generators have dominated power system dynamics and have been the foundation for the comprehension of the physical phenomena involved in power system stability. This paradigm is rapidly changing; large synchronous generators that contribute to system strength are being replaced by inverter-based generators. Consequently, new kinds of instabilities are emerging. Slow-interaction converter-driven instability is one example in which undamped oscillations occur when inverter-based generators operate in weak areas. Transmission system operators have observed the phenomenon under the scope of short-term dynamics following a disturbance during a weak operating condition. This paper suggests that converter-driven oscillations can occur even in the case when the system's initial operating condition is strong. It concludes that the phenomenon can be triggered by long-term dynamics that slowly weaken the system in which small-signal and short-term simulations show an ample stability margin. The outcome is a combination of unstable long-term dynamics and undamped oscillations. Furthermore, this work suggests that classical emergency controllers that are effective against long-term instability may not be successful if undamped oscillations are also present. A method for instability detection and counteraction is proposed based on Prony analysis and time-domain simulations on the IEEE test system for voltage stability assessment.

A novel virtual inertia-based damping stabilizer for frequency control enhancement for islanded microgrid

The Inverter-based generator lacks natural inertia, which leads to instability problems in Microgrid frequency. Virtual inertia is a promising control concept that rapidly injects/absorbs active power to/from the power system to ensure the frequency stability of low-inertia systems. This paper proposes an innovative virtual damping stabilizer (VDS) integrated into battery energy storage system (BESS) based virtual inertia and damping control loops. The proposed VDS adds supplementary damping and stabilizing capability to the BESS by properly correcting and controlling its inertia pumped/drawn power. The VDS aims to enhance frequency stability, decrease the necessary BESS large capacity, and lower the initial expense. Furthermore, the proposed VDS helps operate the BESS efficiently by smoothing the output power profile during transient disturbances, consequently elongating the lifetime. The Particle Swarm Optimization (PSO) method is utilized to get the optimal parameters of the proposed VDS. A frequency control model of an isolated microgrid with the proposed controller is presented, considering various operating conditions. Time-domain simulations and experimental validation using OPAL-RT verify the efficacy of the proposed VDS scheme. Sensitivity and eigenvalues analyses assess the VDS's dynamic stability enhancement and robustness against inherent uncertainties in Microgrid parameters. The results demonstrate a superior frequency response and a reduction in the BESS size compared to PSO and model predictive controller (MPC) based virtual inertia and damping strategies.

Virtual Inertia Control in Autonomous Microgrids via a Cascaded Controller for Battery Energy Storage Optimized by Firefly Algorithm and a Comparison Study with GA, PSO, ABC, and GWO

Modern (micro) grids host inverter-based generation units for utilizing renewable and sustainable energy resources. Due to the lack of physical inertia and, thus, the low inertia level of inverter-interfaced energy resources, the frequency dynamic is adversely affected, which critically impacts the stability of autonomous microgrids. The idea of virtual inertia control (VIC), assisted by battery energy storage systems (BESSs), has been presented to improve the frequency dynamic in islanded microgrids. This study presents the PD-FOPID cascaded controller for the BESS, a unique method for enhancing the performance of VIC in islanded microgrids. Using the firefly algorithm (FA), the settings of this controller are optimally tuned. This approach is robust to disruptions due to uncertainties in islanded microgrids. In several scenarios, the performance of the suggested approach is compared with those of other control techniques, such as VIC based on an MPC controller, VIC based on a robust H-infinite controller, adaptive VIC, and VIC based on an optimized PI controller. The simulation results in MATLAB show that the suggested methodology in the area of VIC is better than previous methods.

A new protection scheme for feeders of microgrids with inverter-based resources

Due to the unavailability of a suitable relay for microgrid protection, various utilities are fitting available IEDs for the protection of microgrids. At present, microgrid protection is achieved using a combination of conventional numerical relays. These numerical relays are not suitable for all kinds of microgrid architectures and do not provide complete protection with inverter-based generators. Since these relays were designed considering the fault characteristics of synchronous generators, they fail to respond to the fault characterized by inverter-based generators. This paper proposes a new protection technique that is independent of the type of generating sources, control philosophy of inverters as well as microgrid architecture. Simulations are performed using PSCAD/EMTDC and performance of the protection scheme is also evaluated in real-time using RTDS. Pertinent results are presented which demonstrate the effectiveness of the proposed scheme.

Adaptive Machine-Learning-Based Transmission Line Fault Detection and Classification Connected to Inverter-Based Generators

Adaptive protection schemes have been developed to address the problem of behavior-changing power systems integrated with inverter-based generation (IBG). This paper proposes a machine-learning-based fault detection and classification technique using a setting-group-based adaptation approach. Multigroup settings were designed depending on the types of power generation (synchronous generator, PV plant, and type-3 wind farm) connected to a transmission line in the 39-Bus New England System. For each system topology, an optimized pretrained ensemble tree classifier was used. The adaptation process has two phases: an offline learning phase to tune the classifiers and select the optimum subset of features, and an online phase where the circuit breaker (CB) status and the active output power of the generators are continuously monitored to identify the current system topology and to select the appropriate setting group. The proposed system achieved an average accuracy of 99.4%, a 99.5% average precision, a 99.9% average specificity, and a 99.4% average sensitivity of classification. The robustness analysis was conducted by applying several fault scenarios not considered during training, which include different transmission network configurations and different penetration levels of IBGs. The case of incorrect selection of the appropriate setting group resulting from selecting the wrong topology is also considered. It was noticed that the performance of developed classifiers deteriorates when the transmission network is reconfigured and the incorrect setting group is selected.

Development of Virtual Inertia Control with State-of-Charge Recovery Strategy Using Coordinated Secondary Frequency Control for Optimized Battery Capacity in Isolated Low Inertia Grid

Integrating renewable energy through inverter-based generators has decreased the power system’s inertia. Reduced inertia may lead to frequency instability during power imbalance disturbances, particularly in an isolated power system with limited inertia. The Battery Energy Storage System (BESS) and a virtual inertia (VI) emulation control system have become popular to mitigate this issue. Nonetheless, the BESS utilization for VI emulation is highly dependent on the availability of BESS capacity, which may affect the energy cost. Therefore, developing a VI emulation control strategy that requires less energy and can recover the state of charge (SoC) to a desired level to optimize BESS utilization is required. This paper proposes a VI control with an SoC recovery strategy through coordination with the generators’ secondary frequency control. Instead of relying on the frequency, such as in the conventional approach, the controlled signal of the generators’ secondary frequency control also includes the VI power and BESS SoC. Hence, the generators can contribute to lowering the VI required energy and recovering the BESS SoC. The results show that the proposed method outperforms the conventional method by requiring around 36% lower energy and the ability to maintain the BESS SoC.

Equivalent grid-following inverter-based generator model for ATP/ATPDraw simulations

This paper presents an equivalent time-domain grid-following inverter-based generator model, which can be used in Electromagnetic Transients Programs (EMTP). It is developed in the Alternative Transients Program (ATP) using the ATPDraw graphical interface. A complete benchmark photovoltaic model available in ATP/ATPDraw environment is taken as reference to evaluate the proposed model under steady-state and fault scenarios. The obtained results showed that the proposed model is simpler and less time-consuming than the complete model, being capable of easily consider the implementation of different components/controls of Inverter-Based Resources (IBR) in EMTP. The settings used in the implemented control schemes proved to be effective, resulting in an average error of about 2.33% during fault conditions. Also, a reduction of about 70 % in the execution time was achieved when compared to the analyzed benchmark one, attesting its usefulness for power system studies with high presence of grid-following IBRs.

Small-signal modelling and stability analysis of grid-following and grid-forming inverters dominated power system

In this paper, the explicit state-space model for a multi-inverter system including grid-following inverter-based generators (IBGs) and grid-forming IBGs is developed by the two-level component connection method (CCM), which modularized inverter control blocks at the primary level and IBGs at the secondary level. Based on the comprehensive state-space model representing full order of system dynamics, eigenvalues of the overall system are thoroughly analyzed, identifying potential adverse impacts of not only grid-following inverters, but also grid forming inverters on the system small- signal stability, with the underlying principle of oscillations also understood. Numerical and simulation results validate effectiveness of the proposed methodology on IEEE benchmarking 39-bus system

Fast frequency response services in low inertia power systems—A review

To fight global warming, the share of electricity generation from renewable sources is increasing in the energy mix. The replacement of conventional generation plants with inverter-based generation sources has led to a reduction in the system inertia and also change the nature of the frequency control in power systems. Thus, many system operators have introduced new techniques to enhance the system frequency stability such as the Fast Frequency Response (FFR) services. This paper reviews the state-of-the-art of most common tools proposed in the literature for participation in the FFR services as well as the challenges that are still facing each FFR tool. Furthermore, some of the control strategies proposed in the literature for each FFR tool have also been discussed and compared. Finally, some recommendations related to the adoption of FFR services in future power systems have been provided.

AC Grid Model Order Reduction Based on Interaction Modes Identification in Converter-Based Power Systems

Increasing application of power electronics devices (inverter-based generation and storage, HVDC lines, FACTS devices), facilitated by growing renewable energy integration, has also changed the ac grid modeling features. Namely, the incorporation of fast-acting control devices can lead to possible detrimental interactions that appear at much higher frequencies compared to synchronous generator-based power systems. In this regard, the phasor-based ac grid model is no longer adequate, putting forward the ac line models with extended validity in the frequency range. However, modeling all the lines in a system in high-frequency resolution requires high computational power and is often not necessary either. To overcome this challenge, this paper proposes the methodology for model order reduction (MOR) of an ac grid that enables a systematic identification of more significant lines in the system from the stability perspective and the necessary level of their model complexity. The methodology is established on subsystem participation calculation and the analysis of interaction modes between power electronics devices and a particular line. Thereat, the vector fitting algorithm is employed to obtain the high bandwidth state-space compatible ac line models. The functionalities and effectiveness of the proposed MOR methodology are demonstrated on a 9-bus test system.

Voltage Stability Constrained Unit Commitment in Power Systems With High Penetration of Inverter-Based Generators

With the increasing penetration of renewable energy sources, power system operation has to be adapted to ensure the system stability and security while considering the distinguished feature of the Inverter-Based Generator (IBG) interfaced generators. The static voltage stability which is mainly compromised by heavy loading conditions in conventional power systems, faces new challenges due to the large scale integration of IBG units. This paper investigates the static voltage stability problem in high IBG-penetrated system. The analytic criterion that ensures the voltage stability at the IBG buses are derived with the interaction of different IBGs being considered. Based on this, an optimal system scheduling model is proposed to minimize the overall system operation cost while maintaining the voltage stability during normal operation through dynamically optimizing the active and reactive power output from IBGs. The highly nonlinear voltage stability constraints are effectively converted into Second-Order Cone (SOC) form, leading to an overall Mixed-Integer SOC Programming (MISOCP), together with the SOC reformulation of AC power flow and frequency constraints. The effectiveness of the proposed model and the impact of various factors on voltage stability are demonstrated in thorough case studies.

STATCOM Technology Evolution for Tomorrow’s Grid: E-STATCOM, STATCOM With Supercapacitor-Based Active Power Capability

The urgency of climate change forces many countries and regions to accelerate toward the goal of a carbon-neutral economy. The consequence of replacing fossil-fuel synchronous generation with inverter-based renewables, such as wind and solar, leads to a paradigm shift from power systems dominated by synchronous machines to inverter-dominated power systems. When the share of inverter-based generation increases, the behavioral differences in terms of the grid services provided to the power network by generation become more salient. Services for grid stability that were historically inherently provided by synchronous generators now must be replaced by services from these inverter-based generation resources, other grid devices, or the combination of the two to ensure stable grid operation in the future as well.