This study proposes a novel control scheme for frequency support in multi-terminal dc grid-based hybrid ac/dc networks. This control is based on the multi-agent system paradigm with an adaptive frequency droop control and is distributed in all grid-tied converters. The objective of this control is to enable the ac grids to intelligently decide on their participation on frequency support, considering their power reserves, demand, and relevant technical constraints and requirements. The main achievement of the proposed control is to minimise the rate of change of frequency and frequency undershoot (), and also providing a systematic enhancement in frequency stability, particularly in the disturbed and weak ac grids. A stability analysis is performed for the proposed control, using vector Lyapunov method for interconnected systems, deriving the conditions for stable operation. Test scenarios are conducted on a modified seven-terminal CIGRE grid, connecting five ac grids. Results under different scenarios show the performance and robustness of the proposed control in providing significant enhancement in the frequency regulation for the connected ac grids.

High-voltage direct-current (HVDC) grids may provide fast frequency support to ac grids with the aid of supplementary control algorithms and synthetic inertia contribution from offshore wind farms. However, when all converters within the HVDC grid are fitted with these supplementary controllers, undesirable power flows and reduced power transfers may occur during a power imbalance. This is due to simultaneous frequency oscillations on the different ac systems connected to the HVDC grid arising during the support operation. To prevent this adverse effect, an auxiliary dead-band controller (ADC) is proposed in this study. The ADC modifies the dead-band set-point of the fast frequency controllers using measurements of the rate of change of frequency and frequency deviation. A four-terminal HVDC integrated with an offshore wind farm is modelled to analyse and study the effectiveness of three different supplementary fast frequency control algorithms. Results show that the proposed ADC scheme improves the performance of fast frequency control algorithms. For completeness, a small-signal stability analysis is carried out to confirm that a stable system operation is maintained.

Wind power generation has reached a significant share in power systems worldwide and will continue to increase. As the converter-connected generation reduces the grid inertia, more and more interest has been given to exploiting the kinetic energy and controllability of variable-speed wind turbine generators (VSWTGs) for frequency support. Consequently, the grid frequency dynamics are changing. Thus, it is necessary to include the frequency response of wind power plants in the system frequency response (SFR) model. A novel approach to low-order SFR modelling of a future power system with a high share of frequency-support-capable VSWTGs has been presented. Low-order model of VSWTGs with primary frequency response and natural inertial response has been developed considering different wind turbine operating regimes and compared to the non-linear model for validation. Low-order model has been presented in a symbolic transfer function form. Model accuracy has been discussed and the impact of VSWTG parameters on frequency response has been analysed. The developed model facilitates studying power system frequency dynamics by avoiding the need for modelling complex VSWTG systems, while retaining a satisfying level of accuracy.

Short-term frequency stability (STFS) is becoming a great concern for a regional receiving-end power system such as the East China Power Grid (ECPG) mainly for two reasons: (i) the increasing percentage of power injected from multi-infeed (ultra-) high-voltage DCs (HVDCs) with the skyrocketed capacities; (ii) the replacement of traditional generation by the continuously growing inertia-less renewables. However, the existing emergency control is not adaptive enough to maintain STFS under varying operation conditions. In this study, a real-time optimised control is proposed to solve the issue more efficiently. It combines emergency power boosting (EPB) of HVDC and emergency demand response (EDR) in a coordinated way. The optimal control problem is formulated based on the online-updated models that reflect the current state of the system and the dynamic responses of multiple types of generators. By converting the non-linear constraint into a linear matrix inequality, the allocation of EPB and EDR can be optimised in a real-time and coordinated way. The performance of the proposed control and its advantages over the existing one are verified by simulation studies on the model of ECPG with low, normal and high penetrations of renewables.

Considering the capacitor banks and on-load tap changer (OLTC) applied in the voltage-source-converter-based high-voltage direct-current (VSC-HVDC) systems with large-scale wind farm integration, this study presents a day-ahead voltage scheduling method to avoid frequent adjustment of the slow discrete devices. Using this method, the AC side voltage of the wind farm side VSC (WFVSC), capacitor banks and OLTC can be scheduled optimally. The scheduling ensures a discrete but large change, while real-time automatic voltage control (AVC) in wind farms offers a continuous and a fine response to the volatility of wind power. This ordination is realised by a two-stage robust optimisation utilising wind power forecasting. Furthermore, a reasonable simplification method is proposed to address non-linear constraints and make the problem solvable. Based on Monte Carlo simulation, case studies are conducted for both simple and real systems to verify the validity and superiority of the method. The results show that the scheduling enhances the AVC effect under the randomness of wind power output and enables collaboration among diverse devices in the vicinity. The system operation outperforms other methods in terms of the voltage profile and dynamic reactive power reserves.

Wind power outputs will bring larger computational error in actual operation without considering the correlation. This study presents an affinely adjustable robust optimisation method for AC–DC optimal power flow (AC–DC AAROPF) considering the correlation of wind power. Affine policies are utilised in the re-dispatch process to ensure the feasibility of the infinite scenarios of uncertainties. After transforming AC–DC AAROPF to a tractable model, a novel approach based on simplified pair copula to consider multiple dependence of wind power is presented. The AC–DC AAROPF is evaluated on the modified AC–DC IEEE 30-bus and 118-bus system. Results show a modest increase in expected cost for reasonable levels of uncertainty representing forecast error confidence intervals, which obtains a more robust solution with higher successful rates.

This study presents a bi-level decentralised active power control (DAPC) for a large-scale wind farm cluster (WFC), consisting of several wind farms for better active power dispatch. In the upper level, a distributed active power control scheme based on the distributed consensus is designed to achieve fair active power sharing among multiple wind farms, which generates the power reference for each wind farm. A distributed estimator is used to estimate the total available power of all wind farms. In the lower level, a centralised control scheme based on the model predictive control is proposed to regulate active power outputs of all wind turbines (WTs) within a wind farm, which reduces the fatigue loads of WTs while tracking the power reference obtained from the upper-level control. A WFC with 8 wind farms and totally 160 WTs, was used to test the control performance of the proposed DAPC scheme.

The Kriegers Flak combined grid solution (KF CGS) will interconnect the eastern synchronous area of Denmark and Germany by extending the existing high-voltage alternating current (HVAC) offshore wind farm infrastructure in the Baltic Sea. In contrast to conventional point-to-point interconnectors, the extension creates a meshed submarine grid (MSG) which includes an interconnector and wind farm collectors to the countries using the same equipment. Denmark East as part of the Nordic system and 50 Hertz as part of the synchronous Continental European grid are asynchronous to each other, which makes a frequency transformation necessary. The interconnection will be realised by a high-voltage direct current (HVDC) back-to-back (BtB) converter in voltage source converter technology located at the German end of the interconnector. The BtB and the entire HVAC MSG between Denmark and Germany will be controlled by a so-called master controller for interconnector operation (MIO). The KF CGS will integrate offshore wind power generation, increase the security of supply and enhance integration of regionally produced renewable energy. This study describes the overall infrastructure of the KF CGS and the MIO functions. A model-based evaluation of those shows the behaviour of the HVAC/HVDC MSG in normal operation and in the case of contingencies.

This study presents a non-linear adaptive control (NAC) for the energy storage system (ESS) embedded dynamic voltage restorer (DVR) in enhancing the low-voltage ride through (LVRT) capability of wind farms. The proposed NAC features a perturbation observer to estimate and then compensate the real perturbation of the whole system, including parameter uncertainties, measurement noise, and external disturbances such as different grid faults and intermittent wind power. It can achieve an adaptive and robust control without requiring accurate system model and full-state measurements. This control is then applied to the ESS embedded DVR (ESS-DVR) system, in which the ESS can store the blocked wind power for potential power fluctuation suppression. Simulation studies have verified that the proposed control for ESS-DVR can effectively enhance the LVRT capability of wind farms installed with different types of WTGs under different operating conditions. Moreover, its superiority has also been demonstrated by comparing with fixed gains-based conventional vector control and accurate system model-based feedback linearising control.

In multi-terminal voltage source converter based high-voltage direct-current (VSC-HVDC) systems, droop controllers are commonly adopted to regulate the active power and voltage. Thus, the droop controller coefficients inevitably affect the system stability. In this study, a method to design droop control coefficient is proposed considering the system stability. The state-space model of the multi-terminal VSC-HVDC system with droop controllers is established in which the droop controllers are considered as feedback controllers to reflect the control characteristics. Based on the model, the determination of droop control coefficients can be equivalent to an optimisation problem. The objective is to minimise the Frobenius-Hankel norm of the system S/T mixed sensitivity. The constraint conditions include closed-loop system eigenvalues constraint and steady-state errors constraint. By doing so, the optimal system stability and robustness are achieved. To verify the proposal, simulations on a four-terminal VSC-HVDC system are performed with two another sets of droop control coefficients for comparison. Simulation results show that the proposed droop controller can ensure system stability and robustness under various disturbances and faulty conditions.

This study presents a method to analyse the secure and optimal operation of transmission systems consisting of both HVDC (high-voltage direct current) and high-voltage alternating current interconnections under a scenario of high penetration of offshore wind and taking into account the system spinning reserves. Different reliability management strategies are assumed, accounting for a single AC element and/or a single DC element outage and taking into consideration the probability of failure of the different power system components. The cost of operation of the system and the wind energy curtailed over the operating time are determined. This method is applied to a study case, based on the CIGRÉ HVDC Test System. The system behaviour over a complete year is modelled using realistic wind generation and demand based on scaling data from the Belgian power system.

The main objective of this study is to increase the power system oscillation damping in the presence of wind farms using flexible alternating current transmission systems (FACTS) devices and predictive control. The desired design is conducted to coordinate static synchronous compensator–static synchronous series compensator and rotor side converter in doubly-fed induction generator (DFIG). This design is done to compensate for the DFIG reactive power and increase power system oscillation damping in the presence of uncertainties in the wind turbine. The method proposed for coordinated design was based on the network predictive control (NPC) so that it could improve damping, and compensate for the time delays in sending wide area signals. In fact, NPC is based on generalised predictive control (GPC) which has the ability to compensate for time delays using model identification method. Using MATLAB software, the simulation results were conducted on a 16-machine and 69-bus power system under different scenarios; and the ability of NPC is well proven compared with GPC and the classic method of wide area controller.

To meet the required operation speed for protection of meshed voltage source converter (VSC) high-voltage direct current (HVDC) grids, travelling wave-based algorithms operating in the submillisecond time-frame can be used. The domain in which these algorithms operate, i.e. modal or phase, determines their performance in fault discrimination, fault type classification, and faulted pole selection. In the recent literature, high-speed algorithms have been proposed for various VSC HVDC grid configurations and transmission line types; yet, the choice of domain has received insufficient attention. This study offers recommendations for the choice of domain for protection algorithm design of HVDC overhead line or cable systems in symmetric monopolar and bipolar configurations. The theoretical analysis of this study, which is based on fundamental wave propagation theory, indicates that the preferred domain for protection algorithms for cable and overhead line systems are the phase and modal, respectively. Furthermore, the study provides comprehensive guidelines to construct detection functions for both configurations and discusses the errors introduced by approximations. Finally, study results from a bipolar overhead line test system demonstrate the advantages of modal over phase domain for fast fault discrimination and classification and illustrate practical problems associated with non-ideal detection functions.

Due to different fault ride through controls of both the wind farm and the voltage-source converter high-voltage alternating current (VSC-HVDC) converters, the offshore wind farms that are connected to the power system through VSC-HVDCs have unique fault transients. During a fault on AC side transmission lines, the wind farm and the VSC-HVDC together provide faulted current, whose amplitude and phase will be decided by their different control strategies collectively. The fault transients are different from those in the traditional AC grid. Thus, the performance of traditional protection will be affected. In this study, the AC fault current expression is deduced, while the influencing factors on the current's amplitude and phase are analysed in detail. Based on these characteristics, the performance of distance relays under the grid side fault of the VSC-HVDC-connected offshore wind farm integration system is evaluated. Simulations based on PSCAD have verified the theoretical analysis.

This study presents a method based on an artificial neural network (ANN) for protecting voltage source converters (VSC)-high-voltage direct current (HVDC) systems. The proposed method takes advantage of ANNs’ excellent capabilities in pattern recognition and classification. The solution presented here is able to detect a fault condition in the whole HVDC system based only on voltage waveforms measured at the rectifier substation, which is an important advantage over other fault detection methods. For any given fault condition, the faulty zone is identified and then the fault is classified concerning the phases or poles involved. The proposed method is shown to be both robust against false operations and very reliable with respect to fault detection and classification. A large number of simulations were performed and results show the effectiveness of the proposed scheme. Different operational conditions and fault cases were considered to evaluate the proposed algorithm, ensuring excellent performance concerning a wide range of possible situations in VSC-HVDC systems.

The ever-increasing demand for electric power has partially been met with access to offshore renewable energy, such as wind and tidal energy. With the development in power electronics, high-voltage direct current (HVDC) transmission is taking over as the primary choice for connecting off-shore generation to on-shore grids. Voltage source converter (VSC)-based HVDC is set to become the backbone of the multi-terminal DC grids replacing the conventional line commutated converter networks. VSC-HVDC networks offer the flexibility for HVDC grids to be connected as conventional AC grids in a meshed network. Advancement of technology has led to the development of the modular multilevel converter which has higher efficiency compared to the two-level VSC configurations. They are gradually becoming a popular choice. Although VSC-based grids offer a varied range of advantages, it is highly vulnerable to DC faults. Many designs of breakers have been patented over the years and various means have been proposed for their control. This study aims to review the available designs of HVDC terminals, the available protection devices and the protection and control methods for HVDC breakers. By comparing the state-of-the-art technologies that are currently available, this study aims to address the research issues and the additional research and development work that needs to be done.

This study provides a novel control method for voltage source converter high-voltage direct current (VSC-HVDC) systems with two salient features: autonomous grid-synchronisation without phase-locked loop and real-time grid frequency mirroring capability. The first feature is realised using a newly proposed control method for receiving end converter (REC) called inertial synchronising control (ISC). This method innovatively adopts the physical inertia of DC capacitors to directly synchronise with the grid, without emulating the motional equation of a synchronous generator (SG) as virtual SG control. Hence, less control loops and easy parameter tuning are achieved. The control robustness to grid impedance variation is also improved. Moreover, the second feature is realised with the merit of ISC. Owing to the fast grid-synchronisation capability of ISC, grid frequency dynamic is bound with DC voltage dynamic intrinsically; hence, the instantaneous grid frequency information can be obtained by measuring the local DC voltage of sending end converter, whereby wind turbines can proceed with inertial and frequency response. Consequently, REC is similar to SG in terms of electromechanical characteristics. The effectiveness of the proposed method is evaluated by comparing it to an existing method in PSCAD/EMTDC, and its performance on the robustness to grid impedance variation is addressed.