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The prospect of future multivendor HVDC systems has led to concerns about interoperability between converter terminals based on different technologies. This paper investigates the interoperability of converter terminals in a small-scale experimental setup, consisting of two 2-level (2L) Voltage Source Converters (VSCs) and two Modular Multilevel Converters (MMCs) with different number of half-bridge sub-modules in each arm. The laboratory setup is utilized to demonstrate interoperability of a 2-level VSCs and an MMCs when operated in parallel on the dc-side as well as in parallel at a common connection point in an ac grid. Experimental results are presented for the investigated 4-terminal configuration with one 2L VSC controlling the dc voltage and all other converters controlling their active power flow. The presented results give an additional empirical confirmation that topological differences between properly designed converter terminals should have limited influence on system level operation and system interoperability of MT HVDC systems Interoperability of Modular Multilevel Converters and 2-level Voltage Source Converters in a Laboratory-Scale Multi-Terminal DC Grid

The real-world interaction of an offshore wind farm with an HVDC is complex due issues such as noise, randomness of event timings, and hardware design issues that are not well explored. Numerical simulations are widely accepted and cost effective tool to test a wide variety of different cases, however, the fidelity of the results is difficult to assess. Higher fidelity can be obtained with scale-down experiments, however, this solution has a limited test coverage. The power-hardware-in-the-loop (PHIL) option offers a good trade-off between test fidelity and test coverage. The hardware part allows a high fidelity of the results whereas, the software simulation part allows an extensive study of different cases at a reasonable cost. This paper presents a PHIL implementation of an offshore wind farm connected with a voltage source converter (VSC)-based HVDC. The offshore wind farm is emulated in a real time simulation environment, and a grid emulator is used as power interface between the emulated system and the hardware system, i.e. VSC-based HVDC substation. The interaction of real time models and hardware is demonstrated with experimental results

Interest in large-scale integration of power from renewable energy sources (RES) has grown in the last decade as a result of energy policies adopted by governments in an effort to reduce CO2 and greenhouse gas emissions. Both large scale, and distributed solar and wind energy have proliferated the power system and will continue to do so in the future. Thus, large and complex transmission systems are needed for robust, flexible and secure operation of the future power system. Multi-terminal HVDC (MTDC) grids are expected to play an important role in an efficient socio-economic operation of the electric power system by acting as a means for integration of RES, exchange of balancing power, crossborder power market trading, grid reinforcement, etc. As the introduction of MTDC grids will eventually result in a hybrid ac/dc power system, it is necessary to carry out a global analysis that considers the entire hybrid ac/dc power system, which includes both dc and all synchronous areas of the power systems. The main objective of this PhD is to study the stability of hybrid ac/dc power systems, with a particular focus on the ac grids. The work investigates how the dynamic characteristics of ac grids will be affected by the introduction of the MTDC grids and/or by control methods implemented in MTDC converter controllers. Modal analysis, in particular eigenvalues, mode shapes, and participation factors, was used to identify and analyze interactions (dynamic coupling) between different subsystems in a hybrid ac/dc power system. Mode shapes were used to identify electromechanical interactions between generators located in different synchronous areas (asynchronous grids). The inter-grid electromechanical interactions are generally weak but are influenced by dc grid control strategy, controller tuning and damped frequency of electromechanical modes. The source of the interactions is dynamic coupling between ac and dc grids. When several terminals share the duty of dc voltage regulation, as in the case of dc voltage droop control operation mode, the dynamics of the ac grids behind those terminals are coupled to a common dc grid dynamics. This leads to indirect coupling of dynamics of different ac grids through dc grid dynamics. A qualitative analysis of state matrix of a single 2-level converter with and without connection to a detailed ac grid model was used to supplement the findings of the quantitative modal analysis. It was shown that there is a two-way dynamic coupling between ac and dc grids when a converter is operated in constant dc voltage or dc voltage droop control modes, i.e. ac grid dynamics is coupled with dc grid dynamics and dc grid dynamics is coupled with ac grid dynamics. However, there is only a one-way coupling between an ac grid and a dc grid if the converter is operated in constant power control mode. In such cases, the ac grid dynamics is coupled with the dc grid dynamics, but the dc grid dynamics is not coupled with the ac grid dynamics. Decentralized control techniques were used to study interactions between power oscillation damping (POD) controllers on multiple terminals of an MTDC that interconnects several asynchronous ac grids. Interaction between the selected control loops was assessed using dynamic relative gain array and performance relative gain array techniques in the frequency domain. In addition, modal and time domain analyses carried out for the study case supported the findings from the frequency domain analysis. For the study case analyzed, it was found that due to control loop interactions the performance of one of the controllers was augmented, while the performance of the other controller deteriorated. The analyses clearly showed that control loop interaction should be considered while tuning PODs on converters even if they are connected to different grids. Finally, a coordinated control strategy for terminal converters of a dc grid was proposed to address the issue of frequency disturbance in other ac grids when one grid receives frequency support from an offshore wind farm. It was shown that by coordinating converter controllers at the terminals of an offshore wind farm and one ac grid, it is possible to maximize frequency support contribution of the offshore wind farm and avoid disturbance in other ac grids connected to the MTDC. However, the proposed method works when only one ac grid is receiving frequency support and the remaining ac grids are connected MTDC terminals, which are operating in dc droop or constant power control mode. If more than one ac grids are to receive frequency support through MTDC grid, then negative interactions occur when the proposed controller is used. Therefore, in such cases, distributed dc voltage and frequency droop control is the best control option. However, it should be noted that with distributed dc voltage and frequency droop control method, the frequency support comes not only from the wind farm but also from other ac grids behind an MTDC terminal operating in dc voltage droop control mode.

The present report summarizes the main findings of the Nordic Energy Research project “DC grids for large scale integration of offshore wind power – OffshoreDC”. The project is been funded by Nordic Energy Research through the TFI programme and was active between 2011 and 2016.The overall objective of the project was to drive the development of the VSC based HVDC technology for future large scale offshore grids, supporting a standardised and commercial development of the technology, and improving the opportunities for the technology to support power system integration of large scale offshore wind power. This was done by bringing together the key industry stakeholders and competent research organisations in the project.

The large-scale integration of renewable energy sources in the power system, combined with the need for an increased transmission capacity has led to a growing interest in multi-terminal high voltage dc (MTDC) grids. In the future, these grids will be integrated with different existing asynchronous ac grids, eventually resulting in hybrid AC/DC power systems. This paper investigates interactions between asynchronous ac grids in a hybrid AC/DC power system. In the study, a symmetrical monopolar ±400kV four-terminal VSC-based MTDC grid connected to three different multi-machine ac systems is modelled in DIgSILENT PowerFactory. One of the ac grids has four generators while the others have two generators each. Governor and automatic voltage controllers are included for each generator so as to capture the complete generator dynamics. DC cables are modelled as PI models with lumped parameters. All dc grid terminal converters are operating in dc droop and reactive power control modes. A small signal analysis is carried out in the test system to investigate interactions between asynchronous ac grids. From the modal analysis of the poorly damped eigenvalues, it is shown that speed state variables of all generators in the study system are observable in these modes; indicating dynamic interactions between generators located in asynchronous ac grids. The change in the level of these dynamic interactions is studied for different time responses of the MTDC terminal converter controllers. It is found that faster and slower converter control response times lead to lower and higher interactions between the asynchronous ac grids, respectively. Results from a time domain simulation of the study system for a fault in one of the ac grids support the findings of the small signal analysis. The study results show that dynamic coupling exists between ac grids across dc grids and that the level of interaction is influenced by the converter controller settings. ispartof: pages:1-7 ispartof: Proc. CIGRE International Symposium Lund pages:1-7 ispartof: CIGRE International Symposium HVDC Systems and Markets Integration location:Lund, Sweden date:27 May - 28 May 2015 status: published

The objective of this thesis work was to study the stability of a distribution network with several distributed generators (DGs) considering different types of regulators in the DGs and loading conditions. The distribution network under study, Øie Kvinesdal, is a 57 km long radial feeder. It contains 8 distributed generators; seven synchronous and one induction generator. The largest generator has 10.3 MW rated power and the lowest has 0.25 MW rated power. The first and last generators are located 7.3 km and 45 km away from the 106/22 kV transformer respectively. Four of the synchronous generators are located on the same side branch.Four cases were studied with three different total active power production levels, two medium and one maximum production levels, and two different network loading conditions, high and low load.In each case, five different types of disturbances were created to analyse the dynamic response of the distribution network. The disturbances are synchronous generator disconnection, change in load, change in system voltage, short circuit fault, and disconnection of the 22 kV feeder from the HV network. Five different scenarios of synchronous generator disconnections were studied; disconnecting the largest four one by one and disconnecting the smallest three at the same time. Two different scenarios of load changes were studied. The first one is a step change in load either from high load to low load or from low load to high load depending on the initial loading condition of the network. The second type of change in load is disconnection of loads in one area which account to 66% of the total loads in the system. Change in system voltage was created by a 2.5 % step up on the swing bus voltage. The pre-disturbance linear analysis result showed that controllers connected to the smallest generators have strong relations with the least damped eigenvalues. The case with maximum generation and low loading had very low damped oscillations; as low as 6% damping ratios. Selecting appropriate regulator gain constants plays vital role in the distribution system s small signal stability. There are some eigenvalues with imaginary part as high as 11 Hz. This is due to the low inertia of the distributed generators.The generators in all cases were able to regain synchronism after disturbances caused by disconnection of synchronous generators, change in load and system voltage. This is because the distribution network is connected to a strong high voltage network. But not all studied scenarios had terminal voltage and power factor within the allowed range in their post-disturbance steady state. Depending on settings of reactive power and over voltage relays, and how quickly a new set point is calculated for the excitation system controllers, a cascade of faults may occur. This could lead to instability. Relays were not included in this study.The critical clearing time for the case with maximum production and low load was the shortest because the distribution network had high voltage and the DGs were operating with their rated capacity in the pre-disturbance steady state. The distribution network was not able to reach new steady state, and be able to operate in island mode after disconnection of the feeder from the HV network with the turbine and governor models used.