Jörgen Svensson

DC bus voltage control for a distributed power system

This paper addresses voltage control of distributed DC power systems. DC power systems have been discussed as a result of the introduction of renewable, small-scale power generation units. Also, telecommunication power systems featuring UPS properties might benefit from a broader introduction of DC power systems. Droop control is utilized to distribute the load between the source converters. In order to make the loading of the source converters equal, in per unit, the voltage control algorithm for each converter has to be designed to act similar. The DC side capacitor of each converter, needed for filtering, is also determined as a consequence. The root locus is investigated for varying DC bus impedance. It is found that the risk of entering converter over-modulation is a stronger limitation than stability, at least for reasonable DC bus cable parameters. The stationary and dynamic properties during load variations are also investigated.

Coordinated voltage control in medium and low voltage distribution networks with wind power and photovoltaics

Distributed Generation (DG) installations have been increasing during the last years. Wind power and photovoltaics are two of the most common renewable energy sources for DG typically connected to the distribution network (DN) originally planned and built to supply loads. DG units connected to the DN impact the voltage where customers are connected. Network voltage is an important quality criterion in DN. Voltage rise caused by DG units may become one of the limiting factors for the hosting capacity of wind power and photovoltaics in DNs. Increasing the hosting capacity by network rebuilding is possible but it is expensive and time consuming. Coordinated voltage control has been proposed to increase network capacity without the need of reinforcement. Simulations based on an existing medium and low voltage DN with wind power and photovoltaics are presented. It is shown that coordinated voltage control can increase the hosting capacity and avoid network reinforcement.

Electricity meters for coordinated voltage control in medium voltage networks with wind power

During the last years the amount of electricity generated by Distributed Energy Resources (DER), especially wind turbines, has been increasing a lot. These Distributed Generation (DG) units are often connected to rural distribution networks, where they have a large impact on the voltage and the network losses. The network voltage at the customers point of connection is an important quality criteria and has to follow different standards as e.g. EN 50160. Therefore the voltage change caused by the integration of production units in the distribution network is an important aspect when integrating more DG in distribution networks and often a limiting factor for the maximum DG capacity which is possible to integrate into an existing network without reinforcement. Using the available voltage band more efficient by applying coordinated voltage control is a possibility to increase the hosted DG capacity in an existing distribution network without reinforcement of the network. To get the actual network status the new generation of electricity meters, which have the feasibility to communicate real time voltage measurements from the customers side to a network controller, give some benefits to a more flexible and coordinated voltage control in the network. The voltage range in the network will be used adapted to the actual load and generation situation instead of using worst case assumptions as it is good practice until now. A main part of the voltage control in medium voltage distribution networks is done by the on-load tap changer (OLTC) which takes the voltage at the consumers point of connection into account. A generic 10 kV distribution network with three typical types of feeders, as pure load, pure generation and mixed load and generation feeder, has been outlined. Coordinated voltage control is implemented by a central voltage controller. Simulations on the voltage and the network losses have been done and will be presented in this paper. The maximum DG capacity in the test system increases most when introducing coordinated control of the OLTC but also the use of reactive power adds some benefit. Further increase of the DG capacity by more extensive use of curtailment is always possible but due to economical aspects not favoured.

Wind turbines voltage support in weak grids

This paper investigates how Full-Scale Converter (FSC) wind turbines can contribute to voltage support in weak grids. A novel voltage support strategy is proposed, which optimizes the voltage support during the fault. This strategy is compared to the voltage support required by two grid codes, the Danish and the German E.ON ones. The influence of a number of parameters, as the network X/R ratio, the voltage support controller gain and the post-fault power ramp is investigated. A sensitivity analysis with regard to uncertainties in the knowledge of the X/R ratio is performed. Finally, the voltage support provided by a wind power plant (WPP) is compared to that provided by a conventional power plant with synchronous generation. Simulation results indicate that a FSC WPP if properly controlled is able to provide a post-fault voltage support comparable to the one provided by a synchronous generator.

Long-term voltage collapse analysis on a reduced order nordic system model

This paper analyzes and explains the mechanism behind long-term voltage collapse in the NORDIC32 test system. For this purpose a simplified test system called N5area, reflecting the key voltage collapse characteristics of NORDIC32 is proposed. Applying control algorithms is much easier in N5area than in NORDIC32. Load recovery and generator excitation current limiter actions which are two important factors contributing to long-term voltage collapse are considered. Dynamic simulation results for a specified long-term voltage instability scenario are explained and discussed. The effect of generator current limiters is analyzed using PV curves. Furthermore, two different control strategies for controlling the shunt capacitors are applied as countermeasures to save the system. The two strategies are explained and compared and it is shown that control using the voltage at neighboring buses gives better performance.

Fault behavior of wind farms with fixed-speed and Doubly-Fed Induction Generators

This paper focuses on the fault current contribution of wind farms with Fixed-Speed (FSIG) and Doubly-Fed Induction Generators (DFIG). The fault current delivered by a single FSIG during both symmetrical and unsymmetrical faults is found analytically and validated through simulations. Simulations of a detailed model of a wind farm with several FSIG or DFIG are then performed to investigate the total fault current contribution at the Point of Common Coupling. The scope is to check the validity of a single-machine approach to predict the fault contribution of the wind farm. It has been found that both in the case of FSIG and DFIG wind farms, the single-machine approach is reasonable. For DFIG wind farms, the initial operating point of each DFIG has an important impact on its fault current and the single-machine should be given an initial slip close to the average slip of all DFIG in the wind farm.

VSC-HVDC application to improve the long-term voltage stability

This paper concerns the VSC-HVDC application to improve the long-term voltage stability. For this purpose the NORDIC32 test system is considered. All necessary dynamics to study the long-term voltage stability are included in the test system. An appropriate control strategy for VSC-HVDC is proposed in the paper. The goal is to reach the best condition from long-term voltage stability perspective with respect to system configuration and also the VSC-HVDC capability curve. To show the capability of the proposed control methodology, two long-term voltage instability scenarios are considered. For the first scenario, VSC-HVDC can lead to a stable condition with its initial active-reactive power set points. In the second voltage instability scenario which is more severe, the proper power flow change in the system using VSC-HVDC is needed to avoid the voltage collapse. Otherwise the VSC-HVDC could buy some time and lead to later collapse which is still important. The simulation results are explained and thoroughly discussed. It is demonstrated that with the proper control of VSC-HVDC, long-term voltage stability could improve dramatically.

Impedance Matching for VSC-HVDC Damping Controller Gain Selection

The impedance matching concept is employed in this paper to select the optimum gain of a VSC-HVDC damping controller. The damping controller of the DC-link is based on control of active power in proportion to the difference in local frequency at the VSC-HVDC converter stations. To explain impedance matching, the small-disturbance electro-mechanical dynamics of a power system is transformed to an equivalent LC circuit. The VSC-HVDC damping controller corresponds to introducing a resistor in the circuit model. Using impedance matching to select a resistor value in the circuit model is equivalent to selecting damping controller gain that gives the maximum damping ratio. An analytical derivation is conducted for a linearized model of a generic two-area power system, including an expression for the optimum gain. It is also shown how the concept may be employed without a circuit model and that the optimum value is hardly affected by changes in the power flow. Then, the performance of the proposed approach in multimode test systems and with nonlinearities is evaluated using dynamic simulations in DIgSILENT PowerFactory. The results show that the impedance matching maximizes the targeted mode damping ratio while nontargeted modes are not negatively impacted.

Impedance Matching for VSC–HVDC and Energy Storage Damping Controllers

The small-disturbance electromechanical dynamics of a power system can be translated to an equivalent circuit model with inductances and capacitances. Damping control of active power in proportion to local frequency as with a voltage source converter (VSC)–HVdc link or energy storage then corresponds to introducing a resistor in the circuit model. This letter shows that impedance matching can be used to select resistor value and, equivalently, damping controller gain, that gives maximum damping ratio. It is also shown how the concept is employed without a circuit model.

Dynamic and static analysis of the shunt capacitors control effect on the long-term voltage instability

This paper concerns the dynamic and static analysis of the effect of shunt capacitor control strategies on the long-term voltage instability. For this purpose a simplified test system called N3area, reflecting the key voltage instability characteristics of NORDIC32 is considered. Two different control strategies for shunt capacitors including the local and neighboring schemes are applied to improve the voltage control in the system. First the dynamic simulation results for a specified long-term voltage instability scenario are explained and discussed then the static investigation is conducted based on the PV curves and it is shown that the neighboring scheme injects more reactive power to the system. Afterward, based on the modal analysis technique and V-Q sensitivity analysis, it is demonstrated that the possibility of involving the most critical buses from voltage stability perspective in the capacitors connection decisions are much higher in the neighboring scheme compared to the local one. The two strategies are explained and compared in both dynamic and static analysis and it is shown that control using the voltage at neighboring buses gives better performance.