Hierarchical systems based on HV grid is divided into regions and on automatic coordination of each region’s reactive power generating element aiming to control local voltages have been established first in Italy and France since 1980. These systems are collectively termed either coordinated voltage control, to highlight the required coordination among region control sources, or they are also called secondary and tertiary voltage control levels (SecVC and TerVC), to emphasize the full image of the control hierarchy. Reference studies and applications come from Italy 1–9 and France 10–12, followed by Belgium 13, 14, Spain 15, 16 and more recently by United States, Brazil, Taiwan, South Korea, Romania and South Africa 17–22. An international CIGRE task force investigated the subject and, in 2005, published an extensive report 23. After 1990, based on experimental applications in voltage wide-area control systems, certain European countries (mainly Italy and France) employed general applications of voltage wide-area control systems as their actual grids. These projects lasted many years, for a great many reasons: its novelty; SCADA linked updates at dispatch control centers; unbundling of transmission and generation companies; and the growing emphasis at the beginning of 2000 on energy market rules in spite of improvements in power system control. With changing utilities organizing structure, and under the impetus of the energy market liberalization, hierarchical voltage control systems are becoming stronger and more appreciated 23–44, mainly where they are already operating, but elsewhere, too, as knowledge about them grows. Global Power system engineers, in fact, knew that both SecVC and TerVC enable the simplification of the complexity automatic control of transmission grid voltages overall by improving system efficiency and stability and the distinction of the contributions of different participants to voltage ancillary service in correct, simplified ways.
Progress and trends toward improvements in transmission grid voltage control require, at the beginning of 2000’s and under the concern of worldwide Smart Grids dream, an important evolution coming mostly from still operating “manual control” to innovative “automatic control”, through simple, effective closed-loop regulating systems, managed and supervised directly by electrical grid dispatching centers. Cost/benefit analyses strongly support this innovation 25–27. Moreover, because voltage control is mainly a local problem, any feasible solutions must consider automatic coordination of local reactive power resources, primarily those of generators and compensators but also of shunt capacitors and reactors, SVCs, STATCOMs, UPFCs and OLTCs. For this reason, the objectives of voltage ancillary service (quality and security improvements in network operation) can be pursued through a decentralized voltage control system which coordinates resources at each grid region. Such coordination requires data exchanges between regional control center and local plants/substations. The best policy was understood: “The more exchange there is of real-time electrical data in accordance with power system dynamics, the more improvement there will be in a voltage control system’s performance and effectiveness”.
The benefit of grid voltage control is high grid efficiency which becomes strongly linked to system with different regions coordination rather than source local control, requiring effective data exchange among regional (either geographical or virtual) centers and the national system control center. In addition to exchange of measurements with surrounding grids (e.g., node-bus voltages and connected lines or cables reactive power flows) and coordination of mutual control actions is also very important for reducing system losses. Within the framework of energy sector liberalisation and ancillary market competition, on-line and real-time monitoring of the performance of actual HV control systems also represents a challenging opportunity for a proper and undoubtable recognition of a power plant’s contribution to voltage stability 26. Definite improvements that result from coordinated “automatic” real-time voltage regulation can then be summarised as follows:
• Power system operation quality is improved, in terms of reduced variations around the defined voltages profile across the overall grid;
• Power system operation security is enhanced, in terms of larger reactive power reserves kept available by generating units for facing emergency conditions 28;
• Transfer capability of the power system is improved, in terms of increased active power levels transmissible, with reduced risk of voltage instability and collapse29;
• Power system operation efficiency is enhanced, in terms of active loss minimisation, reduction of reactive flows and better utilisation of reactive resources;
• Controllability and measurability of voltage ancillary service is simplified, in terms of defining functional requirements and performance monitoring criteria
Voltage and reactive power control of an electrical grid requires geographical and temporal coordination of many on-field components and control functions achievable by a hierarchical control structure. A real-time and automatic voltage control system can, in fact, be basically structured in three hierarchical levels: primary (component control), secondary (area control) and tertiary (power system control and optimisation) levels.
Figure 2.1 gives a preliminary spatial view of the three overlapping hierarchical levels of a voltage -reactive control system. It also shows the interaction of the tertiary level with the not-real-time and off-line forecasting level based on state estimation and optimal power flow (OPF). This scheme distinguishes real-time levels with automatic closed-loop voltage and reactive power controls from day-before or short term optimal forecasting computation (necessarily delayed with respect to real-time power system operating conditions). In doing so, it offers clarity that helps us recognise relevant differences between real-time and forecasting levels.
It often happens that the tertiary voltage (closed-loop) control is confused with the static optimisation problem of voltage-reactive power, which must be considered (due to its long delay with respect to a system’s operating conditions) as openloop control or off-line forecasting related to system operation scheduling.
The most commonly employed OPF objective function is power system loss minimisation, which forecasts, by the use of not-real-time data, the generators’ reactive power scheduling in order to maintain appropriate voltage levels within a power system’s normal operating limits. Obviously, higher performances are obtained with an automatic closed-loop voltage control that minimizes losses in real time (such as by TerVC) in comparison with a system operation based simply on a forecast computation linked to past working points (e.g., by OPF). In fact, a present grid operating condition could be, at times, very different from a forecasted one, mainly during critical operating conditions or in case of a great delay in the computation of a reliable state estimation.
Fig. 2.1 Voltage control Hierarchy implementation
The non-online OPF voltage-reactive power issue is, in any event, a useful input reference for TerVC computing, as shown in Fig. 2.1 and later fully described. In Fig. 2.1, the SecVC level is subdivided into two parts: the decentralized voltage control in the system regions (SecVC) overlaps the power station layer (secondary reactive power regulation), which controls the rotating generators, SVC, STATCOM and UPFC reactive powers. A dispatcher can interfere with the main control levels, mostly with not-real-time levels. He can also switch off the TerVC and manually define SecVC pilot node voltage set-point values, but in this case, it renounces on-line real time system optimization as well as the stability benefits deriving from TerVC. On the contrary, dispatcher manual control inside the SecVC level is to be avoided and is very dangerous for system security due to the criticality of the manual reactive power control at the high control speed provided by SecVC. In other words, SecVc should be fully automatic, while a manual TerVC can be managed by the dispatcher’s operator who, so doing, renounces the high reliability and efficiency that automatic TerVC provides.
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