During a voltage sag or swell due to a short‐circuit fault, lightning or capacitor bank switching on an adjacent distribution line, the bypass‐switch opens and a voltage that is generated by the VSC is placed in series with the load through a coupling transformer to restore the load’s nominal voltage while the conventional system protection equipment clears the fault.
Since a DVR is installed upstream of a sensitive load, it senses the sagged or swelled voltage on its input terminals. The DVR control system is such that it continually compares the input voltage waveform with an internal reference voltage signal and determines the proper voltage that must be added or subtracted to restore the nominal voltage at the load terminals. Figure 1-22 shows a sag correction by a DVR during a field test. The sag occurred in one phase, which was corrected within a few ms.
A DVR is generally designed to store a fixed amount of energy that can be used for voltage compensation during a designated amount of time, for example, 30 fundamental frequency cycles during a voltage sag or swell. This designated amount of time may be adequate to protect a sensitive load, such as a semiconductor manufacturing plant from a voltage sag or swell. However, in some applications where the input voltage to a critical load requires a continuous regulation within a specified range, the guaranteed voltage support for 30 fundamental cycles may be a limitation. This deficiency can be mitigated by a more general controller, which was designed in the 1980s and called an Active Power Line Conditioner (APLC). This electronic circuit topology was patented by Westinghouse in 1987 (U.S. patent number 4,651,265, titled “Active Power Conditioner System”). The APLC introduced the concept of a common DC link between two forced‐commutated switch‐based VSCs, which are connected back‐to‐back at their common DC link. One VSC is connected in shunt and another is connected in series with the line that supplies a load. These VSCs exchange active power (Plink) between the shunt‐ and series‐connected VSCs for continuous regulation of line voltage in distribution‐level applications as shown in Figure 1-23a.
Figure 1-22 Sag correction by a DVR (field performance) (Sen 2015).
The APLC extends the concept of an autotransformer, which is also a Shunt–Series configuration, meaning one unit is connected in shunt and the other unit is connected in series with the line. The APLC configuration, shown in Figure 1-23a, is identical to a stepdown autotransformer that supplies power to a load on the low‐voltage side. The major difference between an APLC and an autotransformer is that the Shunt and the Series Units in an autotransformer exchange active power as well as reactive power. However, in an APLC, only active power is exchanged between the Shunt and the Series Units, since reactive power cannot flow through the common DC link capacitor. The same Shunt–Series VSCs concept was used later in the 1990s in the design of the Unified Power Flow Controller (UPFC) for regulation of line power in transmission‐level applications as shown in Figure 1-23b.
The lessons learned from the installations of the first‐generation FACTS controllers, such as ±160 MVA‐rated UPFC at American Electric Power (AEP), ±100 MVA‐rated CSC at New York Power Authority (NYPA), and ±80 MVA‐rated UPFC at Korea Electric Power Corporation (KEPCO), are that FACTS controllers have limited applications due to their high life‐time costs, which include installation, operation, and maintenance (specialized equipment and trained labor). The main feature of very fast (millisecond‐range) response time, offered by the power electronics inverter‐based FACTS controllers is not needed in most utility applications. In search for the right PFC at an affordable price, the Shunt–Series configuration is used to create the Sen Transformer, which can provide a solution to meet the majority of power flow control needs for the utilities worldwide.
Figure 1-23 (a) Basic circuits for Active Power Line Conditioner and (b) Unified Power Flow Controller.
1.4 Cost of a Solution
The costs presented in this section are Rough Order Magnitude (ROM) that is based on authors’ past three decades of experience on various technologies. This section provides an illustration/methodology for economic appraisal of different technologies that offer similar outcomes.
1.4.1 Defining a Cost‐Effective Solution
The voltage/power flow compensation in the transmission/distribution network results in a higher asset utilization. The types of solutions may vary from using transformer and LTCs to power electronics inverters. Each of these solutions is based on engineering trade‐offs. In particular, as the response times of various solutions increase from slow (3–5 s) to medium speed (<1 s) to fast (<0.010 s), there is a corresponding increase in the solution’s life‐cycle costs (installation, operation, and maintenance), complexity, and impracticability of relocation. Other important features to consider are reliability, robustness, efficiency, component non‐obsolescence, and interoperability.
It is recognized that the superior response capability of a power electronics inverter‐based solution may be beneficial in applications where voltage flicker is caused by an electric arc furnace load and dynamic voltage restoration is required for critical loads. The final selection of a solution, however, depends on knowing the functional requirements and analyzing the cost and benefit of each available solution that means the most features at the least total cost. In the case of a simple voltage regulation at a utility bus, an SC may be an adequate solution, whereas for an arc furnace load, the power electronics inverter may be the best solution.
Consider the three cases (Case 1: “do nothing;” Case 2: “do something;” and Case 3: “go above‐and‐beyond”) of solutions for voltage regulation.
Figure 1-24 Cost versus features in various solutions (Case 1: “do nothing;” Case 2: “do something;” and Case 3: “go above and beyond.”)
Case 1 represents a “do nothing” approach where the solution cost (i.e. cost #1) is zero; but the lost opportunity cost (i.e. cost #2), which is the cost of not providing a solution, such as penalty for causing a voltage flicker may be the highest as shown in Figure 1-24.
Case 2 represents a “do something” approach where the solution cost (cost #1) increases as the number of features in the solution increases. For example, a shunt‐connected reactor or capacitor with a breaker may seem to be the simplest solution where the solution cost (cost #1) is greater than zero; however, the lost opportunity cost (cost #2) that accounts for the (1) penalty for not providing var support and (2) penalty for creating voltage flicker may be less than that in Case 1.
Case 3 represents a “go above‐and‐beyond” approach where the solution cost (cost #1) increases further as the number of features in the solution increases.