Chapter 19

Reactive Power Compensation

19.1 Need for Reactive Power Compensation 19-1

Shunt Reactive Power Compensation • Shunt Capacitors

19.2 Application of Shunt Capacitor Banks in Distribution Systems: A Utility Perspective 19-2

19.3 Static VAR Control 19-4

Description of SVC • How Does SVC Work?

19.4 Series Compensation 19-6

19.5 Series Capacitor Bank 19-7

Description of Main Components • Subsynchronous Resonance • Adjustable Series Compensation • Thyristor-Controlled Series Compensation

19.6 Voltage Source Converter–Based Topologies 19-11

Basic Structure of a Synchronous Voltage Source • Operation of Synchronous Voltage Sources • Static Compensator • Static Series Synchronous Compensator • Unified Power Flow Controller

19.7 Defining Terms 19-19

References 19-19

Rao S. Thallam

Salt River Project

Géza Joós

McGill University

19.1 Need for Reactive Power Compensation

Except in a very few special situations, electrical energy is generated, transmitted, distributed, and utilized as alternating current (AC). However, AC has several distinct disadvantages. One of these is the necessity of reactive power that needs to be supplied along with active power. Reactive power can be leading or lagging. While it is the active power that contributes to the energy consumed, or transmitted, reactive power does not contribute to the energy. Reactive power is an inherent part of the “total power.” Reactive power is either generated or consumed in almost every component of the system, generation, transmission, and distribution and eventually by the loads. The impedance of a branch of a circuit in an AC system consists of two components, resistance and reactance. Reactance can be either inductive or capacitive, which contributes to reactive power in the circuit. Most of the loads are inductive, and must be supplied with lagging reactive power. It is economical to supply this reactive power closer to the load in the distribution system.

In this chapter, reactive power compensation, mainly in transmission systems installed at substations, is discussed. Reactive power compensation in power systems can be either shunt or series. Both will be discussed.

19.1.1 Shunt Reactive Power Compensation

Since most loads are inductive and consume lagging reactive power, the compensation required is usually supplied by leading reactive power. Shunt compensation of reactive power can be employed either at load level, substation level, or at transmission level. It can be capacitive (leading) or inductive (lagging) reactive power, although in most cases as explained before, compensation is capacitive. The most common form of leading reactive power compensation is by connecting shunt capacitors to the line.

19.1.2 Shunt Capacitors

Shunt capacitors are employed at substation level for the following reasons:

1. Voltage regulation: The main reason that shunt capacitors are installed at substations is to control the voltage within required levels. Load varies over the day, with very low load from midnight to early morning and peak values occurring in the evening between 4 and 7 pm. Shape of the load curve also varies from weekday to weekend, with weekend load typically low. As the load varies, voltage at the substation bus and at the load bus varies. Since the load power factor is always lagging, a shunt-connected capacitor bank at the substation can raise voltage when the load is high. The shunt capacitor banks can be permanently connected to the bus (fixed capacitor bank) or can be switched as needed. Switching can be based on time, if load variation is predictable, or can be based on voltage, power factor, or line current.
2. Reducing power losses: Compensating the load lagging power factor with the bus-connected shunt capacitor bank improves the power factor and reduces current flow through the transmission lines, transformers, generators, etc. This will reduce power losses (I2R losses) in this equipment.
3. Increased utilization of equipment: Shunt compensation with capacitor banks reduces kVA loading of lines, transformers, and generators, which means with compensation they can be used for delivering more power without overloading the equipment.

Reactive power compensation in a power system is of two types—shunt and series. Shunt compensation can be installed near the load, in a distribution substation, along the distribution feeder, or in a transmission substation. Each application has different purposes. Shunt reactive compensation can be inductive or capacitive. At load level, at the distribution substation, and along the distribution feeder, compensation is usually capacitive. In a transmission substation, both inductive and capacitive reactive compensations are installed.

19.2 Application of Shunt Capacitor Banks in Distribution Systems: A Utility Perspective

The Salt River Project (SRP) is a public power utility serving more than 720,000 (April 2000) customers in central Arizona. Thousands of capacitor banks are installed in the entire distribution system. The primary usage for capacitor banks in the distribution system is to maintain a certain power factor at peak loading conditions. The target power factor is 0.98 leading at system peak. This figure was set as an attempt to have a unity power factor on the 69 kV side of the substation transformer. The leading power factor compensates for the industrial substations that have no capacitors. The unity power factor maintains a balance with ties to other utilities.

The main purpose of the capacitors is not for voltage support, as the case may be at utilities with long distribution feeders. Most of the feeders in the SRP service area do not have long runs (substations are about 2 miles apart) and load tap changers on the substation transformers are used for voltage regulation.

The SRP system is a summer peaking system. After each summer peak, a capacitor study is performed to determine the capacitor requirements for the next summer. The input to the computer program for evaluating capacitor additions consists of three major components:

• Megawatts and megavars for each substation transformer at peak
• A listing of the capacitor banks with size and operating status at time of peak
• The next summer’s projected loads

By looking at the present peak MW and Mvars and comparing the results to the projected MW loads, Mvar deficiencies can be determined. The output of the program is reviewed and a listing of potential needs is developed. The system operations personnel also review the study results and their input is included in making final decisions about capacitor bank additions.

Once the list of additional reactive power requirements is finalized, determinations are made about the placement of each bank. The capacitor requirement is developed on a per-transformer basis. The ratio of the kvar connected to kVA per feeder, the position on the feeder of existing capacitor banks, and any concentration of present or future load are all considered in determining the position of the new capacitor banks. All new capacitor banks are 1200 kvar. The feeder type at the location of the capacitor bank determines if the capacitor will be pole-mounted (overhead) or pad-mounted (underground).

Capacitor banks are also requested when new feeders are being proposed for master plan communities, large housing developments, or heavy commercial developments.

Table 19.1 shows the number and size of capacitor banks in the SRP system in 1998. Table 19.2 shows the number of line capacitors by type of control.

Substation capacitor banks (three or four per transformer) are usually staged to come on and go off at specific load levels.

19.3 Static VAR Control

Static VAR compensators, commonly known as SVCs, are shunt-connected devices, vary the reactive power output by controlling or switching the reactive impedance components by means of power electronics. This category includes the following equipment:

Thyristor-controlled reactors (TCR) with fixed capacitors (FC)

Thyristor switched capacitors (TSC)

Thyristor-controlled reactors in combination with mechanically or thyristor switched capacitors

SVCs are installed to solve a variety of power system problems:

1. Voltage regulation
2. Reduce voltage flicker caused by varying loads like arc furnace, etc.
3. Increase power transfer capacity of transmission systems
4. Increase transient stability limits of a power system
5. Increase damping of power oscillations
6. Reduce temporary overvoltages
7. Damp subsynchronous oscillations

A view of an SVC installation is shown in Figure 19.1.

19.3.1 Description of SVC

Figure 19.2 shows three basic versions of SVC. Figure 19.2 shows configuration of TCR with fixed capacitor banks. The main components of an SVC are thyristor valves, reactors, the control system, and the step-down transformer.

19.3.2 How Does SVC Work?

As the load varies in a distribution system, a variable voltage drop will occur in the system impedance, which is mainly reactive. Assuming the generator voltage remains constant, the voltage at the load bus will vary. The voltage drop is a function of the reactive component of the load current, and system and transformer reactance. When the loads change very rapidly, or fluctuate frequently, it may cause “voltage flicker” at the customers’ loads. Voltage flicker can be annoying and irritating to customers because of the “lamp flicker” it causes. Some loads can also be sensitive to these rapid voltage fluctuations.

An SVC can compensate voltage drop for load variations and maintain constant voltage by controlling the duration of current flow in each cycle through the reactor. Current flow in the reactor can be controlled by controlling the gating of thyristors that control the conduction period of the thyristor in each cycle, from zero conduction (gate signal off) to full-cycle conduction. In Figure 19.2, for example, assume the MVA of the fixed capacitor bank is equal to the MVA of the reactor when the reactor branch is conducting for full cycle. Hence, when the reactor branch is conducting full cycle, the net reactive power drawn by the SVC (combination of capacitor bank and TCR) will be zero. When the load reactive power (which is usually inductive) varies, the SVC reactive power will be varied to match the load reactive power by controlling the duration of the conduction of current in the thyristor-controlled reactive power branch. Figure 19.3 shows current waveforms for three conduction levels, 60°, 120°, and 180°. Figure 19.3 shows waveforms for thyristor gating angle (α) of 90°, which gives a conduction angle (σ) of 180° for each thyristor. This is the case for full-cycle conduction, since the two back-to-back thyristors conduct in each half-cycle. This case is equivalent to shorting the thyristors. Figure 19.3 is the case when the gating signal is delayed for 30° after the voltage peak, and results in a conduction angle of 120°. Figure 19.3 is the case for α = 150° and σ = 60°.

With a fixed capacitor bank as shown in Figure 19.2, it is possible to vary the net reactive power of the SVC from 0 to the full capacitive VAR only. This is sufficient for most applications of voltage regulation, as in most cases only capacitive VARs are required to compensate the inductive VARs of the load. If the capacitor can be switched on and off, the Mvar can be varied from full inductive to full capacitive, up to the rating of the inductive and capacitive branches. The capacitor bank can be switched by mechanical breakers (see Figure 19.2) if time delay (usually 5–10 cycles) is not a consideration, or they can be switched fast (less than 1 cycle) by thyristor switches (see Figure 19.2).

Reactive power variation with switched capacitor banks for an SVC is shown in Figure 19.4.

19.4 Series Compensation

Series compensation is commonly used in high-voltage AC transmission systems. They were first installed in the late 1940s. Series compensation increases power transmission capability, both steady state and transient, of a transmission line. Since there is an increasing opposition from the public to construction of EHV transmission lines, series capacitors are attractive for increasing the capabilities of transmission lines. Series capacitors also introduce some additional problems for the power system. These will be discussed later.

Power transmitted through the transmission system (shown in Figure 19.5) is given by

$P_2=\frac{V_1\cdot V_2\cdot \sin \delta }{X_L}$ (19.1)

where

P2 is the power transmitted through the transmission system

V1 is the voltage at sending end of the line

V2 is the voltage at receiving end of transmission line

XL is the reactance of the transmission line

δ is the phase angle between V1 and V2

Equation 19.1 shows that if the total reactance of a transmission system is reduced by installing capacitance in series with the line, the power transmitted through the line can be increased.

With a series capacitor installed in the line, Equation 19.1 can be written as

$P_2=\frac{V_1\cdot V_2\cdot \sin \delta }{X_L-X_C}$ (19.2)

$=\frac{V_1\cdot V_2\cdot \sin \delta }{X_L(1-K)}$ (19.3)

where K = XC/XL is the degree of compensation, usually expressed in percent. A 70% series compensation means the value of the series capacitor in ohms is 70% of the line reactance.

19.5 Series Capacitor Bank

A series capacitor bank consists of a capacitor bank, overvoltage protection system, and a bypass breaker, all elevated on a platform, which is insulated for the line voltage. See Figure 19.6. The overvoltage protection is comprised of a zinc oxide varistor and a triggered spark gap, which are connected in parallel to the capacitor bank, and a damping reactor. Prior to the development of the high-energy zinc oxide varistor in the 1970s, a silicon carbide nonlinear resistor was used for overvoltage protection. Silicon carbide resistors require a spark gap in series because the nonlinearity of the resistors is not high enough. The zinc oxide varistor has better nonlinear resistive characteristics, provides better protection, and has become the standard protection system for series capacitor banks.

The capacitor bank is usually rated to withstand the line current for normal power flow conditions and power swing conditions. It is not economical to design the capacitors to withstand the currents and voltages associated with faults. Under these conditions, capacitors are protected by a metal oxide varistor (MOV) bank. The MOV has a highly nonlinear resistive characteristic and conducts negligible current until the voltage across it reaches the protective level. For internal faults, which are defined as faults within the line section in which the series capacitor bank is located, fault currents can be very high. Under these conditions, both the capacitor bank and MOV will be bypassed by the “triggered spark gap.” The damping reactor (D) will limit the capacitor discharge current and damps the oscillations caused by spark gap operation or when the bypass breaker is closed. The amplitude, frequency of oscillation, and rate of damping of the capacitor discharge current will be determined by the circuit parameters, C (series capacitor), L (damping inductor), and resistance in the circuit, which in most cases are losses in the damping reactor.

A view of series capacitor bank installation is shown in Figure 19.7.

19.5.1 Description of Main Components

19.5.1.1 Capacitors

The capacitor bank for each phase consists of several capacitor units in series–parallel arrangement, to make up the required voltage, current, and Mvar rating of the bank. Each individual capacitor unit has one porcelain bushing. The other terminal is connected to the stainless steel casing. The capacitor unit usually has a built-in discharge resistor inside the case. Capacitors are usually all film design with insulating fluid that is non-PCB. Two types of fuses are used for individual capacitor units—internally fused or externally fused. Externally fused units are more commonly used in the United States. Internally fused capacitors are prevalent in European installations.

19.5.1.2 Metal Oxide Varistor

A metal oxide varistor (MOV) is built from zinc oxide disks in series and parallel arrangement to achieve the required protective level and energy requirement. One to four columns of zinc oxide disks are installed in each sealed porcelain container, similar to a high-voltage surge arrester. A typical MOV protection system contains several porcelain containers, all connected in parallel. The number of parallel zinc oxide disk columns required depends on the amount of energy to be discharged through the MOV during the worst-case design scenario. Typical MOV protection system specifications are as follows.

The MOV protection system for the series capacitor bank is usually rated to withstand energy discharged for all faults in the system external to the line section in which the series capacitor bank is located. Faults include single-phase, phase-to-phase, and three-phase faults. The user should also specify the fault duration. Most of the faults in EHV systems will be cleared by the primary protection system in three to four cycles. Backup fault clearing can be from 12 to 16 cycles duration. The user should specify whether the MOV should be designed to withstand energy for backup fault clearing times. Sometimes it is specified that the MOV be rated for all faults with primary protection clearing time, but for only single-phase faults for backup fault clearing time. Statistically, most of the faults are single-phase faults.

The energy discharged through the MOV is continuously monitored and if it exceeds the rated value, the MOV will be protected by the firing of a triggered air gap, which will bypass the MOV.

19.5.1.3 Triggered Air Gap

The triggered air gap provides a fast means of bypassing the series capacitor bank and the MOV system when the trigger signal is issued under certain fault conditions (e.g., internal faults) or when the energy discharged through the MOV exceeds the rated value. It typically consists of a gap assembly of two large electrodes with an air gap between them. Sometimes two or more air gaps in series can also be employed. The gap between the electrodes is set such that the gap assembly sparkover voltage without trigger signal will be substantially higher than the protective level of the MOV, even under the most unfavorable atmospheric conditions.

19.5.1.4 Damping Reactor

A damping reactor is usually an air-core design with parameters of resistance and inductance to meet the design goal of achieving the specified amplitude, frequency, and rate of damping. The capacitor discharge current when bypassed by a triggered air gap or a bypass breaker will be damped oscillation with amplitude, rate of damping, and frequency determined by circuit parameters.

19.5.1.5 Bypass Breaker

The bypass breaker is usually a standard line circuit breaker with a rated voltage based on voltage across the capacitor bank. In most of the installations, the bypass breaker is located separate from the capacitor bank platform and outside the safety fence. This makes maintenance easy. Both terminals of the breaker standing on insulator columns are insulated for the line voltage. It is usually an SF6 puffer-type breaker, with controls at ground level.

19.5.1.6 Relay and Protection System

The relay and protection system for the capacitor bank is located at ground level, in the station control room, with information from and to the platform transmitted via fiber-optic cables. The present practice involves all measured quantities on the platform being transmitted to ground level, with all signal processing done at ground level.

19.5.2 Subsynchronous Resonance

Series capacitors, when radially connected to the transmission lines from the generation near by, can create a subsynchronous resonance (SSR) condition in the system under some circumstances. SSR can cause damage to the generator shaft and insulation failure of the windings of the generator. This phenomenon is well described in several textbooks, given in the reference list at the end of this chapter.

19.5.3 Adjustable Series Compensation

The ability to vary the series compensation will give more control of power flow through the line, and can improve the dynamic stability limit of the power system. If the series capacitor bank is installed in steps, bypassing one or more steps with bypass breakers can change the amount of series compensation of the line. For example, as shown in Figure 19.8, if the bank consists of 33% and 67% of the total compensation, four steps, 0%, 33%, 67%, and 100%, can be obtained by bypassing both banks, smaller bank (33%), larger bank (67%), and not bypassing both banks, respectively.

Varying the series compensation by switching with mechanical breakers is slow, which is acceptable for the control of steady-state power flow. However, for improving the dynamic stability of the system, series compensation has to be varied quickly. This can be accomplished by thyristor-controlled series compensation (TCSC).

19.5.4 Thyristor-Controlled Series Compensation

Thyristor-controlled series compensation (TCSC) provides fast control and variation of the impedance of the series capacitor bank. To date (1999), three prototype installations, one each by ABB, Siemens, and the General Electric Company (GE), have been installed in the United States. TCSC is part of the flexible AC transmission system (FACTS), which is an application of power electronics for control of the AC system to improve the power flow, operation, and control of the AC system. TCSC improves the system performance for SSR damping, power swing damping, transient stability, and power flow control.

The latest of the three prototype installations is the one at the Slatt 500 kV substation in the Slatt–Buckley 500 kV line near the Oregon–Washington border in the United States. This is jointly funded by the Electric Power Research Institute (EPRI), the Bonneville Power Administration (BPA), and the General Electric Company (GE). A one-line diagram of the Slatt TCSC is shown in Figure 19.9. The capacitor bank (8 Ω) is divided into six identical TCSC modules. Each module consists of a capacitor (1.33 Ω), back-to-back thyristor valves controlling power flow in both directions, a reactor (0.2 Ω), and a varistor. The reactors in each module, in series with thyristor valves, limit the rate of change of current through the thyristors. The control of current flow through the reactor also varies the impedance of the combined capacitor–reactor combination, giving the variable impedance. When thyristor gating is blocked, complete line current flows through the capacitance only, and the impedance is 1.33 Ω capacitive (see Figure 19.10). When the thyristors are gated for full conduction (Figure 19.10), most of the line current flows through the reactor-thyristor branch (a small current flows through the capacitor) and the resulting impedance is 0.12 Ω inductive. If thyristors are gated for partial conduction only (Figure 19.10), circulating current will flow between capacitor and inductor, and the impedance can be varied from 1.33 to 4.0 Ω, depending on the angle of conduction of the thyristor valves. The latter is called the vernier operating mode.

The complete capacitor bank with all six modules can be bypassed by the bypass breaker. This bypass breaker is located outside the main capacitor bank platform, similar to the case for the conventional series capacitor bank. There is also a reactor connected in series with the bypass breaker to limit the magnitude of capacitor discharge current through the breaker. All reactors are of air-core dry-type design and rated for the full line current rating. MOVs connected in parallel with the capacitors in each module provide overvoltage protection. The MOV for a TCSC requires significantly less energy absorption capability than is the case for a conventional series capacitor of comparable size, because gating of thyristor valves provides quick protection for faulted conditions.

19.6 Voltage Source Converter–Based Topologies

The alternative to thyristor-based compensators, in either a shunt configuration (SVC) or a series configuration (TCSC), is to make use of synchronous voltage source controllers based on voltage source converter topologies. These converters employ force-commutated switching devices, with turn-on and turn-off capabilities, rather than thyristors, which can only be turned on. Force-commutated devices are derived either from the thyristor technology, the gate turn-off thyristor (GTO), and the improved switch, the integrated gate-commutated thyristors (IGCT), or from transistor technologies. The more common and universally used switch today is the insulated gate bipolar transistor (IGBT).

19.6.1 Basic Structure of a Synchronous Voltage Source

Force-commutated switches allow the implementation of self-commutated converters, which can generate an arbitrary waveform. They do not need to be connected and synchronized to an AC source to operate, as is the case with thyristor-based converters. Thyristor converters require an AC grid voltage to commutate or turn off the thyristors.

In self-commutated converters, the switching of the devices on a DC bus, defined by means of a capacitor, can be done in such a way as to produce a synthetic AC voltage at the AC terminal of the converter of an arbitrary shape, with an amplitude, frequency, and phase that are set by the converter gating and control system. When producing a sinusoidal AC voltage source and synchronized to the AC grid, these converters become synchronous voltage sources.

The basic topology for the voltage source converter is the six-switch full-bridge topology, most commonly used in many low and medium power applications, but also in high power applications (Figure 19.11). A square wave can be produced by switching the devices appropriately once per AC cycle. It has a fully controllable fundamental amplitude, frequency, and phase (Figure 19.12). The amplitude is dictated by the magnitude of the DC bus voltage, the frequency by a clock, and the phase by the position of the gating signal with respect to an AC reference waveform (the AC grid in compensators).

The output voltage consists of a fundamental voltage component, and low-order harmonics of frequency (6n ± 1) and amplitude 1/n, where n varies from 1 to infinity. The dominant harmonics for a three-phase waveform using fundamental switching frequency gating are the 5th, 7th, 11th, and 13th harmonics (Figure 19.13).

Harmonics can be reduced or eliminated using any one of the following methods or combinations of methods:

• Harmonic filters: These typically are passive LC tuned filters or low pass LC filters.
• Phase shifting transformers: By connecting n converters in series, for example, and feeding them with voltages that are phase shifted 60°/n, lower-order harmonics can be eliminated. For two converters fed from transformer secondary voltages shifted by 30°, the harmonics of order 5 and 7 are eliminated, leaving the 11th and 13th as the dominant harmonics.
• Pulse width modulation (PWM) techniques: The principle consists of introducing notches in the output AC voltage, such that a number of harmonic components are eliminated (or reduced) in the output waveform. There are a number of such techniques available. At low switching frequencies, the selective harmonic elimination (SHE) approach is used (Figure 19.13). At higher switching frequencies, techniques based on a carrier, such as a triangular carrier (Sine PWM), or on computations, such as space vector modulation techniques, naturally eliminate low-frequency harmonic components in the AC voltage.
• Multi-level and multi-module structures: Multiple levels can be created in the output voltage of a converter by using a number of topologies; the better known is the diode clamped capacitor multi-level inverter, usually in a three-level configuration. An alternative is to connect a number of basic converter modules in series, such as the two-level converter, appropriately phase shifted to eliminate a given number of harmonics at the combined output of the converter.
• Modular multi-level structures: In high-voltage and high-power applications, the use of a large number of low voltage devices in series is required to obtain the required AC output voltage magnitude. This is the case with any line-connected high-voltage compensator. Switching devices can then be configured in modules, each capable of a controlled low voltage output. A large number of these modules are then connected in series and gated appropriately to achieve a stepped AC waveform. With a large number of steps, an output voltage waveform that is close to sinusoidal is synthesized. This practically eliminates the need of filtering the AC waveform.

The amplitude of the output AC voltage is controlled either by varying the amplitude of the DC bus voltage or by using a PWM technique. The latter technique is preferred. There are a number of such techniques available. At low switching frequencies, the SHE approach is used (Figure 19.13), where the amplitude of the fundamental component of the voltage is one of the harmonic components controlled. At higher switching frequencies, techniques based on a carrier, such as a triangular carrier (Sine PWM), or on computations, such as space vector modulation techniques, can be used.

The frequency and phase of the AC voltage are synchronized with the AC grid by means of a phase-locked loop (PLL) for example, when the converter is connected to the electric grid and used as a compensator. The phase of the AC voltage is set by the phase relation between the switch gating signals and the AC grid.

When connected to an AC grid, a coupling inductance must be provided, since the converter, being a matrix of switches, is essentially a voltage source (Figure 19.11). This inductance can be provided by the coupling transformer and/or by an appropriately sized inductor.

19.6.2 Operation of Synchronous Voltage Sources

When connected to the AC grid, and assuming the general case of a power source on the DC side, the angle δ between the AC supply Vs and the fundamental component of the converter AC output voltage Vi can be set to any desired value (Figure 19.14). This angle defines the amount of power flowing between the converter DC bus and the AC supply. This power is controlled by the phase shift between the AC supply and the gating pattern of the converter AC voltage, and by its amplitude. The converter is reversible and the power transfer, neglecting losses, is given by the equation dictating the exchange of power between two synchronous AC sources:

$P=3\frac{V_i{V}_s}{X}\text{sin}\delta$ (19.4)

where X is the coupling reactance and voltages are expressed on a per-phase basis.

In addition, the converter can be operated at a leading or lagging power factor. The reactive power is given by

$Q=3\frac{V_i(V_i-V_s\text{cos}\delta )}{X}$ (19.5)

Operation is possible in all four quadrants of the Q–P plane (Figure 19.15). However, this requires that energy sources or storage devices be connected to the DC bus to supply or absorb real power. The more common storage devices in power systems are electric storage batteries and superconducting magnet energy storage (SMES) devices. This gives additional flexibility to the compensator in supporting the electric grid voltage.

The basic synchronous voltage source discussed previously can be connected to the grid in a shunt configuration. This is the basic structure of a static compensator (STATCOM). The same synchronous source can also be connected in series with the AC grid through a series transformer. It then implements a static synchronous series compensator (SSSC). Finally, because of the presence of the DC bus, a shunt and a series unit can share the same DC bus. The shunt-series structure is known as the unified power flow controller (UPFC).

It should be noted that most of the structures using synchronous voltage sources and presented next can be applied to, and have found applications, in transmission as well as distribution systems.

19.6.3 Static Compensator

A static compensator (STATCOM) provides variable reactive power from lagging to leading (Figure 19.16), but with no inductors or capacitors required for var generation, as demonstrated in the preceding section. Reactive power generation is achieved by regulating the terminal voltage of the converter. If the terminal voltage Vi of the voltage source converter is higher than the AC bus voltage, the STATCOM produces leading reactive power, that is, it operates as a capacitor. If Vi is lower than the bus voltage, it produces lagging reactive power (Figure 19.14). No net energy is required in this operation, other than supplying the losses associated with the STATCOM operation and with the DC bus capacitor.

The reactive power generated or absorbed by the STATCOM is not a function of the size of the capacitor on the DC bus of the converter, which only sets the value of the DC bus voltage. The capacitor voltage is regulated by the load angle between the converter voltage and the AC grid voltage, as per Equation 19.4. The capacitor is rated to limit only the ripple current, and hence the harmonics in the output voltage.

Unlike the SVC, the reactive current or power that can be injected into the AC grid does not depend upon the AC voltage, since the reactive power is not produced by means of capacitors and inductors, but by a synthetic voltage source defined by the DC bus. So long as the DC capacitor remains charged to its rated value, the compensator can deliver its rated current. Because of this feature, the STATCOM is capable of supplying rated currents down to low AC grid voltages. It is also capable of producing currents that are larger than rated, with short-term overload values and durations dependent on the design of the converter switches and cooling system.

The performance of the STATCOM is similar to that of a synchronous condenser (unloaded synchronous motor with varying excitation). However, the dynamic response is faster than that of a synchronous condenser and of an SVC, if switched at a frequency higher than fundamental frequency, as with PWM, for example. A STATCOM is more effective than an SVC for arc furnace flicker control because of its dynamic range.

The first demonstration STATCOM of ±100 Mvar rating was installed at the Tennessee Valley Authority’s Sullivan substation in 1994 (Figure 19.17). To extend the range of the STATCOM in the capacitive region (with the inductive limit dictated by the STATCOM to 100 Mvar), mechanically switched capacitor banks are added. The control system (Figure 19.18) is similar to that of the typical SVC, with slope control as required. The controller also incorporates a reactive current inner loop and a synchronizing block (PLL).

The advantage of using the STATCOM in this installation has been the fast and coordinated response that it enables, particularly under contingencies. This has allowed deferral of the construction of an additional line or the use of a second transformer bank, resulting in significant cost savings.

STATCOM devices with storage have been successfully implemented, mostly at the distribution level and using the following storage devices: (a) battery storage on the DC bus, to achieve better ride-through and voltage regulation for critical loads in the case of faults and momentary loss of mains; (b) SMES, for applications in transmission and distribution, to support the system voltage in the case of faults on the system; recovery from faults has been found to be faster with the real power injection capability provided by the use of the stored energy.

19.6.4 Static Series Synchronous Compensator

The converter used in a STATCOM can also be used in the SSSC. This device is coupled to the AC grid by means of a series transformer (Figure 19.19), in place of a shunt transformer. It injects a voltage in quadrature with the AC line current, either leading or lagging, rather than injecting a controlled amount of leading or lagging reactive current, as in a STATCOM.

Since the equivalent reactance is the ratio of injected voltage over the line current, the SSSC can be used to emulate a variable inductor or capacitor in series with the line. As a variable series capacitor, it can be used in place of TCSC, with a more controllable characteristic and a faster dynamic response.

19.6.5 Unified Power Flow Controller

The DC bus of a STATCOM and of an SSSC can be connected together (Figure 19.20) to produce a device named the UPFC. It can exhibit the characteristics of both the STATCOM with shunt current injection, and the SSSC with series voltage injection, with added features. The device has 3 degrees of freedom, control of the reactive powers on the shunt and series connections, and of real power flowing through the common DC bus. This in turn allows real power injection on the shunt and series connections. The DC bus voltage is usually regulated from the shunt side, in a manner similar to a STATCOM.

Power injection on the shunt and series connections increases the flexibility and the number of modes of operation of the UPFC (Figure 19.20). In particular, the STATCOM and the SSSC can be operated the same way as the basic device, and if desired, with the added features provided such as real power injection. Among these are (a) the operation of the series side as a phase shifter, with real power being provided by the DC bus through the shunt side; (b) the operation as a variable line resistance injection (positive or negative), modifying the apparent resistance of the line and therefore the line X/R ratio; this is made possible by injecting real power on the series transformer, the power being provided by the shunt side.

The UPFC has been implemented and tested in an NYPA substation (Figure 19.21) in the form of a convertible static compensator (CSC). Since the converters in the STATCOM and the SSSC have the same rating and configuration, it is possible to have two independent converters, each with its own DC bus, to produce, among others, the following combinations: (1) one STATCOM of a power equal to that of two converters operating in parallel; (2) one SSSC of a power equal to that of two converters operating in parallel; (3) one STATCOM and one SSSC, each of a rating equal to that of one converter; (4) the coupled operation of the STATCOM and SSSC to form a UPFC; or (5) the coupled operation of two SSSCs on separate lines to form an interline power flow controller (IPFC), allowing the interchange of power between the two lines.

The potential benefits include (a) improving the voltage support and control; (b) increasing the power transfer capability through the substation; (c) relieving power transfer bottlenecks; (d) maximizing utilization of the transmission system; and (e) reducing power losses on the lines.

19.7 Defining Terms

Shunt capacitor bank: A large number of capacitor units connected in series and parallel arrangement to make up the required voltage and current rating, and connected between the high-voltage line and ground, between line and neutral, or between line and line.

Voltage flicker: Commonly known as “flicker” and “lamp flicker” is a rapid and frequent fluctuation of supply voltage that causes lamps to flicker. Lamp flicker can be annoying, and some loads are sensitive to these frequent voltage fluctuations.

Subsynchronous resonance: Per IEEE, SSR is an electric power system condition where the electric network exchanges energy with a turbine generator at one or more of the natural frequencies of the combined system below the synchronous frequency of the system.

References

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