Coordinating Generator Protection and Controls: An Overview

Keeping generators on line during a power system disturbance requires coordination of generator protection with generator controls. This article provides practical guidance on how to properly coordinate generator protection with governor and excitation system controls.

By Charles J. Mozina

Recent power system blackouts have led the North American Electric Reliability Corporation (NERC) to ask owners of generating facilities to verify coordination of generator protection and controls.1,2,3 The need to improve this coordination came to light as a result of incorrect operation of generator protection during major system disturbances, particularly the 2003 East Coast blackout. The techniques and methods to provide this coordination are scattered in textbooks, papers, and relay manufacturers’ literature. In many cases, these techniques are not well-known to the engineers who must implement them.

Every power system is subject to occasional transient disturbances — primarily due to short circuits or major load switches. Normally, the system adapts to a new steady-state condition with the help of two major generator control systems: the generator governor and excitation systems. In a power system, the governor controls system frequency and the excitation system controls voltage. This article provides insight into the methods to coordinate generator protection with these control systems, as well as to coordinate protection with generator megawatt (MW) and megavolt-ampere reactive (MVAR) capabilities.

Governor control and underfrequency coordination

The primary role of the governor control is to maintain proper speed regulation and load division for the generating units on the power system. For synchronous generators, speed (revolutions per minute) relates directly to frequency. If the generator experiences a sudden loss of load, it will momentarily speed up and increase frequency. The governor responds to the reduced output by closing gates to reduce the mechanical power.

Conversely, if the generator becomes overloaded, it will slow down and the frequency will drop. If the generator is at full load during an underfrequency event, no local control action can correct this overload problem. Underfrequency load shedding needs to take place across the entire system to match load to generation. For example, during major system disturbances, the power system typically breaks up into islands that consist of several plants. In these islands, typically there is a mismatch of load to generation. If load exceeds generation in an island, the frequency will drop as the aggregate generation within the island is overloaded — resulting in a reduction of generator speed. Again, system underfrequency load shedding is required. Underfrequency load shedding programs are universally applied on the North American power grid.

Because operating at low frequencies does not cause problems for hydro turbines, many of these units do not have underfrequency protection. However, some utilities do equip their hydro units to trip during sustained operation at low frequency. The rationale is that sustained operation at low frequency will damage customer load or other utility equipment within an island. Another reason for underfrequency tripping of hydro generators is that they can be only part of a utility’s total generation. When the company’s steam and gas turbines (which are damaged by operation at low frequency) trip due to underfrequency, the hydro units will be dramatically overloaded. Because of this situation, these hydro units are included in the utilities’ generator underfrequency protection program. Utilities must coordinate their generator underfrequency tripping with NERC regional load shedding programs.

Figure 1 shows the eight NERC control regions. Each region has established load shedding programs that require each utility to shed a percentage of its peak load at a pre-established frequency.

Table 1 on page 68 shows a typical example of underfrequency coordination requirements. These are the requirements of the Western Electricity Coordinating Council (WECC), which develops guidelines for the Western U.S. Other regions have similar guidelines. Generator underfrequency protection must be delayed to coordinate with system load shedding programs, and the times in the table provide the minimum times at various frequencies to provide that coordination.

Excitation control and system stability

A generator’s excitation system provides the energy for the magnetic field that keeps the generator synchronized with the power system. It injects direct current (DC) into the generator rotor field windings. In modern excitation systems, DC typically is obtained from an alternating current (AC) transformer connected to the generator terminal. The AC voltage is rectified to DC. To provide voltage to this transformer during start up, the field is flashed using a battery. In older excitation systems, the DC source was a small generator on the main generator shaft.

Figure 1: The North American Electric Reliability Corporation has eight control regions, each with established load shedding programs. The underfrequency protection system for a generator must coordinate with system load shedding. (The light blue areas in the center of the country are not a full part of any region but have a working relationship with SERC.)
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In addition to maintaining the generator synchronism, the excitation system affects the amount of reactive power the generator may absorb or produce. Increasing the excitation current increases the reactive power output and voltage. Decreasing the excitation has the opposite effect and, in extreme cases, may result in loss of generator synchronism with the power system. If the generator is operating in isolation from or is weakly tied to the power system and there are no other reactive power sources controlling terminal voltage, increasing the level of excitation current increases the generator terminal voltage.

Table 1: Underfrequency Coordination Requirements of the Western Electricity Coordinating Council
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The most commonly used voltage control mode for generators 10 MW or greater that are connected to a power system is automatic voltage regulation (AVR). In this mode, the excitation system helps maintain power system voltage within acceptable limits by supplying or absorbing reactive power, as required. In disturbances where short circuits depress the system voltage, electrical power cannot be fully delivered to the transmission system. The fast responses of the AVR and excitation system help increase the synchronizing torque to allow the generator to remain in synchronism with the system. After the short circuit is cleared, the resulting oscillations of the generator rotor speed with respect to system frequency will cause the terminal voltage to fluctuate above and below the AVR setpoint.

Excitation controls are needed to prevent unacceptable conditions being imposed upon the generator. These controls are the overexcitation and underexcitation limiters within the AVR. The overexcitation limiter prevents the AVR from trying to supply more excitation current than the system can supply or the generator field can withstand. The overexcitation limiter must limit excitation current before the generator field overvoltage protection operates. The underexcitation limiter prevents the AVR from reducing excitation to such a low level that the generator is in danger of losing synchronism, exceeding machine underexcitation capability, or tripping because it exceeds the loss-of-excitation protection setting. The overexcitation and underexcitation limiters are set to prevent the generator from operating outside its MW and MVAR capabilities (see Figure 2). The vector sum of the MW and MVAR equals the MVA limit. The generator is limited in its normal operating mode (overexcited) by the rotor and stator winding current limits. In the underexcited mode, the generator absorbs reactive power from the system to help control system high voltage.

Figure 2: This generator capability curve illustrates the role of the overexcitation and underexcitation limiters, designed to prevent the generator from operating outside its MW and MVAR capabilities.
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Generator steady-state stability

Steady-state instability occurs when there are too few transmission lines to transport power from the plant to the load center. When the voltage phase angle (the difference in phase angle between two voltage vectors) between the load center and a remote plant increases beyond 90 degrees, the power that can be transmitted is reduced. The system becomes unstable and usually splits into islands. If enough lines are tripped between the load center and the generating facilities supplying it, the reactance between these two sources increases to a point where the maximum power that can be transferred is insufficient to maintain synchronism. During unstable conditions, generators may slip poles and lose synchronism. Voltage collapse and steady-state instability can occur together as transmission line tripping increases the reactance between the load center and remote generation.

Loss-of-field relaying protection

The loss-of-field relay needs to be coordinated with the steady-state stability and the generator capability and underexcitation limiter. To control system high voltage, the generator may have to operate underexcited and absorb MVARs from the power system. This is especially true when the system breaks into islands during a major disturbance. It is important that the generator be able to absorb MVARs within its capabilities, as defined by the generator capability curve, to regulate system voltage. The generator underexcitation limiter must be set to maintain operation within the capability curve (see Figure 2). The loss-of-field relay must be set to allow the generator to operate within its underexcited capability.

Partial or total loss of field on a synchronous generator is detrimental to the generator and the connected power system. The condition must be quickly detected and the generator isolated from the system to avoid generator damage. A loss-of-field condition that is not detected can have a devastating effect on the power system by causing a loss of reactive power support and a substantial reactive power drain. This reactive drain, when the field is lost on a large generator, can cause a substantial system voltage dip. When the generator loses its excitation, it operates as an induction generator, causing the rotor and amortisseur bar temperature to rapidly increase due to the slip-induced eddy currents in the rotor iron. A loss-of-field condition can occur due to an open circuit in the DC supply to the generator field windings, a short circuit in the field windings, or an inadvertent tripping of the excitation system circuit breaker. When a loss-of-field condition occurs, the high reactive current drawn from the power system by the generator can overload the stator windings.

The most widely applied method for detecting a generator loss-of-field condition is the use of an impedance relay to sense the variation of impedance as viewed from the generator terminals. A two-zone impedance relay approach is widely used to provide high-speed detection. This relay is installed on the generator terminals. It measures generator current and voltage and calculates the resulting generator terminal impedance. The relay characteristic is a circle when plotted on an R-X (resistance-reactance) diagram. When the terminal impedance locus (as measured by the loss-of-field relay) enters the circle, the loss-of-field relay shuts down the generator. There are two basic designs of this type of protection; Figure 3 on page 70 shows the most popular.

This loss-of-field relay consists of two offset impedance characteristics (Zone 1 and Zone 2). An impedance circle diameter equal to the generator synchronous reactance and offset downward by half of the generator transient reactance is used for the Zone 2 element.

Operation of this element is delayed 30 to 45 cycles to prevent misoperation during a stable transient swing. A second relay zone (Zone 1) is set at an impedance diameter of one per unit (on the generator base), with the same offset of half of the generator transient reactance. This Zone 1 element has a few cycles of delay and more quickly detects severe loss-of-field conditions. When synchronous reactance is less than or equal to one per unit, only the Zone 2 element is used and is set with the diameter equal to one per unit.

Figure 2 illustrates the capability of a generator on a MW-MVAR diagram. This information is commonly available from all manufacturers. The generator loss-of-field relay measures impedance, thus these relay characteristics are displayed on an R-X diagram. To coordinate the generator capability with the loss-of-field relay, it is necessary to convert either the capability curve and excitation limiters to an R-X diagram or the impedance relay settings to a MW-MVAR plot.

Figure 3: Loss-of-field protection for a generator, as plotted on an R-X diagram, features two zones of protection (Zone 1 and Zone 2). When the impedance locus that originates from loss-of-field enters one of these zones, a relay shuts down the generator.
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In addition, there is a need to verify that the impedance loci during transient conditions, generally caused by transmission system short circuits, does not swing into the loss-of-field relay impedance characteristic, causing a false trip for a stable system transient. This requires computer transient stability studies, which generally are performed by utility company system planning engineers.


Misoperations of generator protection during major system disturbances highlight the need for better coordination of generator protection with generator control. This article provides practical guidance, specifically addressing the coordination of generator protection with generator full-load capability and machine steady-state stability. Setting of protective relays is an art as well as a science. The coordination methods discussed are generally accepted industry practices.4 However, other methodologies that affect the same results also could be used. Keeping generators on line during major system disturbances is a key goal that requires coordination of generator protection with generator control.


  1. “Standard PRC-001-0, System Protection Coordination,” North American Electric Reliability Corporation, Princeton, N.J., 2005.
  2. 2“Standard PRC-024-1, Generator Performance During Frequency and Voltage Excursions,” North American Electric Reliability Corporation, Princeton, N.J., Pending review and approval.
  3. 3“Standard PRC-019-1, Coordination of Generator Voltage Regulator Controls with Unit Capabilities and Protection,” North American Electric Reliability Corporation, Princeton, N.J., Pending review and approval.
  4. 4IEEE Guide for AC Generator Protection, Institute of Electrical and Electronics Engineers, New York, N.Y., 2006.

Chuck Mozina, P.E., is a consultant with Beckwith Electric Co. Inc. He has more than 25 years of experience as a protection engineer.

µ Peer Reviewed

This article has been evaluated and edited in accordance with reviews conducted by two or more professionals who have relevant expertise. These peer reviewers judge manuscripts for technical accuracy, usefulness, and overall importance within the hydroelectric industry.

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