I. INTRODUCTION
This article discusses why voltage as well as frequency load shedding may be necessary to prevent major system blackouts. It is the first of two articles on the important subjects of power system voltage collapse and undervoltage load shedding. The first article will discuss the causes of system voltage collapse while the second article will propose schemes to address the problem. The second article (part2) will be in the next issue of T&D. Investigations of recent blackouts [1,3,7] indicate that the root cause of almost all of these major power system disturbances is voltage collapse rather than the underfrequency conditions prevalent in the blackouts of the 1960 and –‘70s. This article explores the nature of recent power system blackouts (2003 east coast, 1996 California and others) and explains why voltage collapse is the leading edge indicator of impending power system problems. Part 2 of this article will discusses the design and security issues that need to be addressed in the design of an undervoltage load shedding (UVLS) scheme and why relying on underfrequency load shedding (UFLS) maybe “too little, too late.” Part 2 will also address the current level of UVLS on utility systems as well as current NERC (North American Electric Reliability Council) pronouncements on the subject.
II. WHY VOLTAGE COLLAPSE IS THE CAUSE OF RECENT BLACKOUTS
Power systems today are much more susceptible to voltage collapses than they were 35 years ago as we increasingly depend on generation sources that are located remotely from load centers. Generators in eastern Canada and the midwestern U.S. provide large amounts of power to east coast load centers such as New York City. Generators in Washington, Oregon and western Canada provide substantial power to southern California. Two factors promote generation that is remote from load centers:
• The economics of purchasing power from lower-cost remote sources rather than more expensive local generation.
• The public’s reluctance/refusal to permit new generating plants to be built in urban high-load areas, causing utilities/IPPs to build these plants remote from these load centers.
These two fundamental changes in operation of the U.S. power grid result in the transmission of power over long distances. This makes the power grid very dependent on the transmission system to deliver power to the load centers. It also results in increased reactive power losses when transmission lines trip.
Another key factor that results in rapid system voltage collapse is the nature of the loads that are being served by utilities. Many of today’s loads are single-phase small air conditioning motors. This was not the case 35 years ago when air conditioning was not as prevalent. These small motors are prone to stall when subjected to voltage dips caused by transmission system short circuits. During hot weather, these motors comprise a high percentage of the utility load. The slow tripping of stalled motors and the relatively slow re-acceleration of more robust motors result in low system voltage after a transmission system fault is cleared [2]. The voltage dip and its effect on these motors are exacerbated if the transmission system fault is cleared via a time delay backup relay or is a mullti-phase fault. Such a slow-clearing fault resulted in the voltage collapse that caused a blackout of the city of Memphis in 1987 [3].
Fig. 1 (SEE PDF) shows an example of voltage recovery for a Phoenix area transmission system fault incident that occurred in July 1995 during hot weather.
Fig. 2 (SEE PFD) illustrates a basic power system with the remote generators supplying a significant amount of power (Ps) over a considerable distance to the remote load center. The load is comprised of resistive load and motor load. During a voltage dip resistive load current will decrease and help limit the need for local reactive support. Motor loads are essentially constant kVA devices. The lower the voltage, the more current they draw—increasing the need for local reactive (VAr) support. Power systems loads consist of both resistive loads as well as reactive motor loads. During hot weather, however, air conditioning motor loads comprise a large portion of total load, thereby making the system more susceptible to voltage collapse.
Reactive power (VArs) cannot be transmitted very far, especially under heavy load conditions, and so it must be generated close to the point of consumption. This is because the difference in voltage causes VArs to flow and voltages on a power system are only typically +/- 5% of nominal. This small voltage difference will not cause substantial VArs to flow over long distances. Real power (MW) can be transmitted over long distances through the coordinated operation of the interconnected grid whereas reactive power must be generated at, or near, the load center.
Since VArs cannot be transmitted over long distances, the sudden loss of transmission lines results in the immediate need for local reactive power to compensate for the increased losses of transporting the same power over fewer transmission lines. If that reactive support is not available at the load center, the voltage will go down. For these reasons, voltage—rather than frequency—has become the key indicator that the power system is under stress. Utilities recognize that frequency can remain normal as voltage sags to a low level prior to a complete system collapse and are implementing UVLS schemes to complement their existing underfrequency load shedding programs.
II. TYPES OF POWER SYSTEM INSTABILITIES DURING SYSTEM DISTURBANCES
A. Basics – Voltage vs. Frequency Stability
In a power system, frequency is a measure of the balance of MW generation and MW load. When MW generation and MW load are exactly in balance, the frequency is at the normal level of 60 Hz. When load exceeds generation, the frequency goes down. The rate of decline depends on the inertia of the generators within the system. Under normal conditions, there are slight changes of frequency when load suddenly increases or generation trips off-line which results in a slight (hundreds of a hertz) reduction in frequency until the aggregate generation in the system can be increased to meet the new load condition. If there is a large negative unbalance between MW load and MW generation, the frequency is reduced. UFLS schemes on the utility system are designed to restore the balance by shedding load.
Voltage is a measure of the balance of MVAr load and MVAr capability within a power system. If that reactive support is not available, the voltage goes down. Reactive power system support can only come from two sources: shunt capacitors and generators/synchronous condensers. Shunt capacitors are a double-edged sword. They do provide reactive support, but they also generate fewer VArs as the voltage dips. The VAr output of a capacitor bank is reduced by the square of the voltage. Shunt capacitor banks cannot quickly adjust the level of reactive power.
Generation at the load center can provide a dynamic source of reactive power. As the voltage goes down, the generator can quickly provide increased reactive support within its capability limits. Unlike shunt capacitors, the amount of reactive support does not drop as system voltage goes down. The amount of reactive power is controlled by the generator automatic voltage regulator (AVR). It is essential that the AVR control be properly set and the generator protection system allow the generator to contribute the maximum reactive power to support the system without exceeding the generator’s capability.
B. Voltage Instability
Fig. 3 (SEE PDF) illustrates a simplified power system with a remote generator supplying a substantial portion of the load at the load center through six transmission lines. Es is the voltage at the remote generator buses and Eg is the voltage at the load center buses. As lines between the remote generators and the load center trip the MW power flows over fewer lines resulting in increased VAr losses.
Fig. 4 (SEE PDF) illustrates how voltage decays as lines trip. This type of P-V analysis (real power relative to voltage) is an analysis tool, used by utility system planners, to determine the real power transfer capability across a transmission interface to supply local load. These curves are also called nose curves by system planning engineers. Starting from a base-case system (all lines in-service), computer-generated load flow cases are run with increasing power transfers while monitoring voltages at critical buses. When power transfers reach a high enough level, a stable voltage cannot be sustained and the system voltage collapses. On a P-V curve (as in Fig. 4), this point is called the “nose” of the curve. The shape of the nose of the curve depends on the nature of the load at the load center. High levels of motor load combined with capacitor bank support of load center voltage tend to make the voltage drop very rapidly for a small increase of power at the nose of the curve. The set of P-V curves illustrates that for baseline conditions shown in curve A, the voltage remains relatively steady (changing along the vertical axis) as local load increases. System conditions are secure and stable to the left of point A1. After a contingency occurs, such as a transmission circuit tripping, the new condition is represented by curve B, with lower voltages (relative to curve A). This is because the power being transmitted from the remote generators now follows through five, rather than six, transmission lines. The system must be operated to stay well inside the load level for the nose of curve B. If the B contingency occurs, then the next worst contingency must be considered. The system operators must increase local generation (Eg) to reduce the power being transmitted for the remote generators to reduce losses, as well as increase voltage at the load center to within the safe zone, to avoid going over the nose of curve C.
In the case of the 2003 East Coast blackout [4], three key transmission lines were lost in rapid succession due to faults caused by tree contacts. The voltage at the load center was reduced before the system operators could take effective corrective action. Effective operator action was inhibited by the lack of data from key transmission system substations due to a computer problem at the system operating center. The loss of the fourth line due to load entering a third zone relay characteristic was the final tripping that triggered the blackout.
In the case described above, voltage decay was relatively slow and there was time for system operator intervention to address the voltage decay problem. There have been cases where the voltage decayed so rapidly that operator action was not possible. These cases involve slow- clearing multi-phase transmission system faults that occur during heat storm conditions when the utility load is primarily made up of air conditioning motors. Due to the extended length of the voltage dip resulting from the slow-clearing transmission system fault, motors in the area began to stall and draw large amounts of reactive power after the fault is cleared. The rapid change in load power factor results in low system voltage as shown in Fig.1. Since there is little reserve of reactive power during peak load periods, the area voltage collapses. Such an event occurred in western Tennessee (Memphis) and resulted in an outage of 1100 MW of load. The entire event took less than 15 seconds [5].
C. Phase Angle Instability
When the voltage phase angle between remote generators and local generators (SEE PDF for Fig. 3) becomes too large, phase angle instability can occur. In many cases, this event happens in conjunction with the voltage collapse scenario described above. There are two types of phase angle instability.
1) Steady-State Instability: Steady-state instability occurs when there are too few transmission lines to transport power from the generating source to the local load center. Loss of transmission lines into the load center can result in voltage collapse as described above, but it can also result in steady-state phase angle instability.
Fig. 5 (SEE PDF) illustrates how steady-state instability occurs. The ability to transfer real (MW) power is described by the power transfer equation and is plotted graphically. From the power transfer equation in Fig. 5, it can be seen that the maximum power (Pmax) that can be transmitted is when (SEE PDF) = 90°, i.e. sin 90° = 1. When the voltage phase angle between local and remote generation increases beyond 90°, the power that can be transmitted is reduced and the system becomes unstable and usually splits apart into islands. If enough lines are tripped between the load center and the remote generation supplying the load center, the reactance (X) between these two sources increases, thereby reducing the maximum power (Pmax) which can be transferred. The power angle curve in Fig. 5 (SEE PDF) illustrates this reduction as line 1 trips the height of the power angle curve and maximum power transfer is reduced because the reactance (X) between the two systems has increased. When line 2 trips, the height of the power angle curve is reduced further to where the power being transferred cannot be maintained and the system goes unstable.
At this point, the power system is in deep trouble. During unstable conditions, the power system breaks up into islands. If there is more load than generation within an island, frequency and voltage go down. If there is more generation than load within an island, frequency and voltage generally go up. Voltage collapse and steady-state instability occur together as transmission line tripping increases the reactance between the load center and remote generation. Generally, the voltage drop at the load center is the leading indicator that the system is in trouble with low frequency occurring only after the system breaks up into islands. Analyses of major blackouts indicate that voltage is more of a leading edge indicator of power system impending collapse. Waiting for the frequency reduction may be waiting too long to shed load to save the system.
2) Transient Instability: Voltage phase angle instability can also occur due to slow-clearing transmission system faults. This type of instability is called transient instability. Transient instability occurs when a fault on the transmission system near the generating plant is not cleared rapidly enough to avoid a prolonged unbalance between mechanical and electrical output of the generator. A fault-induced transient instability has not been the cause of any major system blackout in recent years. However, generators need to be protected from damage that can result when transmission system protection is slow to operate.
Relay engineers design transmission system protection to operate faster than a generator can be driven out of synchronism, but failures of protection systems have occurred that resulted in slow-clearing transmission system faults. It is generally accepted [2] that loss-of-synchronism protection at the generator is necessary to avoid machine damage. The larger the generator, the shorter is the time to drive the machine unstable for a system fault. Fig. 6 (SEE PDF) illustrates a typical breaker-and-a-half power plant substation with a generator and a short circuit on a transmission line near the substation. If the short circuit is three-phase, very little real power (MW) will flow from the generator to the power system until the fault is cleared. The high fault current experienced during the short circuit is primarily reactive or VAr current. From the power transfer equation (Fig. 5 - SEE PDF), it can be seen that when Eg drops to almost zero, almost no real power can be transferred to the system. The generator AVR senses the reduced generator terminal voltage and increases the field current to attempt to increase the generator voltage during the fault. The AVR control goes into field-forcing mode where field current is briefly increased beyond steady-state field circuit thermal limits.
During the short circuit, the mechanical turbine power (Pm) of the generator remains unchanged. The resulting unbalance between mechanical (Pm) and electrical power (Pe) manifests itself with the generator accelerating, increasing its voltage phase angle with respect to the system phase angle as illustrated in the power angle plot in Fig. 7 (SEE PDF).
The speed with which the generator accelerates depends on its inertia. The larger the generator, the faster it will accelerate. If the transmission system fault is not cleared quickly enough, the generator phase angle will advance so that it will be driven out of synchronism with the power system.
Computer transient stability studies can be used to establish this critical switching angle and time. The equal area criteria can also be applied to estimate the critical switching angle (SEE PDF). When area A1 = A2 in Fig. 7 (SEE PDF), the generator is just at the point of losing synchronism with the power system. Note that after opening breakers 1 and 2 to clear the fault, the resulting post fault power transfer is reduced because of the increase in reactance (X) between the generator and the power system. This is due to the loss of the faulted transmission line. In the absence of detailed studies, many users establish the maximum instability angle at 120°. Because of the dynamic nature of the generator to recover during fault conditions, the 120° angle is larger than the 90° instability point for steady-state instability conditions. The time that the fault can be left on the system that corresponds to the critical switching angle is called the “critical switching time.” If the fault is left on longer than that time, the generator will lose synchronism by “slipping a pole.” For this condition, the generator must be tripped to avoid shaft torque damage. Out-of-step protection, which is also called loss-of-synchronism protection (relay function 78), is typically applied on large generators to trip the machine—thereby protecting it from shaft torque damage and avoiding a system cascading event.
D. Dynamic Instability
Dynamic instability occurs when a fast-acting generator AVR control amplifies, rather than damps, some small low frequency oscillations that can occur in a power system. This problem has been most often associated with the western region of the U.S. It can, however, occur anywhere the load is remote from the generation. While fast excitation systems are important to improve transient stability as discussed above, a fast-responding excitation system can also contribute a significant amount of negative damping. This reduces the natural damping torque of the system, causing undamped megawatt oscillations after a disturbance such as a system fault. This type of event can occur if the generator is interconnected to a weak system and loads are far from the generating plant. As discussed, the operation of today’s power grid makes this scenario much more likely in many regions of the U.S.
Small signal stability is defined as the ability of the power system to remain stable in the presence of small disturbances most often caused by remote faults. If sufficient damping torque does not exist, the result can be generator rotor angle oscillations of increasing amplitude. When these megawatt oscillations grow, the generator can eventually be driven unstable, lose synchronism and slip a pole. To address this problem, a Power System Stabilizer (PSS) is utilized in conjunction with the generator AVR to provide positive damping when megawatt oscillations occur.
The next issue of T&D will address the current status of undervoltage load shedding programs and the design criteria for a secure undervoltage load shedding program.
III. REFERENCES
[1] C. J. Mozina, Power Plant Protection and Control Strategies for Blackout Avoidance, Georgia Tech Protective Relay Conference, April 2005.
[2] B.R. Williams, W.R. Schmus, D.C. Dawson, Transmission Voltage Recovery Delayed by Stalled Air Conditioner Compressors, IEEE PES Transactions on Power Systems, Vol. 7, No.3 August 1992.
[3] North American Electric Reliability Council (NERC), 1987 System Disturbance Report, p19, July 1998.
[4] U.S. – Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations” April 5, 2004.
[5] G.C. Bullock, Cascading Voltage Collapse in West Tennessee, August 22,1987, Georgia Tech Relay Conference, May 1990.
[6] S. Imai, Undervoltage Load Shedding Improving Security as Reasonable Measure for Extreme Contingencies. IEEE PES Transactions on Power Delivery.
[7] IEEE Power System Relaying Committeee Report, Summary of System Protection and Voltage Stability, Transactions on Power Delivery, Vol. 10. No. 2, April 1995.
[8] Undervoltage Load Shedding Task Force (UVLSTF), Technical Studies Subcommittee of the WECC, Undervoltage Load Shedding Guidelines, July 1999.
About the Authors
Chuck Mozina is a consultant for Beckwith Electric. He is an active 25-year member of the IEEE Power System Relay Committee (PSRC) and is the past chairman of the Rotating Machinery Subcommittee. He is active in the IEEE IAS I&CPS, PCIC and PPIC committees, which address industrial system protection. He is a former U.S. representative to the CIGRE Study Committee 34 on System Protection and has chaired a CIGRE working group on generator protection. He also chaired the IEEE task force that produced the tutorial “The Protection of Synchronous Generators,” which won the PSRC’s 1997 Outstanding Working Group Award. Chuck is the 1993 recipient of the Power System Relay Committee’s Career Service Award and he recently received the 2002 IAS I&CPS Ralph Lee Prize Paper Award. His papers have been republished in the IAS Industrial Applications Magazine.
Chuck has a Bachelor of Science in Electrical Engineering from Purdue University and is a graduate of the eight-month GE Power System Engineering Course. He has authored a number of papers and magazine articles on protective relaying. He has over 25 years of experience as a protection engineer at Centerior Energy, a major investor-owned utility in Cleveland, Ohio where he was the manager of the system protection section. In that capacity, he was responsible for the electrical protection of the company’s generating plants as well as the transmission and distribution system that served over 1.2 million customers. For ten years, he was employed by Beckwith Electric, a manufacture of protective relays, as Application Manager for Protection Products. He is also a former instructor in the Graduate School of Electrical Engineering at Cleveland State University as well as a registered Professional Engineer in Ohio.
This article discusses why voltage as well as frequency load shedding may be necessary to prevent major system blackouts. It is the first of two articles on the important subjects of power system voltage collapse and undervoltage load shedding. The first article will discuss the causes of system voltage collapse while the second article will propose schemes to address the problem. The second article (part2) will be in the next issue of T&D. Investigations of recent blackouts [1,3,7] indicate that the root cause of almost all of these major power system disturbances is voltage collapse rather than the underfrequency conditions prevalent in the blackouts of the 1960 and –‘70s. This article explores the nature of recent power system blackouts (2003 east coast, 1996 California and others) and explains why voltage collapse is the leading edge indicator of impending power system problems. Part 2 of this article will discusses the design and security issues that need to be addressed in the design of an undervoltage load shedding (UVLS) scheme and why relying on underfrequency load shedding (UFLS) maybe “too little, too late.” Part 2 will also address the current level of UVLS on utility systems as well as current NERC (North American Electric Reliability Council) pronouncements on the subject.
II. WHY VOLTAGE COLLAPSE IS THE CAUSE OF RECENT BLACKOUTS
Power systems today are much more susceptible to voltage collapses than they were 35 years ago as we increasingly depend on generation sources that are located remotely from load centers. Generators in eastern Canada and the midwestern U.S. provide large amounts of power to east coast load centers such as New York City. Generators in Washington, Oregon and western Canada provide substantial power to southern California. Two factors promote generation that is remote from load centers:
• The economics of purchasing power from lower-cost remote sources rather than more expensive local generation.
• The public’s reluctance/refusal to permit new generating plants to be built in urban high-load areas, causing utilities/IPPs to build these plants remote from these load centers.
These two fundamental changes in operation of the U.S. power grid result in the transmission of power over long distances. This makes the power grid very dependent on the transmission system to deliver power to the load centers. It also results in increased reactive power losses when transmission lines trip.
Another key factor that results in rapid system voltage collapse is the nature of the loads that are being served by utilities. Many of today’s loads are single-phase small air conditioning motors. This was not the case 35 years ago when air conditioning was not as prevalent. These small motors are prone to stall when subjected to voltage dips caused by transmission system short circuits. During hot weather, these motors comprise a high percentage of the utility load. The slow tripping of stalled motors and the relatively slow re-acceleration of more robust motors result in low system voltage after a transmission system fault is cleared [2]. The voltage dip and its effect on these motors are exacerbated if the transmission system fault is cleared via a time delay backup relay or is a mullti-phase fault. Such a slow-clearing fault resulted in the voltage collapse that caused a blackout of the city of Memphis in 1987 [3].
Fig. 1 (SEE PDF) shows an example of voltage recovery for a Phoenix area transmission system fault incident that occurred in July 1995 during hot weather.
Fig. 2 (SEE PFD) illustrates a basic power system with the remote generators supplying a significant amount of power (Ps) over a considerable distance to the remote load center. The load is comprised of resistive load and motor load. During a voltage dip resistive load current will decrease and help limit the need for local reactive support. Motor loads are essentially constant kVA devices. The lower the voltage, the more current they draw—increasing the need for local reactive (VAr) support. Power systems loads consist of both resistive loads as well as reactive motor loads. During hot weather, however, air conditioning motor loads comprise a large portion of total load, thereby making the system more susceptible to voltage collapse.
Reactive power (VArs) cannot be transmitted very far, especially under heavy load conditions, and so it must be generated close to the point of consumption. This is because the difference in voltage causes VArs to flow and voltages on a power system are only typically +/- 5% of nominal. This small voltage difference will not cause substantial VArs to flow over long distances. Real power (MW) can be transmitted over long distances through the coordinated operation of the interconnected grid whereas reactive power must be generated at, or near, the load center.
Since VArs cannot be transmitted over long distances, the sudden loss of transmission lines results in the immediate need for local reactive power to compensate for the increased losses of transporting the same power over fewer transmission lines. If that reactive support is not available at the load center, the voltage will go down. For these reasons, voltage—rather than frequency—has become the key indicator that the power system is under stress. Utilities recognize that frequency can remain normal as voltage sags to a low level prior to a complete system collapse and are implementing UVLS schemes to complement their existing underfrequency load shedding programs.
II. TYPES OF POWER SYSTEM INSTABILITIES DURING SYSTEM DISTURBANCES
A. Basics – Voltage vs. Frequency Stability
In a power system, frequency is a measure of the balance of MW generation and MW load. When MW generation and MW load are exactly in balance, the frequency is at the normal level of 60 Hz. When load exceeds generation, the frequency goes down. The rate of decline depends on the inertia of the generators within the system. Under normal conditions, there are slight changes of frequency when load suddenly increases or generation trips off-line which results in a slight (hundreds of a hertz) reduction in frequency until the aggregate generation in the system can be increased to meet the new load condition. If there is a large negative unbalance between MW load and MW generation, the frequency is reduced. UFLS schemes on the utility system are designed to restore the balance by shedding load.
Voltage is a measure of the balance of MVAr load and MVAr capability within a power system. If that reactive support is not available, the voltage goes down. Reactive power system support can only come from two sources: shunt capacitors and generators/synchronous condensers. Shunt capacitors are a double-edged sword. They do provide reactive support, but they also generate fewer VArs as the voltage dips. The VAr output of a capacitor bank is reduced by the square of the voltage. Shunt capacitor banks cannot quickly adjust the level of reactive power.
Generation at the load center can provide a dynamic source of reactive power. As the voltage goes down, the generator can quickly provide increased reactive support within its capability limits. Unlike shunt capacitors, the amount of reactive support does not drop as system voltage goes down. The amount of reactive power is controlled by the generator automatic voltage regulator (AVR). It is essential that the AVR control be properly set and the generator protection system allow the generator to contribute the maximum reactive power to support the system without exceeding the generator’s capability.
B. Voltage Instability
Fig. 3 (SEE PDF) illustrates a simplified power system with a remote generator supplying a substantial portion of the load at the load center through six transmission lines. Es is the voltage at the remote generator buses and Eg is the voltage at the load center buses. As lines between the remote generators and the load center trip the MW power flows over fewer lines resulting in increased VAr losses.
Fig. 4 (SEE PDF) illustrates how voltage decays as lines trip. This type of P-V analysis (real power relative to voltage) is an analysis tool, used by utility system planners, to determine the real power transfer capability across a transmission interface to supply local load. These curves are also called nose curves by system planning engineers. Starting from a base-case system (all lines in-service), computer-generated load flow cases are run with increasing power transfers while monitoring voltages at critical buses. When power transfers reach a high enough level, a stable voltage cannot be sustained and the system voltage collapses. On a P-V curve (as in Fig. 4), this point is called the “nose” of the curve. The shape of the nose of the curve depends on the nature of the load at the load center. High levels of motor load combined with capacitor bank support of load center voltage tend to make the voltage drop very rapidly for a small increase of power at the nose of the curve. The set of P-V curves illustrates that for baseline conditions shown in curve A, the voltage remains relatively steady (changing along the vertical axis) as local load increases. System conditions are secure and stable to the left of point A1. After a contingency occurs, such as a transmission circuit tripping, the new condition is represented by curve B, with lower voltages (relative to curve A). This is because the power being transmitted from the remote generators now follows through five, rather than six, transmission lines. The system must be operated to stay well inside the load level for the nose of curve B. If the B contingency occurs, then the next worst contingency must be considered. The system operators must increase local generation (Eg) to reduce the power being transmitted for the remote generators to reduce losses, as well as increase voltage at the load center to within the safe zone, to avoid going over the nose of curve C.
In the case of the 2003 East Coast blackout [4], three key transmission lines were lost in rapid succession due to faults caused by tree contacts. The voltage at the load center was reduced before the system operators could take effective corrective action. Effective operator action was inhibited by the lack of data from key transmission system substations due to a computer problem at the system operating center. The loss of the fourth line due to load entering a third zone relay characteristic was the final tripping that triggered the blackout.
In the case described above, voltage decay was relatively slow and there was time for system operator intervention to address the voltage decay problem. There have been cases where the voltage decayed so rapidly that operator action was not possible. These cases involve slow- clearing multi-phase transmission system faults that occur during heat storm conditions when the utility load is primarily made up of air conditioning motors. Due to the extended length of the voltage dip resulting from the slow-clearing transmission system fault, motors in the area began to stall and draw large amounts of reactive power after the fault is cleared. The rapid change in load power factor results in low system voltage as shown in Fig.1. Since there is little reserve of reactive power during peak load periods, the area voltage collapses. Such an event occurred in western Tennessee (Memphis) and resulted in an outage of 1100 MW of load. The entire event took less than 15 seconds [5].
C. Phase Angle Instability
When the voltage phase angle between remote generators and local generators (SEE PDF for Fig. 3) becomes too large, phase angle instability can occur. In many cases, this event happens in conjunction with the voltage collapse scenario described above. There are two types of phase angle instability.
1) Steady-State Instability: Steady-state instability occurs when there are too few transmission lines to transport power from the generating source to the local load center. Loss of transmission lines into the load center can result in voltage collapse as described above, but it can also result in steady-state phase angle instability.
Fig. 5 (SEE PDF) illustrates how steady-state instability occurs. The ability to transfer real (MW) power is described by the power transfer equation and is plotted graphically. From the power transfer equation in Fig. 5, it can be seen that the maximum power (Pmax) that can be transmitted is when (SEE PDF) = 90°, i.e. sin 90° = 1. When the voltage phase angle between local and remote generation increases beyond 90°, the power that can be transmitted is reduced and the system becomes unstable and usually splits apart into islands. If enough lines are tripped between the load center and the remote generation supplying the load center, the reactance (X) between these two sources increases, thereby reducing the maximum power (Pmax) which can be transferred. The power angle curve in Fig. 5 (SEE PDF) illustrates this reduction as line 1 trips the height of the power angle curve and maximum power transfer is reduced because the reactance (X) between the two systems has increased. When line 2 trips, the height of the power angle curve is reduced further to where the power being transferred cannot be maintained and the system goes unstable.
At this point, the power system is in deep trouble. During unstable conditions, the power system breaks up into islands. If there is more load than generation within an island, frequency and voltage go down. If there is more generation than load within an island, frequency and voltage generally go up. Voltage collapse and steady-state instability occur together as transmission line tripping increases the reactance between the load center and remote generation. Generally, the voltage drop at the load center is the leading indicator that the system is in trouble with low frequency occurring only after the system breaks up into islands. Analyses of major blackouts indicate that voltage is more of a leading edge indicator of power system impending collapse. Waiting for the frequency reduction may be waiting too long to shed load to save the system.
2) Transient Instability: Voltage phase angle instability can also occur due to slow-clearing transmission system faults. This type of instability is called transient instability. Transient instability occurs when a fault on the transmission system near the generating plant is not cleared rapidly enough to avoid a prolonged unbalance between mechanical and electrical output of the generator. A fault-induced transient instability has not been the cause of any major system blackout in recent years. However, generators need to be protected from damage that can result when transmission system protection is slow to operate.
Relay engineers design transmission system protection to operate faster than a generator can be driven out of synchronism, but failures of protection systems have occurred that resulted in slow-clearing transmission system faults. It is generally accepted [2] that loss-of-synchronism protection at the generator is necessary to avoid machine damage. The larger the generator, the shorter is the time to drive the machine unstable for a system fault. Fig. 6 (SEE PDF) illustrates a typical breaker-and-a-half power plant substation with a generator and a short circuit on a transmission line near the substation. If the short circuit is three-phase, very little real power (MW) will flow from the generator to the power system until the fault is cleared. The high fault current experienced during the short circuit is primarily reactive or VAr current. From the power transfer equation (Fig. 5 - SEE PDF), it can be seen that when Eg drops to almost zero, almost no real power can be transferred to the system. The generator AVR senses the reduced generator terminal voltage and increases the field current to attempt to increase the generator voltage during the fault. The AVR control goes into field-forcing mode where field current is briefly increased beyond steady-state field circuit thermal limits.
During the short circuit, the mechanical turbine power (Pm) of the generator remains unchanged. The resulting unbalance between mechanical (Pm) and electrical power (Pe) manifests itself with the generator accelerating, increasing its voltage phase angle with respect to the system phase angle as illustrated in the power angle plot in Fig. 7 (SEE PDF).
The speed with which the generator accelerates depends on its inertia. The larger the generator, the faster it will accelerate. If the transmission system fault is not cleared quickly enough, the generator phase angle will advance so that it will be driven out of synchronism with the power system.
Computer transient stability studies can be used to establish this critical switching angle and time. The equal area criteria can also be applied to estimate the critical switching angle (SEE PDF). When area A1 = A2 in Fig. 7 (SEE PDF), the generator is just at the point of losing synchronism with the power system. Note that after opening breakers 1 and 2 to clear the fault, the resulting post fault power transfer is reduced because of the increase in reactance (X) between the generator and the power system. This is due to the loss of the faulted transmission line. In the absence of detailed studies, many users establish the maximum instability angle at 120°. Because of the dynamic nature of the generator to recover during fault conditions, the 120° angle is larger than the 90° instability point for steady-state instability conditions. The time that the fault can be left on the system that corresponds to the critical switching angle is called the “critical switching time.” If the fault is left on longer than that time, the generator will lose synchronism by “slipping a pole.” For this condition, the generator must be tripped to avoid shaft torque damage. Out-of-step protection, which is also called loss-of-synchronism protection (relay function 78), is typically applied on large generators to trip the machine—thereby protecting it from shaft torque damage and avoiding a system cascading event.
D. Dynamic Instability
Dynamic instability occurs when a fast-acting generator AVR control amplifies, rather than damps, some small low frequency oscillations that can occur in a power system. This problem has been most often associated with the western region of the U.S. It can, however, occur anywhere the load is remote from the generation. While fast excitation systems are important to improve transient stability as discussed above, a fast-responding excitation system can also contribute a significant amount of negative damping. This reduces the natural damping torque of the system, causing undamped megawatt oscillations after a disturbance such as a system fault. This type of event can occur if the generator is interconnected to a weak system and loads are far from the generating plant. As discussed, the operation of today’s power grid makes this scenario much more likely in many regions of the U.S.
Small signal stability is defined as the ability of the power system to remain stable in the presence of small disturbances most often caused by remote faults. If sufficient damping torque does not exist, the result can be generator rotor angle oscillations of increasing amplitude. When these megawatt oscillations grow, the generator can eventually be driven unstable, lose synchronism and slip a pole. To address this problem, a Power System Stabilizer (PSS) is utilized in conjunction with the generator AVR to provide positive damping when megawatt oscillations occur.
The next issue of T&D will address the current status of undervoltage load shedding programs and the design criteria for a secure undervoltage load shedding program.
III. REFERENCES
[1] C. J. Mozina, Power Plant Protection and Control Strategies for Blackout Avoidance, Georgia Tech Protective Relay Conference, April 2005.
[2] B.R. Williams, W.R. Schmus, D.C. Dawson, Transmission Voltage Recovery Delayed by Stalled Air Conditioner Compressors, IEEE PES Transactions on Power Systems, Vol. 7, No.3 August 1992.
[3] North American Electric Reliability Council (NERC), 1987 System Disturbance Report, p19, July 1998.
[4] U.S. – Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations” April 5, 2004.
[5] G.C. Bullock, Cascading Voltage Collapse in West Tennessee, August 22,1987, Georgia Tech Relay Conference, May 1990.
[6] S. Imai, Undervoltage Load Shedding Improving Security as Reasonable Measure for Extreme Contingencies. IEEE PES Transactions on Power Delivery.
[7] IEEE Power System Relaying Committeee Report, Summary of System Protection and Voltage Stability, Transactions on Power Delivery, Vol. 10. No. 2, April 1995.
[8] Undervoltage Load Shedding Task Force (UVLSTF), Technical Studies Subcommittee of the WECC, Undervoltage Load Shedding Guidelines, July 1999.
About the Authors
Chuck Mozina is a consultant for Beckwith Electric. He is an active 25-year member of the IEEE Power System Relay Committee (PSRC) and is the past chairman of the Rotating Machinery Subcommittee. He is active in the IEEE IAS I&CPS, PCIC and PPIC committees, which address industrial system protection. He is a former U.S. representative to the CIGRE Study Committee 34 on System Protection and has chaired a CIGRE working group on generator protection. He also chaired the IEEE task force that produced the tutorial “The Protection of Synchronous Generators,” which won the PSRC’s 1997 Outstanding Working Group Award. Chuck is the 1993 recipient of the Power System Relay Committee’s Career Service Award and he recently received the 2002 IAS I&CPS Ralph Lee Prize Paper Award. His papers have been republished in the IAS Industrial Applications Magazine.
Chuck has a Bachelor of Science in Electrical Engineering from Purdue University and is a graduate of the eight-month GE Power System Engineering Course. He has authored a number of papers and magazine articles on protective relaying. He has over 25 years of experience as a protection engineer at Centerior Energy, a major investor-owned utility in Cleveland, Ohio where he was the manager of the system protection section. In that capacity, he was responsible for the electrical protection of the company’s generating plants as well as the transmission and distribution system that served over 1.2 million customers. For ten years, he was employed by Beckwith Electric, a manufacture of protective relays, as Application Manager for Protection Products. He is also a former instructor in the Graduate School of Electrical Engineering at Cleveland State University as well as a registered Professional Engineer in Ohio.
