Introduction

The control of a power system involves many elements and is one of the major responsibilities of system operators. Included in the elements to be controlled are system frequency, tie-line flows, line currents, equip­ment loading, and voltage. All must be kept within limits determined to be safe in order to provide satisfactory service to the power system customers and to ensure that equipment is not damaged by overload­ing or other improper operations. In addition, tight control of frequency and tie-line flows are required to ensure that each power system will avoid causing problems for its interconnected neighbors.

There are variations in importance among the elements listed above; however, all must receive proper consideration. System fre­quency and tie-line flows are system problems and should be consid­ered as priority items by system operators. Voltages, line currents, and equipment loadings are more localized. Voltage in one area can be low, and at the same time the voltage in another area can be nor­mal or even higher than normal and can be corrected (for example) by changing taps on a transformer bank, the use of line voltage regula­tors, or switching capacitor banks into or removing them from service as may be required at a particular time.

Likewise, generating units or transformer banks and transmission lines can be lightly or heavily loaded at a particular time and can be varied in many cases by local control. For example, the throttle of a thermal unit or the gate of a hydro unit can be adjusted to change load on that machine, and the machine will respond individually to the energy input to its prime mover. It can be operated at full load while at the same time another machine may be lightly loaded.

Transmission line loadings may be affected directly by the power input to the line from connected generating units or changes in paral- lei paths that may be changed by placing other lines into or removing them from service.

Frequency is a system characteristic because it is the same over all of the system and also over all interconnected systems. Correct steady-state frequency is an indication that interconnection's genera­tion is exactly meeting the interconnection's load. If at the same time tie lines to other systems are carrying the loads that have been sched­uled for them, the overall system generation is meeting the system load and interchange commitments.

This section will discuss items involved in power system control in some detail and attempt to provide a reasonably detailed description of the factors involved and some of the features of control equipment.

Power System Control Elements

As was pointed out above, system frequency is a quantity that is common to all of the interconnected systems. Also, interconnecting tie-line loadings are normally scheduled. When both frequency and tie-line loadings are maintained on schedule, the control system is functioning properly.

As has been pointed out previously, almost all power systems make use of alternating current. Except for minor momentary excursions of frequency when a generator increases or decreases load with its attendant power-angle changes, the frequency is the same at all points in the system. Consequently, frequency is a basic quantity that can be measured and applied to the control of generating units. Furthermore, since almost all generating units are of the synchro­nous type, they are locked together at synchronous electrical speed.

When system frequency increases or decreases, the connected gener­ating units will increase or decrease in speed by the same amount electrically. This means that if frequency increases from 60 to 60.1 Hz, all interconnected generators will increase in speed to operate at 60.1 Hz. Of course, the physical speed change will be determined by the number of poles in the machine according to the following formula:

. 120f r/min = —■— NP

where r/min = revolutions per minute f= frequency, Hz NP = number of poles

For example, at 60 Hz a two-pole machine would operate at (120 X 60)/2 = 3600 r/min, and at 60.1 Hz it would operate at (120 X 60.1)/2 = 3606 r/min.

This would be typical of a steam-turbine-driven alternator. Hydro units operate at much slower speeds. For example, an 18-pole machine at 60 Hz would operate at 400 r/min, and at 60.1 Hz the speed would increase to (120 X 60.1)/18 = 400.67 r/min. It should be emphasized that although the two machines in the above examples operate at radi­cally different physical speeds, the electrical speeds are identical.

Frequency Control

Because system frequency is common to all parts of the system and is easily measured, it was the first quantity applied to system control. The governors on generating units make use of rotating flyballs. These actuate a hydraulic system to open or close the throttle valves of the prime movers of the machines. This action increases or decreases ener­gy input (fuel in a thermal plant or water in a hydro plant) to maintain speed (frequency) at the desired value. More recently electronic gover­nors have been applied that sense frequency and actuate hydraulic devices to control gate or throttle position without the use of flyballs.

In order to operate machines in parallel with stability, it is neces­sary that the governors have drooping characteristics. That is, as load increases, speed decreases. Governor droops are expressed in percent­age of speed change from no load to full load. For example, with a 5 percent droop (a common setting), the no-load speed would be 105 percent of the full-load speed. This is shown graphically in Fig. 5-1.

In operation the speed motor on the governor control system will move the speed controls up or down to correspond to the desired load settings as indicated by the curves of Fig. 5-1, curve A for 100 percent and curve Вfor 50 percent load levels.

115p 110-

o 50 ₁₀₀

% Load (MW|

Figure 5-1Governor speed load characteristic. On curve Athe governor speed motor is adjusted so that at no-load and separated the machine will run at 105 percent speed and at full load at 100 percent (synchro­nous on system) speed. CurveВshows the condition for synchronous speed at 50 percent load. In this case, the no-load, separated speed would be 102.5 percent.

If governors had zero droop, or if they were adjusted so that the speed characteristic increased with load, operation would be unstable. This situation would be similar to overcompounding of dc generators operating in parallel. If one machine has a lower governor droop set­ting than the others, when two or more generating units are operated in parallel on an ac system, on a frequency drop the machine with the lower droop characteristic will pick up proportionally more load.

Since generators operated in parallel cannot be separated to adjust the governor, each time a load change is made, the governor droop characteristic is adjusted during a series of tests and is then left fixed. Because governors are a combination of hydraulic and mechanical components, an appreciable change in system speed is required before the governor can sense it and take corrective action. Consequently the correction is delayed by a discrete time interval from the time the speed (frequency) change occurred. As a result, machines or systems controlled only by governors have a "dead band" of the order of ± 0.02 cycle. In other words, on a 60-Hz system with governor control only, normal speed will vary between approxi­mately 59.98 and 60.02 Hz.

During system disturbances due to line troubles or load changes, frequency deviations in systems using only governor action will vary depending on the size of the system and the magnitude of the load change or generation change.

For many years governor speed control was the only available means of controlling system frequency. When a load change occurs on a unit operating alone or on a system with governor control only, the speed will stabilize at that indicated for the new load condition. For example, if the unit with the speed load characteristic shown in Fig. 5-1 was operating at 60 Hz at 100 percent load, and load was decreased to 50 percent, it would operate at excess speed, as indicated on curve A,until the governor speed control was readjusted so that it could operate on curve B.

Automatic Generation Control

Automatic generation control (AGC) systems have many advantages over governor speed control and have generally replaced simple gover­nor control. The AGC systems transmit control pulses to the governor motor operators of the machines that are under control and operate to open or close the control valves to increase or decrease the input to the prime movers to restore and maintain correct frequency, as required.

Prior to the development of AGC systems, speed control was accom­plished with electromechanical governors only. It was difficult to apportion load changes between generators, and frequently one plant was assigned to do the governing for a system. This put an excessive burden on the governors of the plant responsible for governing, because system load changes could cause the governing plant to make wide excursions of load, and it was necessary for the system operator to make frequent requests to other plants to manually increase or decrease load to keep the governing plant within governing range.

AGC systems are capable of assigning the governing burden (con­trolling response) economically among many units at various plants, so that each plant and/or unit takes only an assigned share of the con­trolling response. Also an AGC system can maintain speed to much closer limits than was possible with electromechanical governors. The AGC control unit sends signals to the generating units under its con­trol to raise or lower load as required to correct frequency, tie-line loadings, and time error. The signals are developed by the unit con­troller so that each unit under control will assume its share of the reg­ulating burden, depending on the size and capability of the machine, and the effects of transmission line loadings, and economic factors.

AGC systems can be expanded, if provided with sufficient computer capability, to include other inputs, permitting the determination of efficiency ratings of individual units, hydrothermal coordination, emissions from thermal plant stacks, transmission losses (penalty factors), inadvertent interchanges with interconnected systems, etc. When so equipped, an AGC system can assist in providing efficient interconnected operations, as well as being a tool for minimizing cost for the production of energy supplying the system load.