CONTROL OF ACTIVE POWER AND FREQUENCY Copyright © P. Kundur This material should not be used without the author's consent

Active Power and Frequency Control The frequency of a system is dependent on active power balance As frequency is a common factor throughout the system, a change in active power demand at one point is reflected throughout the system Because there are many generators supplying power into the system, some means must be provided to allocate change in demand to the generators speed governor on each generating unit provides primary speed control function supplementary control originating at a central control center allocates generation In an interconnected system, with two or more independently controlled areas, the generation within each area has to be controlled so as to maintain scheduled power interchange The control of generation and frequency is commonly known as load frequency control (LFC) or automatic generation control (AGC)

Primary Speed Controls Isochronous speed governor an integral controller resulting in constant speed not suitable for multimachine systems; slight differences in speed settings would cause them to fight against each other can be used only when a generator is supplying an isolated load or when only one generator in a system is required to respond to load changes Governor with Speed Droop speed regulation or droop is provided to assure proper load sharing a proportional controller with a gain of 1/R If precent regulation of the units are nearly equal, change in output of each unit will be nearly proportional to its rating the speed-load characteristic can be adjusted by changing governor settings; this is achieved in practice by operating speed-changer motor

ωr = rotor speed Y = valve/gate position Pm = mechanical power Figure 11.6 Schematic of an isochronous governor Figure 11.7 Response of generating unit with isochronous governor

Figure 11.8 Governor with steady-state feedback (a) Block diagram with steady-state feedback (b) Reduced block diagram Figure 11.9 Block diagram of a speed governor with droop

Percent Speed Regulation or Droop where ωNL = steady-state speed at no load ωFL = steady-state speed at full load ω0 = nominal or rated speed For example, a 5% droop or regulation means that a 5% frequency deviation causes 100% change in valve position or power output. Figure 11.10 Ideal steady-state characteristics of a governor with speed droop

Load Sharing by Parallel Units Figure 11.11 Load sharing by parallel units with drooping governor characteristics Figure 11.12 Response of a generating unit with a governor having speed-droop characteristics

Control of Generating Unit Power Output Relationship between speed and load can be adjusted by changing "load reference set point" accomplished by operating speed-changer motor Effect of load reference control is depicted in Figure 11.14 three characteristics representing three load reference settings shown, each with 5% droop at 60 Hz, characteristic A results in zero output; characteristic B results in 50% output; characteristic C results in 100% output Power output at a given speed can be adjusted to any desired value by controlling load reference When two or more units are operating in parallel: adjustment of droop establishes proportion of load picked up when system has sudden changes adjustment of load reference determines unit output at a given frequency

(a) Schematic diagram of governor and turbine (b) Reduced block diagram of governor Figure 11.13 Governor with load reference control Figure 11.14 Effect of speed-changer setting on governor characteristic

Composite System Regulating Characteristics System load changes with freq. With a load damping constant of D, frequency sensitive load change:  PD = D.  f When load is increased, the frequency drops due to governor droop; Due to frequency sensitive load, the net reduction in frequency is not as high. As illustrated in Figure 11.17, the composite regulating characteristic includes prime mover characteristics and load damping. An increase of system load by PL (at nominal frequency) results in a generation increase of PG due to governor action, and a load reduction of PD due to load characteristic

where The composite frequency response characteristic β is normally expressed in MW/Hz. It is also sometimes referred to as the stiffness of the system. The composite regulating characteristic of the system is equal to 1/β Figure 11.17 Composite governor and load characteristic

Supplementary Control of Isolated Systems With primary speed control, the only way a change in generation can occur is for a frequency deviation to exist. Restoration of frequency to rated value requires manipulation of the speed/load reference (speed changer motor). This is achieved through supplementary control as shown in Figure 11.22 the integral action of the control ensures zero frequency deviation and thus matches generation and load the speed/load references can be selected so that generation distribution among units minimizes operating costs Supplementary control acts more slowly than primary control. This time-scale separation important for satisfactory performance.

Figure 11.22 Addition of integral control on generating units selected for AGC

Supplementary Control of Interconnected Systems The objectives of automatic generation control are to maintain: system frequency within desired limits area interchange power at scheduled levels correct time (integrated frequency) This is accomplished by using a control signal for each area referred to as area control error (ACE), made up of: tie line flow deviation, plus frequency deviation weighted by a bias factor Figure 11.27 illustrated calculation of ACE Bias factor, B, set nearly equal to regulation characteristic (I/R + D) of the area; gives good dynamic performance A secondary function of AGC is to allocate generation economically

Figure 11.27 AGC control logic for each area

Figure 11.28 Functional diagram of a typical AGC system

Underfrequency Load Shedding Severe system disturbances can result in cascading outages and isolation of areas, causing formation of islands If an islanded area is undergenerated, it will experience a frequency decline unless sufficient spinning generation reserve is available, the frequency decline will be determined by load characteristics (Fig. 11.30) Frequency decline could lead to tripping of steam turbine generating units by protective relays this will aggravate the situation further There are two main problems associated with underfrequency operation related to thermal units: vibratory stress on long low-pressure turbine blades; operation below 58.5 Hz severely restricted (Fig. 9.40) performance of plant auxiliaries driven by induction motors; below 57 Hz plant capability may be severely reduced or units may be tripped off

Fig. 11.30 Frequency decay due to generation deficiency (L) Fig. 9.40 Steam turbine partial or full-load operating limitations during abnormal frequency, representing composite worst-case limitations of five manufacturers ©ANSI/IEEE-1987

Underfrequency Load Shedding (cont'd) To prevent extended operation of separated areas at low frequency, load shedding schemes are employed. A typical scheme: 10% load shed when frequency drops to 59.2 Hz 15% additional load shed when frequency drops to 58.8 Hz 20% additional load shed when frequency reaches 58.0 Hz A scheme based on frequency alone is generally acceptable for generation deficiency up to 25% For greater generation deficiencies, a scheme taking into account both frequency drop and rate-of-change of frequency provides increased selectivity Ontario Hydro uses such a frequency trend relay Fig. 11.31 Tripping logic for frequency trend relay