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1106 Transactions on Power Systems. Vol. 7, No. 3, August 1992

A report of the AGC Task Force of the IEEE/PES/PSE/System Control Subcommittee

UNDERSTANDING AUTOMATIC GENERATION CONTROL

Nasser Jaleeli 1 (TF Chairman) Louis S. VanSlyck 2

Donald N. Ewart 3 Power Technologies, Inc. Schenectadv, New York American Electric Power Service Corporation

Lester H. Fink 4 Arthur G. Hoffmann 2

ECC, Inc. Columbus, Ohio

1 Member, IEEE z Senior Member, IEEE

Abstruct - This paper describes what automatic generation control (AGC) might be expected to do, and what may not be possible or expedient for it to do. The purposes and objectives of AGC are limited by physical elements involved in the pro- cess and, hence, the relevant characteristics of these elements are described. For reasons given in this paper, it is desired that AGC act slowly and deliberately over tens of seconds or a few minutes. From a perspective of utility operations, there is no particular economic or control purpose served by speeding up the AGC action.

By this Task Force paper, the System Control Subcom- mittee is providing a resource to the power engineering com- munity to help guide research into topics related to AGC.

K e y Words- Area Control Error, Automatic Generntion Control, Economic Dispatch, Frequency Response, Govemor Action, Inadvertent Energy, Load Frequency Control, Power System Control, Power System Operation, Speed Droop.

INTRODUCTION Present schemes of automatic generation control (ACC),

have evolved over the past six decades and are in use on inter- connected systems as large as one-fourth the North American continent. Continued enhancement of these schemes is expected via new application9 and yet to be developed logic algorithms and prwcss con~rol lechnology. However, certain concepts, objectives, and simulation models that too often have been assumed for research effofis in AGC are not applica- ble for present day power systems. This paper (prepared under the auspices of the System Control Subcommittee) attempts to describe basics that are applicable to today's power systenis and AGC in order to assist interested research parties in direct- ing their work at nieanirigful objectives.

The way loads and unit govemors respond to various upsets of electric power mismatch in the system is presented. This is followed by a brief description of types of generating units, arid constraints on their range and rate of response to AGC signals. Within these constraints, the objectives of AGC in isolated, and then in multi-conlrol areas are presented. For the latter, the philosophy of tie-line bias control is reviewed. Additional fundamental considerations affecting AGC, together wilh some concluding rematks, m presented at the end

91 WM 229-5 PWRS by the IEEE Power System Engineering Committee of the IEEE Power Engineering Society for presentation at the IEEE/PES 1991 Winter Meeting, New York, New York, February 3-7, 1991. Manuscript submitted September 4, 1990; made available for printing January 3, 1991.

A paper recommended and approved

Fairfax, Virginia 4 Life Fellow, IEEE 3 Fellow. IEEE

SYSTEM NATURAL PERFORMANCE Power system loads and losses are sensitive to frequency.

Data captured right after frequency disturbances indicate that their aggregate initial change is in the same direction as the frequency change.

once a generating unit is tripped or a block of load is added to the system, the power mismatch is initially compen- sated by an extraction of kinetic energy from system inertial storage which causes a declining system frequency. As the fre- quency decreases, the power taken by loads decreases. Equilibrium for large systems is often obtained when the fre- quency sensitive reduction of loads bal'wces the output power of the tripped unit or that delivered to the added block of load at the resulting (new) frequency. If this effect halts the kquency decline it usually does so in less than 2 seconds.

If the mismatch is large enough to cause the frequency to deviate beyond the govemor deadbarid of generating units, thcir output will be increased by govemor action. For such mis- matches, an equilibrium is obtained when the reduction in the power taken by loads plus the increased geeneration due to gov- emor action compenqates for the mismatch. Such equilibrium is normally obtained within a dozen seconds after the tripping of a unit or connection of the additional load.[ I ]

Many govemor deadbands are beyond 35 mHz. This amount of frequency deviation requires the upset of more than 1000 M W in the eastem interconnection of the US. Thus, in this interconnection many govemors may be called upon as unit speed stabilizers (21 only a few times per month.

Typical speed droops for active govemors are in the range of about 5%. (Govemor droop is the percent change in fre- quency which would cause the unit's generation to change by Io()% of its capability.) This level of sensitivity to frequency allows many isolated systems, which are not necessarily small in capacity, to perform satisfactorily without AGC. Thus, at the expense of some tiequency deviation, generation adjust- nient by govemors provides aniple opportunity lor a follow up manual control of units. The objectives of the follow up con- trol, especially under normal changes of load, are to retum the frequency to the schedule, to minimize productioti cost, and to operate the system at an adequate level of security.

The purpose of AGC is to replace portions of the above mentioned manual control. As it automatically responds to normal load changes, AGC reduces the response time to a minute or two, more or less. Mainly due to delays associated with physically limited response rates of energy coiivcrsion, further reductioti in the respoiisc tliiie ol AGC i s ucillier pos- sible nor desired.

NeiIher Iiw follow up nianrml cnntrol nor' AGC. i.\ irhle or' expected to pluy urry role in linrititrrg tire ntugrri~rrtle (d rlw

0885-8950/92$03.00 Q 1992 IEEE

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first frequency swing which occurs within seconds ajier the loss of a block of generation or loud in the system. In fact, in the U.S., the procedure in most control areas requires AGC to be suspended when the frequency deviates 200 mHz or more. For conditions where change of generation due to govemor action and change of load due to its sensitivity to frequency are not enough to intercept the run-away frequency, over- and under-frequency relays are among the last resorts for shedding loads to prevent system collapse, or tripping generating units to prevent their damage.

GENERATING UNIT CHARACTERISTICS AGC realizes generation changes in the system by

sending signals to units under its control. The design and performance of an AGC system is very dependent on how units respond to such signals.[ 3,4,5] Unit response characteristics vary widely and are dependent on many factors such as:

Type of generating unit; for example fossil-fired, combustion tuhine, combined cycle, nuclear, or hydro.

Type of he1 being used; i.e. coal, oil, gas, or uranium. Generic plant type; i.e. drum-type or once-through boiler,

boiling- or pressurized-water nuclear steam supply, high- or low-head hydro plant.

Type of plant control; i.e. boiler-follow, turbine-follow, or coordinated. Also, whether the unit is operated in a sliding pressure or fixed presswe mode.

Operating point; frequently the ability of a unit to respond is different at one load point than at another. E.g., operation near a valve point will be different than operation between valve points. Also, a generating unit operating with valves wide open cannot respond to a signal to generate more power.

Operator actions; unit operators may take a unit off AGC control for various reasons. Problems with auxiliaries such as boiler feed pumps, and coal mius are two examples.

A brief description of the characteristics of several types of generating units as they affect the response to AGC signals Ls given below.[6]

- Fossil-Fired Stem-Turbine Units Many existing drum-type units are still controlled in a

boiler-following or turbine-following mode. Controlling the steam flow at the turbine inlet allows fast initial unit power response by altering the rate of boiler energy conversion. Boiler-following controllers tend to he fairly responsive to AGC signals, on the order of 3% per minute for a 30% excur- sion, particularly if fueled by oil or gaq. The AC‘ signal usu- ally drives the speed-load setpoint adjuster on the speed-gover- nor control which, in turn, cauSes turbine valve movement. The boiler controls sense the changes in steam pressure to adjust flows of air, fuel, etc.

Once-through steam generators are frequently supplied with coordinated control systems, meaning that the AGC sig- nal is processed by a master controller that “coordinates” the fuel, air, temperature, and turbine valve controls so as to limit undesirable stresses on the plant components. Many of the

Nuclear Units Nearly all nuclear plants have either boiling-water (ESWR)

or pressurized-water (PWR) steam generators.[8,9] Most are not currently controlled by AGC, but there are exceptions. BWR units operated under AGC, typically can respond at 3% per minute for 10 minutes or so within their regulating range. To move outside the range requires malcing changes manually in the control-rod pattem, a more lengthy process.

Power control in P W R units is accomplished by adjusting control rods in the reactor core, and for larger excumions at slower rates, by changing the concentration of boric acid in the primary loop. These units are capable of making 20% excursions at rates of nearly 3% per minute.

fi Combustion turbines, particularly simple-cycle gas tur-

bines, are capable of the fa..test response of m y units on util- ity systems, but since typically used as peaking units they are seldom equipped for operation under AGC. Combined-cycle units, where the gas-turbine exhaust gas is used to generate steam to power a steam turbine, are more likely to be equipped for AGC control if operated by a utility. The response of a combined-cycle plant is not quite as rapid as a simple gas tur- bine. Combined-cycle units operated by independent power producers and cogenerators may constitute a significant fraction of generation in some areas, but are seldom operated under AGC.

Hydro Units Low-head hydro units, such as used in run-of-river plants,

have excellent response capabilities. Many can be cycled over their entire operating range in under a minute. High-head units must have their response rates somewhat curtailed to prevent water-hammer damage in long penstocks. Even with such a limitation, the units can respond with very large excursions, if desired. However, hydro plant loading maneuvers may require careful coordination with other hydro units upstream or down- stream on the same river system.[lO]

AGC OBJ ECTIVES The objectives traditionally defined for AGC appear to be

vague and incomplete. However, any attempt in this paper to precisely detine them may introduce a constraint on future opportunities. Hence, we only compare attributes of AGC strategies from different aspects. For each attribute, the pre- ferred strategy is indicated. Yet, we leave the selection (or weighting) of attribute importance and the exact determination of m overall score for individual consideration.

For the comparison of the strategies, a power system hav- ing some units under AGC and others manually controlled, is considered. Various attributes are to be assessed over a selected time window (duration of their comparison.) This comparison is lint made when the system operates as a single (isolated) control area. The concepts developed for the single control area caye are then extended to that of an interconnection comprising several control areas.

newer drum-type steam generators are &“oiled this way too. Depending upon how these controls are designed and adjusled, unit response cm v i l q widely.l71 A wcll-adjustcd unit of this type be o f Iliaking a 20% in 10 minutes.

Shide (isolated) Control Area ‘The following nspects for which the strategies are coni-

pared ant by no niems intended to be coinplcte nor to k appli- cable for all systems. We also acknowledge that niucli is lelt

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for improving the definition of each aspect and the qualifying words used in them. For example, how should the acceptabil- ity of a frequency trend be defined, or measured? This issue will be addressed again later.

Of AGC strategies, the one which yields a geaeration trend acceptably matching the trend required to serve the varying load at scheduled frequency over tbe selected t h e window gets a high score, The more acceptable the generation trend, the more acceptable becomes the kquency head, and vice versa. Therefore, a main input to AGC for a single control area is the system frequency.

The strategy which accumulates lower fuel cost over the time window is preferred. Such an AGC may also be expected to recognize undesirable unit generation ranges (including steam valve points ot hydro rough spots) and avoid un- necessary sustained operation in such ranges.

The strategy should maintain a sufficient level of reserved control range and a sufficient level of control rate. System load can potentially have more sudden sustained changes than those which occurred in the selected time window. Prior to such changes the operating point of each unit would be preferred to be in the middle of its controllable range. Also at any time, the number of speed-govemor type units in a wound-up state should be minimized

The strategy should operate the system with a better security margin as specified by the system’s management. The strategy which accumulates lower cost associated With

the wear and tear of regulation for all units combined is pre- ferred. This strategy, therefore, is expected to avoid unneces- sary rapid maneuvering of unit generation (or the chasing of high frequency components of demand change.) The strategy which requires less effort fiom system operators

gets a higher score. The strategy which provides timely recommendations for

changing tbe output of units that are manually controlled gets a higher score.

The strategy should provide timely recommendations for changing the automatic regulation band (whether set at the plant ot at the control center) for units controUed by AGC.

The strategy should provide meaningful alarms, e.g. for units not responding to either system operators’ requests or to the AGC signals. This may include displays in the control center and/or at the plant for prior deviation from desired generation level and anticipated trends of future desired generation. This could also include the automatic observation of security constraints on the generation level of units.

The strategy which requires less computing power and other hardware may deserve a higher score. This would recognize that “simpler” is easier to understand and maintain, and is usually more reliable.

We now address the issue of frequency trend acceptability. Under normal variation of load, the frequency must be main- tained sufficiently within a band where under- or over- frequency relays could not be actuated by the next credible contingency, e.g., a unit trip, or loss of a block of load. In most systems, AGC can accomplish this objective even if it yields a generation trend which laps by several minutes that wliich would colrtirlually serve the load at the scheduled fquency .

Oacr the ficquency goes out of the above band for any reason, eitllcr suddenly or slowly, the role of AGC UI its quick

restoration becomes very limited. Almost all units can provide a higber rate and range of control from the unit control room than via AGC signals from a control center. Following a large frequency deviation, the mode of operation of a number of units is normally changed from automatic to manual and unit operators are usually asked to adjust the generation manually. Therefore, the time required for restoration of frequency to the schedule mainly depends on how quickly manual changes can berealized.

While frequency is maintained within the acceptable range, electric clocks may still gain or lose time. To maintain accurate time, the scheduled frequency is offset from nonlinal whenever the time error exceeds a threshold.

When the frequency is lower than nominal, the system loses a small component of sewed load. When it is higher, the system imposes a small additional component onto the con- nected load.[ll] As long as the time emr is forced to cross zero frequently, the difference between tbese lost and gained load components remaios negligible. (Depending on frequency amplitude excursion, “fkquently” may mean merely “several times per week.”)

Multi-Area Control A ”multi-area interconnection” is comprised of regions, or

“areas”, that afv interconnected by tie-lines. Tie-lines have the benefit of providing inter-area support for abnormal conditions as well as transmission paths for contractual energy exchanges between the ateas. The area boundaries are determined by tie- line metering for AGC and contractual billing purposes. Both power and energy flows are metered. Energy metering is usu- ally on an hourly basis and the data values used for accounting purposes must be identical (after auditing) for each corporate party sharing the tie-line. Accounting, and auditing, are described in reference 12.

The mnd of fiquency measured in any area is an indicator of the trend of mismatch power in the interconnection and not in the area alone. Any area, of a multi-area system, that attempts to adjust its generation to restore the frequency to schedule, requires a block of controllable generation large enough to respond to the mismatch power in the interconnec- tion. Furthermore, the interconnection requires tie-lines which can carry such amounts of power between this area and the Others .

In an interconnection where AGC in more than one area is driven solely by a frequency signal, there will be large power oscillations between controlling areas unless regulating actions taken by all areas can be realized simultaneodsly. Further, the operation of such an interconnection would face a more severe problem if the areas attempting to control frequency had measurement error. An area that measured the frequency at a value higher than others would reduce its generation, while others raised, both attempting lo force frequency (as they each measured it) to the scheduled value.

On the surface, an alternative to frequency based control may seem to be that each area generate enough power to serve its intemal loads and losses, plus the total scheduled power interchange ‘Ts” with other areas. However, if every area oper- ated wilh this objective, then for reiso~ls described below U t e interconnectiorl tiright not be able to operite salisfactorily.

‘ h e tliflerence between an area’s pelwrition and the power takeo internally by loads and losses is the suln of power llows

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“Ta” on all tie-lines between this area and others. The scheme whereby each area controls its Ta to match its Ts is called con- stant net interchange (or flat tie-line) control. Consider a sys- tem comprising two areas, 1 and 2, and suppose area 1 mea- sures its interchange several M W below the actual, and area 2 measures its own correctly. Then both areas will continuously raise their generation and no equilibrium can ever be reached. Altemately, assume area 1 uses an erroneous interchange schedule whose magnitude is higher than that used by area 2 for its purchase. The same instability occurs.

Even in the absence of the above errors, this method of control is unable to provide satisfactory operation because it mu l l s in severely depressed frequency when either area is not able to produce its share of generation. As area 2 will attempt to maintain its interchange at the schedule, the system may collapse if a large unit is tripped in area 1.

Just as it was found impossible, for reasons that are now obvious, for generators to operate stably in parallel without providing a suitable droop to their govemor characteristics, so it was found impossible for systems to operate stably in p a d - le1 under either constant frequency or constant net interchange control. Ther@ore, a quick return of either frequency or inter- change to the schedule must not be used as a basis for advocat- ing an AGC algorithm.

Tie-Line Bias Control Multi-area control philosophy 1131 constitutes assistance

from area 2 to area 1 beyond the scheduled interchange when area 1 is not, for whatever reasons, satisfying its obligations. All areas of an interconnected system respond relatively quickly, under load and govemor action, to changes in demand as signalled by changes in frequency. The concept of tie-line bias control, developed in the mid Ihirtias, permits areas, over the longer run, to readjust generation (to follow changes in their intemal load) without compromising the area’s share! of natural response for frequency support.

To understand the basis of the above mentioned control philosophy, we examine a power system in two cases, first operated as one control area, and then as two control areas. The system is assumed to be operating at scheduled frequency, Fs, when it loses a block of load or generation.

However operated, system natural response (aka. regula- tion, or primary response) based on design criteria, is expected (for credible contingencies) to stabilize the system at a new frequency, Fa. With Fs and Fa in Hz, this response is conven- tionally expressed as 10 J3 (Fa - Fs). The coefficient, J3, is neg- ative and traditionally is given in M w / O . 1 Hz. It represents the combination of both load and govemor sensitivity 1141 to frequency. As system frequency is retumed to the schedule, pri- mary response diminishes.

When the system operates as one control area, it benefits from primary response of the complete system until central (supplementary or secondary) control actions can fully com- pensate for the power upset. Assume the same system operates as two control areas and the location of the power upset is in area 1. It is desired, of course, to obtain a smooth restoration of frequency in this case roo. Therefore, area 2 should, as before, assist area I with iis natural response - a power coni- parable to its share or IO J3 (Fa - Fs) - aid ihis natural rcsponse should riot he unduly compromised by AGC action. Thus, the AGC iri area 2 should yield a generation tretid wliidi

has an “acceptable match” with the sum of the area’s own load and losses, Ts, and the area portion of 10 p (Fa - Fs).

The system natural response coefficient, J3, is not a con- stant, neither is it accurately obtainable nor predictable. It depends on the current status and governor response character- istics of the presently on-line units [15] and the sensitivity of loads. Depending on the magnitude of upset from the prevail- ing pre-disturbance frequency, the variable number of gover- nors coming out of deadband causes J3 to be highly sensitive to upset size.[ 1,121 Moreover, the observation or measurement of natural response can be obscured by normal system activities. E.g., generating units may be actively responding to prior control signals and, of course, individual system loads are con- stantly and arbitrarily changing.

The North American Electric Reliability Council (NERC) Guidelines specify using 10 B (Fa - Fs) to represent the area portion of the frequency response term in area’s AGC process. The Guidelines allow the use of a constant for B which i to be estimated annually based on the average of apparent area p values as observed for disturbances that occurred during on- peak hours. (The sum of all area J3 values is system J3.) Guidelines altemately allow using a variable B so as to repre- sent an estimate of the area’s p variation. However, they fur- ther require that the monthly average of IBI should not be numerically smaller than 1% of the control area’s estiniated yearly native peak load demand (IBI is the magnitude of B.)

Hevery area used an underestimated value for IBI, opera- tion of the interconnection would tend to show characteristics similar to those associated with constant net interchange con- trol. On the other hand, indiscriminate use of over-estimated values for IBI, would tend to yield inter-area generation oscilla- tions.

Using B as proxy for an area’s J3 restates one of the major objectives of AGC - it is desired that ACK in each control area provide a generation trend which has an acceptable matdi witli that representing the sum of the area’s own load and losses, 10 B (Fa - Fs), and Ts. Generation in this area equals the sum of load and losses, and Ta. Therefore, the difference, called the area control e m r (ACE), between the trend of gener- ation and that with which an acceptable match is desired, is:

A C E = ( T a - T s ) - l O B ( F a - F s )

Even if it were possible, it would not be desirable to maintain ACE at zero because this would require unnecessarily rapid maneuvering of units. The definition of a desirable gen- eration trend remains an open issue.

As long as each area manages to keep ACE and its (several minute) average bounded, the interconnection will continue to operate successfully despite reasonable errors in metering of frequency and tie-line tlows, and/or the use of imprecise fmquency and power interchange schedules. Meeting these conditions, each area will be supported by other mas when it faces a large change of load, or the tripping of a unit, that it otherwise could not alone handle satisfactorily. Furthermore, huge economic savings are realii~d by utility interconnections versus the altemative of each operating a$ an isolated entily.

Power nihmatch in the intcrconncction causes frequency to change, and sustained frequency dcviation lroni Uie noniind value causes t h e error. Siniilarly, sustained deviation lroni

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tbe interchange power schedule results in inadvertent energy exchange between area$. Even if an area were able to maintain its ACE at zero all the time, sustained frequency deviation from the scheduled value (whether offset from nominal or not) would cause inadvertent accumulation. However, such inadver- tent exchange benefits those areas requiring support and they accept respomibility for its subsequent retum. lo multi-area operation, over the very long term, the energy generated in each area must he made to match the area's native load and losses, and the area's interchange energy schedule. There is no equivalent energy balance consmint for isolated operation because Ta and Ts are each identically zero.

"bere are procedures by which time error is corrected and inadvertent energy is paid back. Methods m described in =fer- ences 12 and 16.

To define the objectives of AGC when the area is a part of an interconnection we again refer to the comparison of AGC strategies. However, for a multi-area interconnection the first attribute listed for a single controt area should be replaced by:

Of AGC strategies, the one that yields a more acceptable ACE trend gets a higher score.

All other aspects for which the AGC strategies were com- pared for a single control area are also applicable for multi-area operation. In addition, the following ataibute is included for multi-area systems. The strategy which maintains a mote acceptable range of

inadvertent energy and repays its accumulation in a timely manner is preferred. Strategies that exploit unilateral inadver- tent corrections, which simultaneously reduce time error, may be consided to deserve a higher score.[12,161

Timely and accurate calibration of power metering on each tie-line versus energy metering over recent hours can con- tribute to the veracity of the AGC process.

T N It is typical for only a subset of units in any area to be

equipped with remote control hardware. For a variety of rea- sons, a fraction of those equipped m not operated under AGC at any given time. Of those that are, some do not always re- spond to control signals, e.g. because of backlash and wind-up in speed-govemor motom. Thus, the rate and range of output M W change that AGC can realiie is limited.

With this limitation, and notwithstanding the details of AGC algorithm designs, control areas are Undbk to compen- sate quickly for an abrupt large power mismatch caused, for example, by a unit trip. NERC Guidelines define disturbance conditions for such events. The guidelines require that ACE in the disturbed area should be returned to zero within ten minutes following the start of the disturbance. To satisfy this requirement for large power upsets, system operators typically need to manually intervene, to alter interchange schedules, to bring some hydro and combustion units on line, and/or to manually q u e s t generation cbanges Erom some units whether or not they are on AGC. In non-disturbed areas, depending on the match between B and area p, AGC may be quite in- sensitive to the power upsel - thereby avoiding undo comproniise of naturdl wsponse.

Disturbance conditions it] an area are not frequent evcnts. They typically occur only a few tinics pcr nioritli. I n contrast with its limited role under disturbancc cordictilions, AGC plays

a dominate role in providing an acceptable generation trend under nonnal conditions.

Such a tend should have an acceptable match with that of the area demand [i.e. the sum of the area's own load and losses, 10 B (Fa - Fs), and Ts.] Area demand unpredictably varies around an average mnd. With the existing limits on the rate and range of generation change and the fact that steam units take a few to several dozen seconds to fully respond, maneuvering generation to match fast varying components of area demand is impossible. Furthermore, maneuvering generation based on these components will not necessarily produce a moR desirable ACE brend[l7]

Even if generation control rate and range were not as lim- ited as they are and units could respond much faster, it may still be undesirable to maneuver generation attempting to match fast varying components of the m a demand. Such oper- ation would increase equipment wear and tear.

For normal operation, NERC guidelines encourage each area to control so that ACE crosses zero at least every ten minutes and has a ten-minute average below an area specific value. Lack of generation reaction to the components of area demand whose periods are smaller than several dozen seconds should not reduce the level of compliance with these guide- lineS.

Almost all systems filter tie-line power flow measure- ments to compute ACE, and then process ACE to arrive at an AGC decision in each cycle. Any form of signal processing is in fact a filtering action: the sampling process in itself is a fil- ter; therefore filtering is inescapable. Filtering of any type introduces delays and distortion, and design should attempt to minimize them. Moreover, unless digital sampling is preceded by coordinated analog filtering, disruptive aliasing will be introduced into the process.

Typical filters on tie-line metering introduce delays of up to a few seconds. ACE processing logic introduces further delays. Given these delays and the response characteristics of units, most systems use 2 or 4 seconds for the data acquisition *and decision cycles of the AGC system. Reduction of this cycle to a fraction of a second would substantially increaqe the percent of overall CPU time required for AGC with little or no improvement in system perfomaoce; in the presence of alias- ing, performance could even be degmded.

SIMULATIONMODELS F 0 R A G C S T U DI ES In various literature one can find analyses related to elec-

tro-mechanical transients and intermachine oscillations which follow power balance upsets. Where these analyses utilize such variables as rate of change of power angles, or local frequency, etc., the phenomena being studied are really not the slow and deliberate process of AGC, but the dynamics themselves. The requirement of anti-aliasing filters for the typical time scales of AGC measurements prevents the observation of such dynamics. The studied systems may come to some final off-nominal frequency, or other imbalance from scheduled conditions which AGC is then responsible to correct on its own time scale of action.

As U cpntrol control process AGC is n P i t k p r able nor t n n be e.yper*ted to pluy any role in dcmipinR elecuw-mPclruiiic,~I transients iricluding intermachine o.wi1kution.v. 111 systems pos-

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sessing coordinated control steam units, it takes a few to sev- eral dozen seconds for AGC actions to be reali74. Therefore, system models developed for AGC studies need not repment phenomena having time coostants shorter than a few seconds.

AGC studies, the momentary difference between the frequency of different areas can be ignored. For all AGC pur- poses, the frequency used for one area to compute ACE should be the same as used in other areas so long as they remain interconnected. In AGC practice, rapidly varying components of frequency are almost unobservable due to filters involved in the process.

OVFRVIFW AND CONCLUS IONS A major factor that must be comidered in the design of a

control system is the nature of the utility plant to be con- tmlled. If it already exists, or its design has been completed, the control system must accommodate the characteristics of that design. Even if the control system is designed as part of the overall design, so that insofar as possible the plant and the Control system designs are coordinated with each other, physi- cal and thermodynamic limits am non-negotiable, and often constrain control objectives.

In the case of automatic generation control of electric power systems, the utility plant, i.e. those individual com- pany systems, pools or interconnections that comprise subcontinental or continental systems, already exists and represents a massive investment that can only be changed slowly over time in an evolutionary manner. Accordingly, any proposed contribution to improved control of such systems must accommodate existing physical realities if they am to be meaningful.

Most important of these physical realities are Newton’s laws of motion, and the effects of inertia that are entailed thereby. These effects are governing, not only at the level of the entire system, with its massive inertial effects, but ako at the level of the individual boiler-turbine-generator units. An inescapable consequence is the impossibility of matching load and generation other than in a time-average manner. The degree of mirmatch that must be accepted is dictated by (i) the opera- tional constraints of the utility plant, (ii) the limits of control effom that are available and accepted, and (iii) the signal/noise ratio in the instantaneous estimate of generation demand.

Control realization is limited by how much stored energy is available in generating units, and how rapidly its conversion rate can be changed. The signal/noise ratio is limited by ele- ments of the component signals that do not represent true changes in load, by instrumentation noise and error (possibly including heavy aliasing if not purposely avoided by filtering), by non-synchronicity of signals, etc. Additional, and some- times purposeful, constraints are imposed by deadbands in mechanical linkages, by tnmport delays, by catch-up speeds of control motors, and other inescapable nonlinearities.

In view of the considerations described in this paper, attempts to reduce the root-mean-square magnitude of a sys- tem’s ACE below some threshold, or to achieve any reduction in a portion of its spectrum beyond some frequency, are inevitably futile and counterproductive.

A. M. DiCaprio, A. A. Fouad, R. K. Green, Jr, K. Hill, R. K. McCrea, T. L. Overly, E. H. Preston, III, J. E. Price, R. P. Schulte, G. B. Sheble, R. R. Shoults, L. H. Siddiqi, J. Singh, J. E. Troutman, S. Vemd, ads . Virmani.

REFERENCES [l] D. N. Ewart, “Automatic Generation Control -

Performance Under Normal Conditions,” Systems Engineering for Power: Status and Prospects, U.S. Government Document COW-750867.1975, pp. 1-14.

[2] C. Concordia, “Power System Objectives’ Side Effects: Good and Rad,” IEEE Power Engineering Review, September 1990, pp. 12-13.

[3] R. D. Dunlop, and D. N. Ewm, “System Requirements for Dynamic Performance and Response of Generating Units,” IEEE PAS, May/June 1975, pp 838-849.

[4] C. Concordia, F. P. de Mello, L. K. Kirchmayer, and R. P. Schulz, “Effect of Prime-Mover Response and Governing Characteristics on System Dynamic Performance,” Pmxedings of American Power Conference, 1966, pp 1074-1085.

[5] M. R. Stambach, and D. N. Ewart, “Dynamics of Interconnected Power Systems: A Tutorial for System Dispatchers ami Plant Operators,” Electric Power Research In.titute, Report EL6360-L, Section 9, May 1989.

[6] E E E WG on Power Plant Response to Load Changes, “MW Response of Fossil Fueled Steam Units,” IEEE PAS, March/ApriI 1973, pp 455-463.

[7] D. N. Ewart, “Who‘s Watching Frequency These Days,” Power Technology, Issue 53, April 1988.

[8] D. G. Carroll, R. G. Serenka, and H. R. Propst, “BWR Maneuvering Capability,” Proceedings of American Power Conference, 1979, pp 73-78.

[9] N. P. Mueller, “Response of Pressurized Water Reactors to Network Power Generation Demands,” IEEE PAS, October

[IO] A. Klopfenstein, uReSponse of Steam and Hydroelectric Generating Plants to Generation Control Tests,” AlEE PAS, December 1959, pp 1371-1381.

[ l l ] P. D. Henderson, er al, “Cost Aspects of AGC, Inadvertent Energy and Time Error,” IEEE TPS, February

[12] L. S . VanSlyck, N. Jaleeli, and W. R. Kelley, “Implications of Frequency Bias Settings on Interconnected System Operation and Inadvertent Energy Accounting,” IEEE TPS, May 1989, pp712-723.

E131 N. Cohn, “Discussion of : The Megawatt-Frequency Control Problem: a New Approach Via Optimal Control

[14] N. Cohn “Control of Generation and Power Flow on Interconnected Systems,” John Wiley and Sons, Inc. New York 1961.

[15] T. Kennedy, S . M. Hoyt, and C. F. Abell, “Variable, Non-Linear Tie-Line Frequency Bias for Interconnected Systems Control,” IEEE TPS, August 1988, pp1244- 1253.

1161 K. P. Schulte, W. L. McReynolds, and D. E. Badley, “Modified Automatic Time Error Control and Inadvertent

1982, ~~3943-3950.

1990, pplll-118.

Theory,” IEEE PAS, April 1970, ~574-576.

Interchange Reduction for thc WSCC Inlcrconneded Power Systems,” Paper 90SM 304-7 PWRS, IVesenled at I99U 1EWpES Sunmer Meeting, m K a y o l i s , July 16-19.

ACKNOWLEDGEMENTS T h e Task Force (Authors) wisll to acknowledge

contributioiis from: C. F. Abcll, J. R. Beachman, A. Bose,

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[I71 L. S . VanSlyck, N. Jaleeli, and W. R. Kelley, “A Comprehensive Shakedown of an Automatic Generation C00tr0l Pr-s~,” IEEE TPS, May 1989, ~~771-781 .

BIOGRAPHIES Nasser Jaleeli (M’79) graduated from the College of Engineering, University of Tehran in 1%7. He earned the PhD in Electrical Engineering from tbe Imperial College of Science and Technology, of the University of London in 1975. He joined the teaching staff of Arya-Mehr University of Technology (AMUT) in 1967. While serving AMUT as an Assistant Professor from 1975 to 1979, be actively served the local industry and, in particular, as the head of Electrical Services Division of Bonyan Consulting Engineers.

Dr. Jaleeli joined Ohio University in 1979, attaining the rank of associate professor before joining AEP Service Corporation in 1983. At AEP he has been principal or co- principal investigator for several system control center pro- jects. Automatic generation control has been his main respon- sibility in recent years. He is a Principal Engineer in Operations Control Systems.

Dr. Jaleeli is lhe author or coauthor of several research papers in the Electric Power Systems field. He is a registered Professional Engineer in the State of Ohio, and a member of Eta Kappa Nu.

Louis S. VaoSIyck (M’SS, SM’63) has over 35 yean expe- rience in the elecaic industry, primarily in computer applica- tions for power system operation and engineering. He earned the BSEE and MSEE degrees from North Dakota State University, and tbe PhD from Illinois Institute of Technology, all in Electrical Engineering.

Joining the American Electric Power Service Corporation in New York in 1968, Dr. VanSlyck participated in research, development, and implementation of the h t large power sys- tem network state estimator in the world. He is presently an AEP Senior Staff Engineer in Engineering Computer Applications at Columbus, Ohio.

lo the WEE, Dr. VanSlyck has been chairman, 1966, of the Red River Valley Subsection. He was an original member of the Power Engineering Education Committee (PEEC) and served drat committee from 1963 to 1975, including four years as its secretary. He was responsible for publishing the surveys of Electric Power Engineering E<lucatiooal Resources in U.S. accredited schools for 1970, 1972, and 1974. In 1980 he nxeived the IEEE award for recognition of dislinguished seMce to the Power Engineering Society.

Dr. VanSlyck is a meniber of Tau Beta Pi, Eta Kappa Nu, and the Society of the Sigma Xi for “Dedication to Research in Science.” He has been 3 registered Professional Engineer in North Dakota since 1959, and in the state of Ohio siiice 1972. He is the author or coauthor of several research papers in the Electric Power Systems lieid.

Scbeoectady, NY, where be conducted studies in bulk power system stability, boiler and control simulations, excitation and turbine control analyses, automatic generation control synthe- sis, and subsynchronous resonance. Mr. Ewart was responsible for the formu1;ltioO of GE’s digital implementation of AGC and following through with field installation. Mr. Ewart was: named Manager, System Dynamics and Control in 1969, and Manager, System Performance Engineering in 1977. During this period he made major contributions to define the role of large interconnected power systems.

In 1980, Don changed assignments, becoming Manager, Transmission and Distribution, with respomibilities for studies and product application engineering for ac and HVDC Transmission, Distribution Systems, and for EPRI’s High Voltage Transmission Research Center in Lenox, MA. Systeni engineering for several large General Electric HVDC projects was carried out under his direction.

Mr. Ewart joined Power Technologies, TOC. in 1987 where he is Manager, Consulting Services. Don i s a Fellow of the LEEE, and an active member of the Power Engineering Society and the Fellows Committee. He is the author of over 40 tech- nical articles and papers, and a registered Professional Engineer in the states of New York and Massachusetts.

Lester H. Fink (M’51, SM’S8, F’73, LF’90) received the BS and MS degrees f” the University of Pennsylvania in 1950 and 1960. He has forty years experience in’eledric utility systems engineering and re.search, including twenty-four years with tbe Philadelphia Electric Company. At Philadelphia, he conducted researcb for and drafted the functional specifications for the indusby’s first digitaUy directed automatic generation control system and, a decade later, its second-generation replacement. Les has authored or coauthod some chi- papers, and holds two U.S. patents related to power system control.

Arthur C. Hoffmann (M’62, SM’75) graduated fmm the University of Pittsburgh with a BSEE degree. After graduation be joined the EMS Department of Westinghouse Electric wbere he beld various positions from Project Manager through EMS Depmment Manager. He is currently Chairman of ECC, Inc., which he co-founded in 1978. Mr. Hoffmann is also Chairman of the System Control Subcommittee of the Power System Engineering Committee. He is a Registered Professional Engineer in several states and a member of Eta Kappa Nu.

Donald N. Ewart (M’SS, SM’75, F’78) is a native of Buffalo, New York. He holds a BSEE degree from Come11 University and an MS degree in Engineering from Union

After gaining experience in the US. Air Force and the Generrrl Eleclric Transli)rlner Depdrtlllenl he joined GE’s Electric Utility Systeais Engineering Department in

College.

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DIBCUBSION

JACX Y. YILLER, Cajun Electric Power Coopera- tive, Baton Rouge, LA. The authors are to be complimented for presenting the technical de- scription of AGC so clearly. The industry has needed such a fundamental review. It would be interesting if the authors would ex- pand the subject somewhat and discuss the economics of AGC as well. Specifically, what is the affect of generating unit load- frequency control on production cost? Does system load-frequency control increase or reduce the system production cost?

H. Glavitsch, (Swiss Federal Institute of Technology, CH8092 Zurich, Switzerland): This is a very much needed and timely paper which clarifies a number of subjects of automatic generation control. The authors and the task force are to be congratulated on their efforts and care in explaining the concepts, limitations and facts. Unfortunately, there have been several misconceptions of AGC earlier which have led to unrealistic investigations out of which papers have been published whose results are quite impractical. The present paper puts almost all of them in the right perspective and says what is possible and reason- able in this field.

One of the main items which quite often has been the starting point of misled investigations is the turbine-generator model which was expanded to a two-area model for AGC. The parameters of this model give the impression that the output of the turbine can be changed in a fast way. Studies which do not take into account the crossover ele- ments in a thermal unit or the behavior of the penstocks in a hydraulic installation nor the real sampling interval of the data acquisition system come to results where frequency or tie-line power could be corrected within one second. Irrespective of the fact that this is not possible there is no incentive to control the system in such a way as the paper makes it clear from various directions. If frequency devia- tions (several hundreds of mHz or over one Hz) are to be expected other means like load shedding have to be employed.

In Europe there is an extended experience with AGC in the UCPTE system. One feature is that area controllers with different sampling rates (decision cycles) and different control laws (propor- tional, proportional-integral) having different parameters cooperate without difficulties. In at least one country AGC is implemented on two levels, one receiving setpoints from the other. So the basic concept of AGC is very robust.

It might be useful to consider the following few additional remarks which could be helpful in understanding the material in the paper.

Under “Tie-Line Bias Control” a verbal explanation is given as to the adjustment of the bias B, e.g. by the term “acceptable match.” In the years of active development of AGC the term “non-interactive control” has been introduced which means that no control actions should be initiated, for example in area 2 when the power upset is in area 1 (as assumed in the paper). This can be achieved by setting B equal to p. The paper explains that p is not constant and difficult to measure or to obtain which is certainly correct. As a concept, however, it is worthwhile to mention it. It is to be kept in mind, that no “control actions” means no “AGC control” (ACE = 0) whereas primary con- trol will contribute significantly to the support \of the other area.

At another point, namely in the conclusion of the chapter on multi-area control (written in italics), it is found by this discusser that the foregoing arguments are not logically leading to this statement. The points mentioned before that statement are subjects of the control structure, observability and controllability. It is agreed that a quick return of the frequency is no basis for advocating an AGC algorithm but the reasons for not aiming at a quick return lie in the technical constraints of the turbine-generator set and not in the control structure. So, an explanation of this point may be useful.

For the purposes of discussing the effects of incorrect measure- ments and of various modes of AGC operation the following analysis is offered which may complement the explanations in the paper.

Assume a three area system which is to operate under AGC. for each area the formation of an ACE according the formula in the paper is assumed.

ACE, = Ta, - Ts, - IOB, (Fa - Fs,), i = 1,2,3

In addition the power balance must hold:

Tal + Ta, + Ta, = 0

Each AGC controller should function according to a control law which in the final steady state reduces the ACE to a small value which is zero if the law is integrating. If the ideal case is assumed (ACE = 0) the following system of equations can be set up

Tal Ta, Ta, Fa a1 - 10 B, = Ts, - 10 B, Fs,

1 - 10 B, = Ts, - 10 B, Fs, = Ts, - 10 B, Fs, 1 - 10 B,

1 1 1 - . = o

All the setpoints governing the exchange of power and the frequency are on the right-hand side. All the variables are on the left side.

The system has a solution if the matrix is non-singular which can be achieved if the sum of the bias values does not disappear. A first conclusion from this requirement is that at least one area has to do frequency control (one B must be non-zero). The converse is also true. None of the areas or several together can do flat frequency control. This is equivalent to avoiding that one of the diagonal one’s becomes zero which would lead to singularity. As far as errors in measuring tie-line power or frequency is concerned which can be transformed to errors in the setpoints it can be stated that the system has a stable solution irrespective of inaccurate setpoints. The right-hand side must not be consistent or must not have accurate values for Fsi, for example. The AGC system will generate a set of tie-line powers and one well defined frequency. They will deviate from the setpoints but the system is stable which in general leads to inadvertent interchange and to a time error.

Thus, there is another indication that the AGC system is quite robust allowing non-consistent setpoints without jeopardizing the sys- tem.

It is hoped that the findings of this paper will find its due recogni- tion among system analysts and researchers.

Manuscript received March 3, 1991.

Charles Concordia, Consulting Engineer, Venice, Florida. I would like to offer the following comments:

As a general comment, transmission in a single company not only serves to go from generator to load, but also serves to permit sharing of load changes among all generators. This is well known, and within a company advantage is taken of this to avoid large generation changes on any particular generator. It would be ridiculous to have tie-line control exten- sively within a company. From a physical point of view the-- benefits should be obtained from interconnections between com- panies, Thus it is almost too obvious that rigidly controlling “tie - line” loading is silly.

The only negative comment I have is that, even though I agree with most of the paper, it is always dangerous to say that something cannot be done in the future, and the somewhat nega- tive tone of the paper may “turn some people off“, who ought to read it.

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THOMAS KENNEDY (System Operations Consultant, St. Louis,Missouri) The authors and the System Control Subcommittee are to be complemented for setting the stage for further discussion of the very complex topic of automatic generation control (AGC). It is the opinion of this discusser that the conclusions reached in the paper (in italics) are correct. The North American Electric Reliability Council (NERC) Operating Committee is certainly very much concerned with developing an acceptable "definition of a desirable generation trend".

The NERC Operating Committee promotes the reliable and coordinated operation of the North American interconnections through operating policies and procedures that are contained in the Reliability Criteria for Interconnected Systems Operation (Criteria) and the Operating Guides (Guides). The Criteria and Guides (rather than guidelines) deal with all aspects of interconnection contro1,including AGC, and are designed to promote an orderly sharing of interconnection resources and burdens. While AGC is certainly an important part of interconnection control, it is just one facet of the overall interconnected systems operation.

The paper should be read with the perspective that the system operator has several operating tools and procedures at his disposal, including AGC, that aid him in operating his system in a reliable and economic manner. Those same tools also allow him to contribute to the reliable and economic operation of his interconnection by following the NERC Criteria and Guides. Present day control room facilities coupled with present day operating techniques and procedures are quite adequate for the system operator to fulfill both of these obligations. The authors are quite correct in stating that a number of the requirements and recommendations of the NERC Operating Guides, regarding system regulation, cannot and should not be accomplished through AGC. However, it must be remembered that the NERC Criteria and Guides can all be followed by the proper application of the operating tools and procedures at the system operator's disposal. AGC capability or intended use should not be confused with the control area's obligation to follow the NERC Criteria and Guides.

The paper is correct in its description of the "flat tie line " unstable control action when there is a tie line measurement error on the part of one of two control areas. However, where the system response is recognized through a frequency bias setting, a stable frequency point will always theoretically be reached. Also, both the low and high bias setting cases, described on page 4 of the paper, will result in a frequency and interchange movement similar to that shown in Figure 1 of reference 15. It should be noted that tie line bias control was developed to eliminate some of the disadvantages of "flat tie line" or "zero bias" control.

The strategy that discusses the cost of "wear and tear" of regulating generating units should also mention the obligation of each control area to carry its share of the regulation burden and not cause undue burden to its interconnection neighbors. It also should consider the differential cost of an uneconomic combination of regulating units that could result from insufficient regulating capability of some generating units.

The NERC interconnections have a multi- control area configuration and therefore must rely on tie line bias control. However, some interconnections of the world, such as the British grid and the Chinese provincial systems, are centrally controlled as a single area. Single area control requires that frequency be controlled by AGC but, of course, does not require direct AGC control of tie lines. While the multi-area configuration must closely control frequency and interchange, because they are so closely interlocked (l), the centrally controlled system can use frequency as a regulating tool if their "biggest contingency to system size" ratio is small.

Areas of AGC technology that the discusser feels need further study include HVDC interties characteristics, proper application of expert systems, and automatic MVAR control between control areas.

References [ I ] L.A.Mollman,and T - K e n n e d y . "Interrelationship of Time Error, Frequency Deviation, and Inadvertent Flow on an Interconnected System", Paper 31 TP 67-136 presented at the IEEE Winter Power Meeting, New York, N.Y. January 29-February 3 , 1967. Manuscript received February 19, 1991.

ROBERT P. SCHULTE (Consulting Engineer, Portland, Oregon): This paper does indeed provide a good viev of many AGC topics that are of interest. The folloving discussion is about the topics of acceptable ACE trend and vear on regulation units.

In the paper the highest rated attribute of AGC strategies for a multi-area inter- connection is one that yields a more acceptable ACE trend. Much further dovn the list of strategies is an attribute that accumulates lover cost associated vith vear and tear of regulation on all units. These strategies, vhich are given in preferred order, are not exclusive. To a limit, as is pointed out in the paper, an improved ACE trend does require greater response by regulating units to AGC signals.

Thus a more acceptable ACE means more strict load and schedule folloving by energy sources in the area. In assessing the present state of AGC the authors point out in their conclusion the futility of attempts to reduce ACE performance belov some threshold. But vhat vi11 happen in the future as pover system demands grow? Increasingly additional loads are being met vith scheduled imports and alternative source or non-utility generators vithout AGC Capability. Also, as is mentioned, nuclear plants are not usually used for AGC. Will ve then be obliged to put even greater AGC duty on existing regulation units, vi11 ACE control performance threshold suffer or vi11 we reach a time when ve must employ special energy conversion devices of some kind designed for area load folloving? Manuscript received March 4 , 1991.

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Carson W. Taylor, Bonneville Power Administration, Portland, Oregon: The purpose of this paper seems to be to lay to rest the "mischief" started by Elgerd and Fosha [A,B] over twenty years ago. Although many of the basics in the present paper were given in the discussions of references A and B, many subseqent academic papers have made unwarranted assumptions. AGC is a slow (tens of seconds) follow-up control to return frequency and interchange to scheduled values following disturbances. For system dynamic perfor- mance, attention should be paid mainly to the primary powerplant controls (excitation, prime mover, and en- ergy supply controls). These controls are often poorly tuned. Data is generally unavailable for energy supply system models. Area control cannot be responsive if the power plant generation controls are either sluggish or excessively oscillatory. Besides helping the bookkeepers and keeping clocks accurate, there are other reasons for good AGC perfor- mance. Part of the difficulties in connecting the eastern and western North American interconnection in the late 1960s was probably due to poor AGC performance such as undergeneration during morning pickup. The diffi- culties led to an expensive solution-back-to-back dc links. My study indicated, however, that the generation and transmission additions in Montana, Wyoming, Nebraska, and the Dakotas of the 1970s would have allowed successful ac interconnection. Partly because of concerns related to the poor AGC performance of the eastern interconnection the study was rejected by west- ern utilities. Special generation control at selected power plants and improved AGC logic might have improved performance of the interconnection. Improved AGC logic might have been reduced frequency bias coeffi- cients for western utilities during morning pickup hours of the eastern interconnection-. The bias coeffi- cients should be closer to the early morning western natural response (p). Such logic is feasible with digital AGC . Related to the above paragraph, recall that a motivation for the Elgerd and Fosha work was the east-west inter- connection problems. The paper focuses on the potential for automatic genera- tion control to improve system dynamic performance.

Nowadays, slowly occurring voltage instability is a major industry concern. One solution is fast emergency automatic generation control. There is a race between generation increase to improve stability and generator current limiting and transformer tap changing. Several examples can be cited to show the importance of genera- tion control:

A voltage collapse in southern England on May 20, 1986 was averted by emergency start of 1000 Mw of gas turbines within five minutes [Cl.

Voltage stability along the Pacific AC Intertie [Dl for disturbances such as loss of the 3100 MW Pacific DC Intertie could be improved by fast generation changes in the Pacific Southwest. The Hoover hydro power plant and several pumped storage plants are candidates for large power increase. AGC in the Southwest can detect the loss of the major tie-lie (DC Intertie) and command the generation change. Controls are available [E] to

make very large hydro generation changes within one minute.

The Puget Sound (Seattle) area voltage stability problems can be improved by dropping hydro generation in eastern Washington state and ramping generation to the north (B. C. Hydro) and to the south. Activation of reactive reserve at generators or SVCs could be used to trigger the generation changes.

You say you are providing a resource to guide research into topics related to AGC. What research do you think is needed? I think better characterization of both prime mover con- trol deadbands (andor backlash) and natural regulation may be useful. The statement is made that many gover- nor deadbands are beyond 0.035 Hz (0.06%). Reference F and its discussions address this subject; see also refer- ence G. We should realize that a t any point in time, gov- ernors may be positioned randomly within deadbands and for large systems a statistical characterization is useful. Many hydraulic governors have vibration motors t o reduce deadband by dither modulation; process noise may also provide dither modulation. Do you advocate in- tentional deadbands for electronic prime mover control? Incidentally, IEEE Std 122-1985 IEEE Recommended Practice for Functional and Performance Char- acteristics of Control Systems for Steam Turbine- Generator Units depreciates the term governor % ad- vance the understanding that control systems need not be limited to rotating flyweights but include mechanical, hydraulic, and electronic components."

Do you have evidence regarding the statements that relatively small generation-load imbalances are arrested mainly by load response?

You say that "the system natural response coefficient, p, is not a constant, neither is it accurately obtainable nor predictable." Do you favor research of on-line estimation of p with a view toward adaptive control (setting B = p)? From time-scale separation or psuedo steady-state notions, "perfect" calculation of ACE results with B = p. I have always felt this attacks unnecessary control and oscillation problems at a fundamental level. I commend you for a paper that advances the under- standing of automatic generation control.

A . 0. I. Elgerd and C. E. Fosha, Jr., "Optimum Megawatt- Frequency Control of Multiarea Electric Energy Systems,' IEEE Transactiom on Power Systems, vol. 89, no. 4, pp. 556-563, April 1970.

B . C. E. Fosha, Jr. and 0. I. Elgerd, "The Megawatt-Frequency Control Problem: A New Approach via Optimal Control Theory," IEEE Transactwns on Power Systems, vol. 89, no. 4, pp. 563477, April 1970.

C M. G. Dwek, Study Group 38 discussion, Proceedings of 33rd CIGRE Session, vol. 11, 1988.

D . W. Mittelstadt, C. Taylor, M. Minger, J. LuiN, J. McCalley, and J. Mechenbier, 'Voltage Instability Modeling and Solutions as Applied to the Pacific Intertie," CIGRE 38-230,1990.

E . D. N. Scott, R. L. Cresap et al., 'Closed Loop Digital Automatic Generation Controller,' IEEfPES C73 518-8.

F . C. W. Taylor, K. Y. Lee, and D. P. Dave, 'Automatic Generation Control with Governor Deadband Effects," I E E E Transactions on Power Apparatus and Systems, vol. PAS-99, pp. 2030-2036, Novembermecember 1979.

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G. C. W. Taylor, discussion of "Inertial, Governor, and A w l Economic Dispatch Load Flow Simulations of Loss of Gen- eration Contingencies," IEEE Transactions on Power Apparatus and Systems, vol. PAS-104, no. 11, pp. 3020-3028, November 1985.

A. Kryhrni (The Ohio State University, Columbus, OH): The authors have performed an invaluable nervice to the utility in- dustry by presenting the practical limitations of AGC which are constrained by the dynamic response of the process involved. The authors have defined a number of strategies that clearly define what AGC is expected to perform when it is controlled M a process. In these strategies, limited knowledge of process dynamics is utilized. However, a strategy which uses the gross dynamics of a boiler for the dynamic control of generation and load may also be considered. In the following, such a strategy will be presented, and the authors' comments concerning the proposed strategy are welcomed.

Let the gross dynamics of a boiler be represented by the fol- lowing linear, vector difference equations.

X ( t + 1) = X ( t ) + B U ( t )

where

and P ( t ) is the MW generated at time t .

Also, ansume the energy delivered to the system is con- strained to be equal to the energy consumed by the load over the next few minutes; that is

where &(to) is generated M W at time to; ACEis the area control error, Pf is the forecseted load a t time to + 2'; and T is the final time of control. T is appropriately chosen based on boiler response. The discrete version of the above equation can be written BB

pc(t) t A C E t PfT N-1

2 P(t )At =

1=0

The constraints of the control problem can be expressed as

a) Final time of control in fixed

b) Initial and terminal boundary values are given

X ( 0 ) = So X ( N ) = X ( T )

c) The control variables and the state variables must satisfy a magnitude constraint:

X n i n I X ( t ) I Xln, k i n I U ( t ) 5 Um.x

d) The rate of change of state variables must satisfy a mag-

nitude constraint:

( X ( t + 1) - X ( t ) ( I &,e

e) The rate of change of state variables must be zero at t = N; i.e., the system must reach a smooth level at the final time of control (i.e., X(t,) = 0)

X ( t - 1) - X ( t ) = 0

The problem is to find a control sequence U = (Uo, U , , . . . Ut-l) and a corresponding trajectory S = (Xo, XI,. . . Xt) determined by the above equations and condi- tions while minimizing the performance index J:

t=o

where D ( t ) is a weighting vector on control actions.

For such a control, the gross boiler model developed by Astrom [I] can be used. In this model, the control variables are fuel flow, valve setting and feed water flow, and the state variable is the drum pressure.

The above control strategy may be possible, if the models of power plant components are developed for AGC control. AU- thors' comments concerning the above are welcomed.

[I] Astram, K.J. and Eklund, K., "A Simplified Non-Linear Model of a Drum Boiler-Turbine U i t , " Int. Journal of Con- trol, Vol. 16, No. 1, 1972.

T.S.Bhatti,D.P.Kothari,and J - S a t i s h ( Ind ian I n s t i t u t e o f Technology De lh i , I nd ia ) : We wish t o commend the authors f o r t h e i r extremely valuable and t ime ly c o n t r i b u t i o n i n the important area o f AGC. This Task Force paper would go a long way i n p rov id ing a g rea t resource t o researchers ,p rac t is ing engineers and students t o understand and t o c a r r y Out f u r t h e r research i n t o AGC r e l a t e d top ics . However, we would l i k e t o o f f e r some comments and seek the au thor 's c l a r i f i c a t i o n on some po in ts . 1. I t i s a p r a c t i c e by u t i l i t i e s t o use a

smal l value o f speed droops f o r a c t i v e generators i n the range o f 3% t o 5%.The percentage droop o f each u n i t determines the shar ing o f a d d i t i o n a l load amongest the var- i ous generat ing u n i t s . & h igher value o f speed droop ensures more s t a b l e p a r a l l e l opera t ion whereas a lower value o f speed droop prov ides b e t t e r load frequency control .Thus a balance has t o be s t ruck between the two t o a r r i v e a t optimum value. ~n our computer s imu la t i on s tud ies f o r AGC we have found t h a t lower value o f speed droop(4%) and higher value o f speed droop (10%) g i v e more or l e s s same dynamic responses(frequency,tie-power and ACE dev ia t - ions) f o r reheat thermal u n i t s i n presence o f generat ion r a t e constraint(GRC) o f 3%/min. Therefore, one wonders i f i t i s poss ib le t o p r e f e r a higher value of speed droop f o r thermal u n i t s ? . I f the answer i s yes, then, w i l l the governor be economical ly cheaper?.If the answer i s no, then f o r what reasons?

I

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a d d i t i o n t o ACE p r o c e s s i n g l o g i c i n t r o d u c i n g f u r t h e r d e a l y s . I n v i e w o f t h i s how f o r i t i s j u s t i f i e d t o u s e 2 - 4 s e c o n d s for a d a t a a c q u i s i t i o n a n d d e c i s i o n c y c l e s o f t h e AGC s y s t e m s ? S h c u l d a h i g h e r v ~ l u e o f s a m p l i n g p e r i o d b e e x p l o r e d t o p r o v i d e m o r e o r l e s s b e s t t r a n s i e n t r e s p o n s e a n d r e d u c e s s i m u l t a n e o u s l y t h e s a m p l l n g e i f o r r ? C a r p e n t i e r [ l ] i n h i s s t a t e o f t h e a r t review p e r t a i n i n g t o AGC h a s s t a t e d t h a t a s a m p l i n g p e r i o d v a r y i n g f r o m 2 -10 s e c o n d s i s u s e d by u t i l i t i e s . B o s e a n d A t i y y a h [ 2 ] h a v e u s e d s a m p l i n g p e r i o d s v a r y i n g f r o m 2-30 s e c o n d s . We w o u l d t h e r e f o r e l i k e t h e a u t h o r s t o c o m m e n t o n t h e o p t i m u m s e l e c t i o n of t h e s a m p l i n g p e r i o d .

I n t h e o b j e c t i v e s o f AGC t h e a u t h o r s s t a t e t h e s t r a t e g i e s t h a t e x p l o i t u n i l a t e r a l i n a d v e r t e n t c o r r e c t i o n s , w h i c h s i m u l t a n e o u s l y r e d u c e t i m e e r r o r m a y b e c o n s i d e r e d t o d e s e r v e h i g h e r s c o r e . T h e s e a r e a c h i e v e d by a n AGC s t r a t e g y b a s e d on n e w a r e a c o n t r o l e r r o r (ACEN) 1 3 1 . T h e ACEN i s b a s e d o n t i e p o w e r d e v i a t i o n , f r e q u e n c y d e v i a t i o n , time e r r o r a n d i n a d v e r t e n t i n t e r c h a n g e . T h e AGC s t r a t e g y b a s e d o n ACEN g u a r a n G e e s z e r o s t e a d y s t a t e e r r o r o f i n a d v e r t e n t i n t e r c h a n g e a n d t i m e e r r o r a c c u m u l a t i o n s i n a d d i t i o n t o r e g u l a t i n g ACES t o z e r o f o l l o w i n g l o a d p e r t u r b a t i o n s . We w o u l d a p p r e c i a t e t h e a u t h o r s c o m m e n t o n t h e u s e o f AGC s t r a t e g y b a s e d o n ACEN.

I n a n AGC s y s t e m t h e n ~ t h o r s m e n t i o n t h a t

z e r o a s t h i s w o u l d r e q i l i r e u n n e c e s a r i l y r a p i d m a n e u v e r i n g o f u n i t s . C o u l d t h e a u t h o r s t h r o w s o m e l i g h t o n a p p r o p r i a t e selection o f m i n i m u m l e v e l o f ACE f o r AGC?

i t i s n o t d e s i r b a l c L O m a i n t a i n ACE a t

However. f o r hydro u n i t s generat ion r a t e cons- t r a i n t i s very h igh (270%/min f o r r a i s i n g generat ion and 360%/min f o r lower ing generat- i o n ) and i n our s imu la t i on s tud ies we have found t h a t a lower value o f speed droop(4%) g ives much b e t t e r frequency s t a b i l i z a t i o n as compared t o the higher value o f speed droop and GRC l i m i t was never v i o l a t e d . I n f a c t . i n the Northern g r i d o f I n d i a , speed droops o f many hydro u n i t s a re i n the range o f 3% t o 4%. 2. We f u l l y agree t h a t for the thermal

uni ts,governor t ime constant(Tg)and the steam chest t ime cons tan t (T t ) a re much smal le r than the o ther t ime constants used f o r s imu la t i on o f AGC model[ l ] .

3.The load changes occur always i n random fashion i n a r e a l system which r e s u l t random opera t ion of the governor a c t i o n and produce s tochas t i c v a r i a t i o n s i n the frequency and the t i e - l i n e power nominal values[2].How the ACE s i g n a l will be monitored i n t h i s case f o r d e r i v i n g the supplementary c o n t r o l l e r ? . 4. We have a l so found [21 t h a t the e f f e c t of governor deadband on the dynamic response i s no t s i g n i f i c a n t b u t i t has a tendency t o fo rce the dynamic response t o o s c i l l a t e f o r l ong pe r iod around i t s steady s t a t e value.

Once again we would l i k e t o h e a r t i l y congra tu la te the authors f o r an exce l l een t p iece o f work and look forward t o t h e i r f u r t h e r i nves t i ga t i ons i n the f i e l d .

[l]. 1.J.Nagrath and D.P.Kothari " Modern Power System Analysis ",I1 edn, Tata McGraw- H i l l ,NewDe lh i , l 989 . [ 2 ] : S.C.Tripathy, T.S.Bhatt i , C.S.Jha, O.P. Ma l i k and G.S.Hope, " Sampled data Automatic Generation c o n t r o l Ana lys is w i t h Reheat Steam Turbines and Governor Dead-Band Effects", IEEE Trans.on PAS.vol .PAS-103,No.5,May 1984,pp.1045 -1051.

REFERENCES

J.NANDA, M.L.KOTHAR1, L. H A R I , G . G . B H I S E ( D e p a r t m e n t o f E l e c t r i c a l E n g i n e e r i n g , I . I . T . D e l h i , I n d i a ) : We w o u l d l i k e t o c o n g r a t u l a t e t h e a u t h o r s f o r a u s e f u l . a n d i n t e r e s t i n g p a p e r . p r o v i d i n g i n d e p t h u n d e r s t a n d i n g o f a u t o m a t i c g e n e r a t i o n c o n t r o l . We s h a l l v e r y m u c h a p p r e c i a t e t o h a v e t h e c o m m e i i t s o f t h e a u t h o r s o n t h e f o l l o w i n g p o i n t s :

1 .

2 .

T h e a u t h o r s m e n t i o n s p e e d d r o o p s f o r a c t i v e g o v e r n o r s t o b e i n t h e r a n g e o f 5%. A p p a r e n t l y l i t t l e a t t e n t i o n h a s b e e n p a i d t o t h e o p t i m u m s e l e c t i o n o f g o v e r n o r r e g u l a t i o n p a r a m e t e r R w h i c h d e c i d e s t h e g o v e r n o r d r o o p . O u r i n v e s t i g a t i o n s f o r a t w o e q u a l a r e a s y s t e m s h o w t h a t i n t h e p r e s e n c e o f t h e s u p p l e m e n t a r y c o n t r o l ( i . e . AGC) w i t h a g e n e r a t i o n r a t e c o n s t r a i n t (GRC) o f J X l m i n , a m u c h h i g h e r v a l u e o f p e r c e n t a g e d r o o p e v e n t o t h e t u n e of a r o u n d 1 5 % may b e p r e f e r r e d t h a t p r o v i d e s b e t t e r t r a n s i e n t r e s p o n s e . We b e l i e v e t h a t a h i g h e r v a l u e o f R m a k e s t h e r e a l i z a t i o n o f t h e g o v e r n o r s i m p l e r a n d r e d u c e s i t s c o s t . C o u l d t h e a u t h o r s f r o m t h e i r e x p e r i e n c e s u g g e s t g u i d e l i n e s f o r o p t i m u m s e l e c t i o n o f R f o r g o v e r n o r d e s i g n ?

T h e a u t h o r s r i g h t l y m e n t i o n a b o u t t y p i c a l f i l t e r s o n t i e - l i n e m e t e r i n g i n t r o d u c i n g d e l a y s o f u p t o a f e w s e c o n d s i n

-

3 .

4.

REFERENCES

1.

2 .

3 .

J . CARPENTIER " S t a t e o f t h e a r t r e v i e w , T o b e o r n o t t o b e m o d e r n " t h a t i s t h e q u e s t i o n f o r A u t o m a t i c G e n e r a t i o n C o n t r o l ( p o i n t of v i e w o f a u t i l i - . y e n g i n e e r ) " , I n t . J . E l e c t r i c a l P o w e r a n d E n e r g y S y t e m s , V o 1 . 7 , A p r i l 1 9 8 5 , p p . 8 1 - 9 1 .

A.BOSE a n d 1.ATIYYAH " R e g u l a t i o n E r r o r i n L o a d F r e q u e n c y C o n t r o l " , IEEE T r a n s o n P o w e r A p p a r a t u s a n d S y s t e m s , V o l . P A S - 9 9 , M a r c h / A p r i l 1980, p p . 6 5 0 - 5 5 7 .

M.L.KOTHAR1, J . N A N D A , D.P.KOTHAR1, a n d " D i s c r e t e Mode A u t o m a t i c D.DAS.

G e n e r a t i o n C o n t r o l o f a Two Area R e h e a t T h e r m a l S y s t e m w i t h N e w A r e a C o n t r o l E r r o r " , I E E E T r a n s On P o w e r S y s t e m s V o l . 4 , May 1989, p p . 7 3 0 - 7 3 8 .

J. Z. PONDER, G. A. CUCCHI, (Pennsylvania-New Jersey- Maryland (PJM) Interconnection, Nomstown, PA. 19403): This paper provides an excellent tutorial summary of Automatic Generation Control. However, it is a bit frustrating for the reader to see the stage set so well and then be left without seeing the play! While the general notion of what

1118

constitutes "good control" has been discussed at length within the industry, no one has yet defined the specifics.

As it stands today, some control areas do an excellent job of control as evidenced by their NERC A1 and A2 control performance criteria. Some control areas approach 100% compliance with the NERC criteria. Other control areas perform very poorly, as defined by existing standards, with A1 and A2 compliances below 50%. Probably adequate performance lies somewhere in between these two extremes. Can the authors comment on the reasonability of the existing NERC criteria for measuring control performance and/or suggest other specific measures of performance which would be better?

It may also be desirable to maintain "good control" for other than reliability reasons. For instance, it is desirable to maintain a reasonable match between scheduled and actual interchange for accurate accounting purposes. If a control area does a poor job of generation control, then its actual interchange may have little relationship to its scheduled interchange, resulting in large inadvertent interchange accumulations and gross inequities for the parties involved with the transactions. Inadvertent interchange is often paid back at a more favorable time than it was accumulated. The requirements for "good control" to prevent such inequities may exceed that required for reliability. Has the task force examined this and if so, what were the conclusions?

On the subject of generating unit characteristics, we have seen instances where the modem coordinated control systems have resulted in poorer initial response from units. Apparently, the coordination of the turbine output with the boiler response restricts the unit from using stored energy in the boiler. Older systems allowed wider swings of boiler pressure and temperature as the stored energy was drawn from the boiler. Coordinated controls block the steam valves from opening if it would mean drawing down the boiler pressure or temperature. This is of course good from a boiler control standpoint, but results in less aggressive initial governor and AGC response from the unit.

The paper discusses kinetic energy and load frequency response from a very traditional viewpoint. Can the authors comment on the effects of the newer dynamic controlled loads, such as load commutating inverters, which digitally sense frequency and may draw more power to maintain the local loading level? Such modem air conditioning controls had an impact on the July 23, 1987 Tokyo voltage collapse. Can traditional AGC techniques cope with these dynamic types of local load control?

On a more general level, the coordination of AGC with frequency, stability and voltage controls needs to be addressed. While the authors point out that many of these items have a much shorter time constant than AGC and therefor AGC cannot be expected to react to them, there have been instances where such problems have developed over periods of time consistent with AGC response capability. Lack of coordination of AGC with these problems can aggravate rather than help the situation. It is quite conceivable that AGC may take action counter to logic programmed for special relay schemes, under voltage relay load shedding and thyristor controlled devices which act independently from the AGC. Shouldn't the AGC strategy which best coordinates with these other independent controls be given some bonus points in the ranking?

Many control areas today must control to specific power transfer interface limits in addition to net interchange.

Traditional AGC schemes do not allow for this. Shouldn't this be one of the aspects for which strategies are compared to rank AGC schemes? At PJM, we find that we must operate to transfer limit restrictions about 60% of the time. This "split cost" operation of the system requires us to use manual control.

Another subject of interest is the NERC disturbance recovery criteria. The control areas in the MAAC and NPCC regions of NERC have instituted a joint Shared Reserve procedure in which neighboring control areas will assist a control area which has experienced a large disturbance. The assisting areas help the disturbed area to return ACE to zero within ten minutes. Are the authors proposing that this is unnecessary? It would seem that there is indeed some value in quickly recovering from a system disturbance, since additional disturbances, if they should occur before recovery of the initial disturbance, would cause a further drop in frequency, possibly resulting in load shedding.

There are many specific issues yet to discuss and resolve concerning automatic generation control. We hope that the Task Force and the industry will be able to develop more specific recommendations for automatic generation control. The specific answers to the question 'What is good generation control?" still remain unresolved.

Manuscript received March 4 , 1991.

M. K. Enns, (Electrocon International, Ann Arbor, Michigan): A few years ago I had occasion to examine the AGC behavior of a control area in connection with a dispute between a utility and a steel-making customer. The arc furnaces operated by the .customer caused large swings in demand that made it impossible for the utility, which constituted a small control area, to meet the NERC Control Perfor- mance Criteria. The utility experienced rapid and erratic response of their units under AGC without any apparent benefit in the form of good control. They were, in the language of the paper, "chasing high frequency components of demand change." They eventually took most if not all of their units off AGC and lived, with no cost and little inconvenience, with a somewhat large and nonconforming ACE.

This solution was really quite satisfactory. The ACE was large because the control area was so small. Combining with neighboring utilities to form a control area ten times larger would reduce the effective ACE by a factor of ten, which would easily conform to the NERC criteria. What appeared to be excessive interarea flows would simply be internal flows, unmeasured and unnoticed.

H. H. Thompson, (Chetty Mamandur, Energy Services, Inc., Pine Bluff, AR): We congratulate the authors for clearly summarizing the importance for tie-line bias control it he interconnected power system operations. We agree with the comments and conclusions of the paper on impacts and penalties of overachieving AGC control. In systems with significant nuclear units, which are not currently controlled by AGC, fewer remaining units are expected to provide all the control, hence requiring increased maintenance. Moreover, to accommodate the nuclear base load generation during minimum load periods, fossil-fired system-turbine units are being converted to sliding pressure type control to achieve lower minimum run levels. However, this mode of operation seems to result in reduced controlling capabilities for the units hence resulting in increased control demands from other units. Thus, the systems are forced to regulate with fewer and .fewer units that can be trusted to control. Hence, it is becoming very important that significant efforts be devoted to identify any unit problems and get as many units as possible, to participate in AGC control.

1119

Recently, there seems to be discussions for including integrated ACE in addition to ACE to determine unit desired generations. Would the authors kindly comment on the implications and impacts of this control.

Manuscript received March 4, 1991.

Jaleeli, VanSlyck, Ewart, Fink, and Hoffmann: We would like to thank all the discussers for their interest in the paper as well as their contributions. Our closure addresses points raised in the discussions and provides additional comments.

Mr. Miller’s questions are very much appreciated as tliey provide an opportunity to emphatically state that: “of-course, operating units with a well-designed AGC procedure rctliicrs the total production cost in the area.” AGC systenis allow much more frequent adjustment of the output power of cdcli unit as compared to a manual system where the adjustnicrit of each unit requires verbal communication b e t ~ e e i i a central control coordinator and the unit operator. Therefore, output power adjustments of units under AGC can be performed with much finer steps than are possible with verbal control. Hence, the unit output power trends can be held much closer to eco- nomical trends with AGC than wlieri all units are unclrr verbal control, or a mixture of AGC and verbal COllhYJl .

A review of Figures 1, 2 and 3 supports this claim. Figure 1 shows the load trend over a period of several minutes lor an area with two units. The optimal economic trend for each unit, as shown in Figures 2 and 3, are those that will minimize the area production cost over the given time window while their sum equals the area load trend. As shown in Figure 2 where both units are under AGC, the output power of each unit is adjusted frequently a t fine increments and trcnds are therefore maintained close to those of optimal rcononiiis. “lie small deviation of the output power trend of each iinit fioin optimal is due to irreducible imperfections of tlie AGC process including inaccuracies in the prediction of unit response to the control signals sent.

In the scenario depicted in Figure 3, unit 1 is verl)ally coli-

trolled and unit 2 is under AGC. Limitation on tlie frequency of verbal communications between a control center coordinator and the unit operator constrain the output powcr of unit 1 to be adjusted just once in the given time window, and with a necessarily large magnitude as shown conceptually in the up- per portion of Figure 3. Therefore the deviation of the trcntl of unit 1 output power from that of its optimal economic trrntl is much larger than that of the Figure 2 scenario. This devin- tion also impacts operation of unit 2. As the sum of the pover generated by the two units must equal the load, the generalion trend required from unit 2 must also differ substantially from its optimal economic trend.

The difference between area production cost undcr tlie scc- nario shown in Figure 2 and that in 3 depends on the incremen- tal cost characteristics of the units. Let XI and XL respecti\ely be the area incremental cost at the start and at the end of the shown time window. The greater the difference betweell dl and Xp, the more savings result from operating the units uiidrr AGC. Of-course, if A , and X2 are equal, the prodiiction cost for the scenarios shown in Figures 2 and 3 would he tlic same. However, tests conducted in 1989 on the AEP system (with in- stalled generation capacity of 23500 MW) have indicated that, on average, operation of an additional 1000 MW of capability

m.

unit2 ma . .-

Figure 2; BMh unita are aulMMticplly Conbolled.

Economic Tnnd

Unit 1 Tm

A

1. 7 I b

Tlnv Unit 2

Figure 3: Unit 1 la verbally maneuvered and, hance, can reallze generation changes only in large sleps. As a result, to match total generation with load, a step change in target, and otherwise unnecessary movement, is imposed on automatically controlled unit 2. Both units are consequently operatsd away from their economic trends.

under AGC, can realize a savings of $350,000 per year in fuel costs.

In reality, load variation is not a smooth line as shown in Figure 1; it fluctuates irregularly about its trend. While present NERC Control Criteria do not demand a tiglit match between generation and load, many control areas cause their generation to follow these fluctuations to some extent. Moving generation up and down will cause units to operate off eco- nomic base points some portion of the time. This can increase production cost and, in some literature, it is called rrgulation cost. Various authors go still further afield and call this the cost associated with putting units on LFC or even, unfortu- nately, on AGC.

Matching generation with area load fluctuations results in an unavoidable increase in cost over that of constant power output. Whether this matching is accomplished by verbal coni- munications or automatically by AGC, the cost of doiiig so is- an inherent requirement of the business, not of AGC, (it is sig- nificantly less, we might add, than would be required without the benefil of interconnected operation.) Rut, in fact, ihr cost of matching load with generation, when the matching is ac- complished by a well-designed AGC, can be much lower than when units are verbally controlled. Operating an increased number of units under a well-designed AGC realizes reduction in system production cost.

The first two paragraphs of Professor Glavitsch’s discussion which emphatically state the main messages of the paper are very much appreciated. We agree with him that, if R = 8, ACE would remain insensitive to external disturbances, but \{-e have not advocated adjustment of 13 in an attempt to obtaiii an “acceptable match.” Our words “acceptable match” were between generation trend and demand, not I? and 8. In line with the discusser, our message for normal operation is: “it is impractical and unnecessary to attempt a precise matrli of area generation with the trend of an area’s own load and losses, T,, and the area portion of lO,B(F, - F?).” The iriterconnrctioii

F

11%

will continue successful operation as long as these trends arc “acceptably matched.”

On the paper’s statement of “a quick return of eit her fre- quency or interchange to the schedule must not be used as a basis for advocating an AGC algorithm,” and in agrernieiit, with what can be inferred from the discusser’s comments, we mean that the interconnection is hurt if every area should at- tempt to quickly (or even slowly):

Return its interchange to the schedule with no consider- ation of system frequency. or

Return frequency to the schedule with no consideration of its interchange.

The very astute equations presented by Professor Glavitscli for analysis of a three area system support the previous point and complement the explanations in the paper on the subject. The AGC process has some characteristics which are intrinsic and some which are a manifestation of inaccuracies and un- avoidable imprecision. An attribute of Dr. Glavitscli’s equa- tions is that all error effects, offsets, etc. (of which there are many in the AGC process) are constrained to the right Iiand side while everything on the left hand side is exact.

From the left hand side of the equations, Dr. Clavitsch made the observation that a t least one area must do frequency control. It can be noted too, that “flat” frequency control can be done in one area, but not more than one. By the cun- ning construction of Professor Glavitsch’s equations these ob- servations can be seen to be intrinsic to the ACC process and independent of its inaccuracies.

Considering collective AGC action in the interconiircf ion . we may add:

C A C E = -1OB,(F,, - F%) where

B, = B1 + BP -t B ~ l , and

Fa = ( B I F ~ I + + BJ’ , , ) /B , . Therefore, for stability, B , must be negative as wrll as non- zero. Clearly, if B , is positive, any deviation from F, will be amplified until the system collapses. Beyond this point how- ever, it is not sufficient that l?, be negative, because tlicre may be occasions when a number of areas are unable to match thrir obligations. For successful operation of the interconnection on such occasions, it is necessary for the sum of the L? in the set of remaining areas to be negative.

The first paragraph of Mr. Concordia’s discussion nicely helps to promote one o f t e main messages of our paper. We feel so strongly about th j that we want to reempliasize his point: “It ts obvtow th .t over-control of t i e - h e loading ES sally.’’ It is certainly not intended to discourage research in the AGC area. We have stated today’s practical limitatioiis and theoretical basis to help increase the usefulness of rrscarch efforts on this subject.

Mr. Kennedy’s observation concerning“NERC Guides” vcsr- sus “Guidelines” is correct, of-course, and we find his com- ments to be compatible with our views. Uy broadening tlie understanding of AGC, we hope this paper will inspire the continued evolution and development of tools and proccdiirrs to assist system operators, beyond tlie present level, so that improved system operation and control can be acli irvd. We believe that while an area is satisfying its obligation to the interconnection, even as measured by today’s NEHC Criteria,

the area can and should avoid following fast varying cornpo- nents of load. Such attempts are without benefit to the area or to the interconnection, and often can amplify ACE and in- crease the cost of wear and tear.

The belief stated above is also relevant to some aspects of Mr. Schulte’s comments, to which we would like to add the following. As far as response to fast varying compoiicnts of load is concerned, the typical frequency trend in tbe Eastein Interconnection indicates that the present level of AGC regitla- tion is satisfactory. To continue this level of performance, the generation adjustment capability, as related to the rat r ol load change during pick-up and drop-off, must be maintained near its existing level. Relative to the “ACE control performance threshold” point of the discusser, in our opinion, no energy conversion device of short h c d output will be necessary in f h e AGC domain, notwithstanding potential applications of such devices for suppression of undesirable transients in a fnturr, but as yet undefined and unconventional manner.

When ACE, in compliancr with performance criteria, frr- quently crosses zero and has a small average, it essentially mea- sures fast area load dynamics that ought iiot be a concern of AGC, and acceptable control does not require any reaction to them. The present performance criteria for normal conditions have a ten minute time scale. While AGC should adjust area generation to yield an acceptable ACE trend, it should not at- tempt to react to components of load whose oscillation periods are comparable to area generation response time. Attempting to react to such components does not produce an iniprovcd ACE trend and requires unnecessary nianeuveriIig of units.

In line with Mr. Taylor’s comments, we believe in utiliza- tion of AGC for enhancing any aspect of area operation lwfor- mance, including voltage stability, when it can be accomplished by adjusting unit generation within the constraints of their as-

sociated characteristics. AGC data captiiring and plotting p~<’- grams developed at AEP (171 have provided the opportunity of

observing the response of about sixty major AEP units to small and large (60 mHz) frequency upsets. The measured frequency in these plots is the one second average of local frequellcy, atid the measured unit power output is observed through an rxpo- nential filter having a time constant of -3 seconds. Presented below is a summary of these observations.

While many units present a discernible response to frr- quency upsets exceeding 40 mHz, only a few respond wlien the upset is -15 mHz. Wherever “dead-band” is referenced in the paper or closure, it indicates the effective dead band in the governor loop. Inspection of the frequency trend and the power output of units, even for tlie latter few units, lias shown no correlation when upsets are below -10 mlL . Since AEP’s primary generation response to frequency upsets, espr- cially those exceeding -25 m h , is very close to that of tliv Eastern Interconnection on a per hIW basis, units with govrr- nor dead-bands less than 10 to 15 mHz appear to be rare.

We believe tlie state of governor control in the Eastern In- terconnection is adequate for non-islanding scenarios. (Tlir largest frequency upset in recent years has been less than 100 mHZ.) While we do not advocate tlie introduction of intert- tional dead-band in governors, we feel it would be cliflicult to justify any large expenditure for reducing dead-baricls brlow the existing level. This assumes that the percentage of units with smaller dead-bands would be maintained near the present ratio.

As mentioned in the paper, ACC shoulcl not i i n r l i i l , ~ com-

1121

promise an area’s primary response. This does not inean t h a t B has to nearly equal p. There are many other reasons for oscillations, including the nature of load in many arras. that substantially limits perceived benefits from setting 13 = @.

Professor Keyhani’s concept of matching energy demand with minimum unit maneuvering is commendable. Ile presents a model for obtaining a solutioii that attempts to control uiiits with this objective. This model requires a forecast of future load Pj and could be enhanced to iiiclude minimization or fucl cost over the forecast period T. Characteristics of units and loads in many areas, however, substantially limit the usefulness of the proposed algorithm.

Many units can fully realize a requested generation change within one minute after AGC has stopped ramping tlieni at the allowed rate and essentially all units will have complclrd this task within two minutes. To realize the full bciiefit of a n extended boiler model, the period T should therefore be about two minutes. Although load can satisfactorily be forrcastetl for the next hour, methods to reliably forecast the load for the next minute or two are not available, and may be infeasible in our opinion.

If T is taken to be several minutes, allowing flie forecasled load Pj to be more reliable, then a detailed prediction of R I L

output power trajectory of each unit over horizons of up to two minutes does not play a significant role. Despite these consid erations, some areas have implemented ideas along the lilies suggested by the discusser. AEP uses a 90 second anlicipa- tion of interchange schedule changes and initiates generation maneuvering to avoid ACE. Some areas also use a vrry simple model to compute what power change is yet to be aiiticipaietl from a unit if the ramping were to be stopped at the presciit cycle.

We would like to offer the following comriicrits on Ihe first and fourth remark from Messrs. Hhatti, Kotliari, aiid Satish and on the first remark from Messrs. Nanda. Kothari, llari, and Bhise.

Under normal conditions, the US Eastern Interconnection frequency rarely experiences a sudden deviation of more t tian 20 mHz from its one or two minute average. Even for the upper range of such deviations, only a small number of units partic- ipate in arresting frequency excursions. Since the majority of generating unit governors apparently remain in dead-baud, it appears governors have a minimal influenrr on operation under normal conditions in this large interconiiectiou. Conse- quently, supplementary control (wlidher providcd inaiiually 01 by AGC) and the performance resulting from it undei iiornial conditions, is not sensitive to the droop of governors. Such droop only comes into consideration when a sudden deviation from prevailing frequency takes a substantial number of gover- nors out of dead-band.

For such interconnections, governors (and their droops) bc- come of great importance when units find themselves in an island. For an island to be able to continue its operation, it initidly must arrive at a stable frequency. For this, tlie com- bined contribution of governors, components of load sensitive to frequency, and (when necessary) load slieddiiig or ovrrspretl tripping have to overcome the initial power mismatch in tlic island.

The ratio of the maximum probable mismatch or r r thc sine of the island (or interconnection when islanding is not of coii- cern,) the sensitivity of the island load to frequency dcvia tioii, and the available automatic load shedding are among {hose

’

parameters that affect selection of governor droops in order 10 arrest the frequency at acceptable level. AGC is a slow antl deliberate process relative to governor action. I’ropcr tlrsigu of AGC parameters prevents interaction hctween AGC aiid gor- ernor response. Due to limited rate and range of control, AGC of the disturbed area takes minutes to return ACE to zero. Tlir governor droops only affect the level at which tlie frequency is initially arrested. These droops have no significaiit effect on how the interconnection frequency returns from its post u p w t level to the scheduled value.

This paragraph responds to the third renlark from hlrssrs. Bhatti, Kothari, and Satish. The ACE signal is computed aiitl

plotted in most control areas. In many of them the coordinator can even monitor it on his CRT. Most of the AGC algorithms in service, use a processed ACE to decide if generation nrrtl be changed and by how much at each AGC cycle. Tlicsr pro- cesses normally filter out fast varying components of ACE antl, hence, to some extent prevent AGC froiii responding to rail-

dom changes in the load.

The following three bullets respond to the second to fourth comments from Messrs. Nanda, Kothari, Hari, and Hhisr.

In many areas, the upper limit of the spectrum of collrc- tive achievable unit response is roughly 0.015 Hz, correspond- ing to about 60 seconds/cycle. With such generation response characteristics, it would not only be futile, but corinterpro- ductive to attempt to follow load fluctuation components with periods shorter than 60 seconds.

AGC must be on the constant look-out for disturbance con- ditions which normally require operator alert or emergelicy ac- tion. This requirement must also be considered in the selection of the data acquisition sampling rate and generation response immediately after the occurrence of a disturbance in the area. The NERC B2 criterion somewhat addresses this issiie by re- quiring response within one minute.

Characteristics of the necessary analog filters in a data ac- quisition system must also he compatible with the coiitrol ry- cle. The output signal from any such filters should at least l)e sampled at the rate of 1/4th the period of the highest frequency component present in the signal. Conversely, if the sampling cycle is chosen, say 2 seconds, one has to make sure that all fre- quencies beyond 1/8 Hz are removed by analog filters in order to avoid aliasing.

Many areas use an integral term of ACE in tlicir AGC algorithms. Fortunately, their algorithms bencfit from some sophistication that limits or disregards the integral term whcrt- ever its use may potentially deteriorate AGC performance. Any significant power mismatch in the interconnection is vcry undesirable. Adverse impact of such a power mismalch by an integral of ACE offset should be avoided.

No algorithm can guarantee zero inadvertent and time er- ror. There are many periods over which an area or several areas are unable, for whatever reason including unknown erlor and mistakes, to match their generation with their obligal ion. During such periods, frequency may stay off schedule. TO s t o p further degradation of frequency, other areas are requzrrd to provide their share of system frequency support. For this, thcy accumulate inadvertent.

Unilateral inadvertent payback with a limited rate is al- lowed by NERC when it helps iiiterconnrction perforrnaiicc. Many areas repay their inadvertent unilaterally if it liclps to reduce time error and if the frequency is within a proper range.

1122

0 The ACE level acceptable by the current NERC Guidt-s, is stated in the last paragraph under “ACCEPTABLE ACE TREND” of the paper. The NERC definition of an acccptable ACE trend may, however, be changed in the future.

As Messrs. Ponder and Cucchi are aware, NERC is present- ly considering other proposals for measuring contrrd 11rrh- mance. Some of the Task Force members are involved in t liis rf- fort and hope to soon publish suggestions. Improvetl intercon- nection reliability and economic equity as well as increased in - terconnected operation benefits to member areas are the basrs of proposals being examined.

Messrs. Ponder and Cucchi state that coordinated unit con- trols could result “in less aggressive initial governor and AGC response from a unit.” We do agree that response of such units to changes in target MW (via AGC or hand-auto control) arc delayed by several tens of seconds for coordination with atl- justments of air, fuel, etc. We do not believe delays of such durations are significant to the function of AGC.

Coordinated unit controls do not necessarily introduce a time delay for aggressive and immediate governor response. However, to avoid a follow up compromise of the initial gover- nor response in such units, a boiler-loop bias logic should SCIW

off-nominal frequency and allow a sustained net RI\V (droop like) deviation from target value.[7] If AGC survives, o r is rc- turned to service after an upset, it will subsequently Iradjust unit output, regardless of any offset from target due to a boilrr loop bias, so as to satisfy interchange, frequency and economic objectives.

The discussers mention the Tokyo voltage collapse. Cer- tainly the stabilizing effect of load sensitivity to frequency will be compromised if modern load controls, such as those involvrtl in the Tokyo incident, become extensively utilized. This is an issue of primary control and not that of AGC; one line of defense could involve larger governor response, if a n d when the existing aggregate load-frequency characteristics slioulti be- come drastically changed.

AGC is automatic generatton control. It changes genera- tion by adjusting the output of each unit. Within the con- straints of unit response delay and other characteristics. we encourage any AGC strategy that can enhance any nsprr t of operation performance. This includes, as statrtl in i lw paprr. the strategy that operates the system with a bettrr security margin. Under this umbrella, are considerations of trarisfcr interface limits and coordination with relay schemes.

The discussers refer to a jointly shared reserve proccdiire of MAAC and NPCC. We understand this as a scheme of in- voking an interchange transaction to split the ACE of a largc disturbance between areas, getting them both into a sensed dis- turbance state so that more units are available for emiw?prg action. We wonder which portion of the paper has given tllc discussers the impression that such a scheiiie could he undr- sirable, indeed it may be a means of realizing further economy of interconnected operation. It may also be a consitleratiou, if implemented automatically, for an area having a problem situation, such as that described by Dr. Enus.

We don’t believe taking units off AGC is the proper re- sponse to the performance criteria compliance problrnl cited by Dr. Enns. An area with this problem should, ntost impor- tantly, control to meet its short term (less than an hour) area energy demand. The more units on control, the less actioii needed from any one of them for good area performance. It may be worthwhile to consider telemetry from some customers that could provide an anticipatory signal of load change to use in AGC.

On the comments of Messrs. Thompson and h4amandur: we would like to include remarks from Mr. R. A. Bulley, Man- ager of Power System Supply, Commonwealth Edison Con- pany. All of Commonwealth Edison’s nuclear units, both BM‘H and PWR, are equipped for AGC regulation and they have u p to five years operating experience with some of them. Unit re- sponse rates are up to 0.5% per minute. Depending on system conditions, most on-line nuclear units may be operated in a regulating mode.

There are various ways of implementing sliding pressure operation for generating units. These result in corresponcl- ingly various unit regulating capabilities, some of nliicli may be rather minimal as the discussers suggest. AEP has iinple- mented a hybrid sliding pressure mode 011 some of its supercrit- ical units and could maintain a turbine control valve reserve for AGC action. This has not been found necessary as control obtained via the pressure control valve has been adequate.

The discussers also ask about including “integrated A C T ” as an area control error compoIient. integrated ACE includes both an inadvertent component and a time error component. Over a term of days, energy metering provides an inadvrrteiit accumulation to be controlled within bounds. Heduring the time scale to hours, one must be concerned with energy audit- ing uncertainty. Use of integrated ACE is simply shortening the time scale still further. But, if done judiciously, we believe this can be beneficial. One can think of the current inad\rrtent as having three components: 1. The audited value, norniallj- as of midnight yesterday, 2.The sum of the hourly valtirs since midnight (from energy metering if available), a d 3. The inte- gral of the tie-line component of ACE since hourly data was last obtained. Separate accounts must be maintained for on- peak and off-peak periods. Depending on one’s confidence iii

the accuracy of these three components their weiglited s i~ i i i

could be an estimate of the up-to-the minute inadrertrnt. A unilateral inadvertent correction might be invoked, following NERC rules, of course, and including proper consideration o f any change in time error.

In conclusion we would like again to tliank all the discussers for the time and effort they have contributed. Tlieir questions and interest have added clarification to many of the points of the paper and have improved its qualtity and usefull~~ess as a reference for AGC practice axid development.

Manuscript received A p r i l 5, 1991.

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