Lecture 44 45 AGC 1 and 2

7/16/2019 Lecture 44 45 AGC 1 and 2

http://slidepdf.com/reader/full/lecture-44-45-agc-1-and-2 1/12

1

Lecture 44 and 45

AUTOMATIC GENERATION CONTROL

1.0 INTRODUCTION

Maintaining power system frequency at constant value is very important for the health of the power generating equipment and the utilization equipment at the customer end. The

job of automatic frequency regulation is achieved by governing systems of individual

turbine-generators and Automatic Generation Control (AGC) or Load frequency control( LFC) system of the power system.

2.0 FREQUENCY VARIATION IN A SINGLE MACHINE

To understand the variation of frequency in a power system, we can consider a singlemachine connected to an isolated load, as shown in the figure below.

Fig.1 SINGLE TURBINE GENERATOR WITH LOAD

Normally, the turbine mechanical power (Pm) and the electrical load power (Pl) are

equal. Whenever there is a change in load, with mechanical power remaining the same

the speed (ω) of the turbine generator changes as decided by the rotating inertia (M) of the rotor system, as given by the following differential equation..

Pm-Pl = M [d ω/dt ]

The governing system senses this change in speed and adjusts steam control valve so

that mechanical power (Pm) matches with the changed load (Pl). Speed variation stops but at a different steady value. The change in frequency (Δω) at steady state can be

described using the following equation in terms of change in load (Δ Pl) and a factor R called ‘speed regulation or ‘droop’.

Δω = - [Δ Pl ]( R)

A 20 % change in load (Δ Pl = 0.2 per unit) causes 1 % change in frequency (Δω = 0.01 p.u) with a per unit (p.u) droop value of 0.05. Similarly full load throw off (Δ Pl = - 1.0)

Pm

PlTurbine Gen

7/16/2019 Lecture 44 45 AGC 1 and 2


2

causes 5 % change in speed. (Δω = + 0.05). This is described by the well known droop

characteristic.

3.0 NEED FOR SUPPLEMENTARY CONTROL

Now when there is a load change, speed settles down after a transient period at a value

different from the original steady speed. This new speed value is dictated by the droop

value. For instance a 100 % load rejection will cause the machine speed to settle down at105 % speed, with a droop value of 5 %, as shown in the figure below. During the

transient, speed may touch a higher value as shown in the figure (by TSR: transient speed

rise). The speed however has to be brought back to the original value for which speed/load reference (Pref) has to be adjusted either by the operator or by a supplementary

control system.

In the speed control system block diagram shown in Fig. 4, when elec. load changes,

reference set point is to be adjusted to restore speed to the pre-disturbed value. This is

equivalent to shifting the speed droop characteristic to match the new operating load asshown in Fig. 5.

Load

100%

Time sec

t

100%0%

Speed (%)

TSR

(6 - 10%)

5% Droop

Fig 3 LOAD REJECTION RESPONSE

Frequency

(Hz)

50

5% Droop

Load 0% 50% 100%

Fig.2 SPEED REGULATION CHARACTERISTIC

7/16/2019 Lecture 44 45 AGC 1 and 2


3

4.0 AUTOMATIC GENERATION CONTROL (AGC)

Automatic Generation Control (AGC) usually implemented in Energy Managementsystem (EMS) of Energy Control centers (ECC) consists of

Load frequency control

Economic Dispatch

Interchange scheduling

In this section Load frequency control is described.

LOAD FREQUENCY CONTROL

The speed/ frequency variation concept can be extended from a single turbine- generator

system to a power system comprising several turbine- generators as shown in Fig.6. Now

the mismatch between the total power generated and the total electrical load causes thefrequency change as dictated by the combined system inertia. The governors of all the

Frequency

(Hz)

50

Load 0% 50% 100%

Fig.5 SHIFTING OF SPEED REGULATION

CHARACTERISTIC

SPE

E

DValvePosition

Pref SET

-Mechanical

Power

GOVERNOR TURBINE ROTOR

INERTIA

Fig 4 GOVERNING SYSTEM FUNCTIONAL BLOCK DIAGRAM

Elec.load

Operating point

shifted to 50 %

7/16/2019 Lecture 44 45 AGC 1 and 2


4

machines sense the frequency and the mechanical power outputs will be changed

automatically to match the combined generation with the new combined load. This actionis called primary regulation.

But frequency remains at a new value and set points must be adjusted, just as in single

machine case for frequency restoration. This job is done by the Automatic Load Frequency controller (ALFC) as shown in Fig. 7. This process of set point adjustment is

called secondary regulation.

When load change occurs frequency varies and the regulation initially for the first few

seconds is due to the action of the governors of all generating units and subsequently the

Load frequency control system prevails.

5.0 POWER SYSTEM FREQUENCY CONTROL :INDIAN SCENARIO

In India, the power system is divided into regions. Load Despatch Center in each regionmonitors the frequency by interacting with State Load Despatch Centers and generating

Pref

-Combined Mechanical

Power

Composite

Governor Composite

Turbine

Power System

Inertia

Fig 6 BLOCK DIAGRAM SHOWING POWER SYSTEM FREQUENCY VARIATION

Total Elec.

load

Fre uenc

Set point

○

Generator

Power

Frequency

Total Generation

Total

Load

Primary regulation

Other m/c

To

Other

Machines

Set point Area

Freq-

uency

Secondary regulation

-

-

○

○

○

AUTOMATIC

LOAD REQUENCY

CONTROLLER

Governor Turbine

GRID

INERTIA

Fig 7 AUTOMATIC LOAD RFEQUENCY CONTROL SYSTEM

7/16/2019 Lecture 44 45 AGC 1 and 2


5

stations under the control of States and the generating companies like NTPC, NHPC. The

Regional Load Despatch Centers (RLDC) function under Power Grid Corporation of India. So, for the purpose of frequency each region can be considered as one coherent

unit. For instance Southern RLDC comprises AP, TN, Karnataka, Kerala and Goa.

SRLDC is located in Bangalore.

For the load frequency control, the generating units at Hydro power plant are normally

adjusted as the response is faster to raise/lower the power. Thermal power plants have

‘rate’ limitations due to thermal stresses. But all units are expected to participate in primary regulation.

Load – Generation imbalance causes frequency variation. Load is never constant. Precisefrequency control is possible only if there is a surplus generating capacity, which is not

the case in many states. Hence load shedding is resorted to for frequency management.

There is no AUTOMATIC load frequency control in many regions as many utilities want

to generate to the maximum possible extent and would not like their generation levelsadjusted by ALFC. Mostly manual control is only exercised to maintain frequency.

In many cases, generators are not allowed to participate in primary regulation also i.e.,

the natural tendency of the governors to raise/ lower generation when frequency falls/

rises is suppressed. With the result, frequency is always less than the rated value of 50Hz. When sudden disturbances occur, system collapses causing blackouts. The situation

has vastly improved in the recent years after the introduction of availability cased tariff

(ABT) and free governor mode of operation (FGMO) regimes.

6.0 FREE GOVERNOR MODE OF OPERATION (FGMO)

To maintain grid discipline, all generating units shall have their governors in free

operation (natural governing ) at all times.

In Indian grid code the following specifications are given.

The rated System frequency is 50 Hz and the target range for control should be 49.0 Hz – 50.0 Hz the statutory acceptable limits are 48.5 - 51.5Hz.

Each operating machine should pick up load as below:Up to MCR: 5% extra load for at least 5 minutes.

Above MCR :105 % of MCR

Facility available like load limiters, ATRS etc, shall not be used to suppressnatural governor action in any manner

All governors shall have a droop of between 3% and 6%.

No dead band or time delays should be deliberately introduced

Each Generating Unit shall be capable of instantaneously increasing output by 5%when the frequency falls, limited to 105% MCR.

7/16/2019 Lecture 44 45 AGC 1 and 2


6

Ramping back to the previous MW level (in case the increased output level cannot be sustained) shall not be faster than 1% per minute.

At 49 Hz, all constituents shall resort to adequate manual load shedding instantly,

Operating frequency should not touch such level, which may trigger Under Frequency Relay (UFR) operation; as UFR actuated shedding is meant only for

taking care of contingencies like sudden losses of bulk generation etc. The recommended rate for changing the governor setting, i.e., supplementary

control for increasing or decreasing the output (generation level) for all generating

units, irrespective of their type and size, would be one (1.0) per cent per minute or

as per manufacturer’s limits.

However, if frequency falls below 49.5 Hz, all partly loaded generating units shall

pick up additional load at a faster rate, according to their capability.

Implementation of FGMO in power plant

In a typical 200 MW/ 250 MW thermal power plant, implementation scheme isshown in the figure below.

LOAD

CORRECTION OF

+/-APPOX 2.5 MW

FOR +/- 1 KG/CM2

TURB MAX

LOAD LIMIT.

(220 MW)

BOILER FUEL

CONTROL.

CORRECTION

DUE TO PR.

VARIATIONS

MIN

TURBINE

CONTROL.

DEAD TIME (2.5 MINUTES)

SCHEME OF FGMO.

FGMO WORKS WITHIN THE LOAD SET PT

LIMITS OF 175 MW TO 220 MW ONLY

CMC LOAD ST. PT.

LOAD CORRECTION

DUE TO FREQ. +/- 20 MW

MIN.

CMC MAX LOAD

LIMIT. ( 220 MW)

LOAD SET POINT.

Fig 8 IMPLEMENTATION OF FGMO IN A TYPICAL 210 MW PLANT

The Coordinated Master Control ( CMC) scheme gives commands to the turbinecontrol as well as the boiler fuel control to raise/lower generation. When frequency

changes these command signals are modified with a limit of plus or minus 20MW as

shown below in Fig.9.

7/16/2019 Lecture 44 45 AGC 1 and 2


7

In case CMC is not there FGMO can be implemented in the Load control loop of theelectro hydraulic turbine controller (EHTC).

Fig.9

7.0 AUTOMATIC GENERATION CONTROL : DESIGN AND IMPLEMENTATION ASPECTS

The objective of the AGC in an interconnected power system is to maintain the frequency of each area

and to keep tie-line power close to the scheduled values by adjusting the MW outputs the AGC generators

so as to accommodate fluctuating load demands.

The components of AGC in the modern power system are:

Load-frequency control (LFC) Economic dispatch (ED)

Interchange scheduling (IS)

When frequency changes, under primary regulation, governors respond immediately. But as mentioned

earlier, frequency does not get restored but will settle down at a different value. At this point of time LFC

function comes in to the picture.LFC maintains the system frequency by performing the function of Secondary Regulation. It provides generation set points to the generators participating in the frequency

regulation. But these set points may not be the optimum from cost point of view. Economic dispatch (ED)

function readjusts the set points of the generations after the time scale of LFC.

In a large interconnected power system there are a number of areas connected by tie lines with share

agreements with neighbors. The LFC and ED functions have to take care of these agreements. This

function is performed by Interchange Scheduling (IS).. Each of these areas is responsible for generatingenough power to meet its own customers or "native load." By keeping the generated power equal to the

power consumed by the load, utilities keep the overall system frequency at 50 Hz. Not only must areas

adjust their generation to meet their own changing native load, but they must also maintain anyscheduled tie-line transactions. It is possible, by monitoring both the tie-line flow and the system frequency

to determine the proper generation action (raise or lower). Thus, electric utilities use an automatic

generation control (AGC) system to balance their moment-to-moment electrical generation to load

within a given control area.

+20 MW

- 20 MW

50 51 Hz 52 Hz48Hz 49Hz

LOAD CORRECTION WITHOUT DEAD BAND

7/16/2019 Lecture 44 45 AGC 1 and 2


8

The current practice of the load frequency control (LFC) function of automatic generation control (AGC) is

based on a strategy known as tie-line bias control. In this control strategy each area of an interconnected

system tries to regulate its area control error (ACE) to zero, where:

The term (T,-T, ) is the difference between the actual and the schleduled net interchange on the tie lines.

The term representing the area's natural response to frequency deviations is lOp(f,-f,). The coefficient, p, isknown as the system natural response coefficient. It is difficult to obtain an accurate value of p since itdepends on the governor reslponse capability of the generating units presently on-line and the frequency

dependence of the constantly changing load. This characteristic is expressed as:

where, (1/R) is the generator regulation or droop, D is the load damping Characteristic.

Figure 10: AREA CONTROL ERROR WITH FREQUENCY

Area Control Error (ACE)

ACE = Δ Net Interchange + β Δ f

Δ Net Interchange = Interchange error = Scheduled – ActualΔ f = Δ ω = frequency deviationβ = frequency bias ( pu MW/ pu frequency)

Basic Idea in AGC design is that when :ACE> 0 generation decreased and ACE<0 generation is

increased.

As long as one frequency bias β≠0, if all areas have ACE=0: then Δω = 0 and all Δ Net Interchange =0

Driving ACE to zero restores frequency and interchange

LFC Implementation:

Ideally ΔPrefi = -ACEi

7/16/2019 Lecture 44 45 AGC 1 and 2


9

More practically it is necessary to use integral control ( or Proportional integral control)

ΔPrefi = - Ki ∫ ACEi dt

Note in steady state ΔPrefi must become constant and ACEi=0. Then necessarily Prefi=ΔPli.

Integral control with stable gain Ki guarantees zero error.

Load Frequency ControlLFC Implementation

FrequencyMeasuredAt a centralLocation Tie line flows(MW)

DesiredFrequency

Net Interchange

ACE

Filters K ∫ Allocation To Plants

Other Considerations

∆Pref To Units

Economic Dispatch SeverityActual Unit Movement Unit Energy BalanceMinimum Movement Response Rate Time error

~every 4 sec

~every 4 sec

Fig 11 LOAD FREQUENCY CONTROL SCHEME

In the modern Energy Management Systems (EMS) automatic load frequency control

system (ALFC) is part of Automatic Generation Control (AGC).

In power systems, where automatic control does not exist, manual control of set points is

done on instructions from dispatch center.

In this response curve taken from published literature, a loss of generation has resulted in

a frequency fall from 60.01 Hz to 59.209 Hz and due to governor actions (primaryregulation), frequency starts increasing and it should have settled around 59.75 Hz as

shown

7/16/2019 Lecture 44 45 AGC 1 and 2


10

below.

Fig. 12 Typical frequency response of a 60-Hz power system with AutomaticGeneration Control (AGC) for a step load increase

But Automatic Generation Control (AGC) system which includes Load Frequency

Control (LFC) acts on the set points of the governors and frequency gets restored to the

60 Hz value as shown in the response curve (Fig. 12).

For a similar system, measured frequency variation when large generation is lost is

shown in Fig. 13.

Fig. 13 Typical frequency response of a 60-Hz power system with Automatic

Generation Control (AGC) for a generation loss

7/16/2019 Lecture 44 45 AGC 1 and 2


11

The AGC implemented in developed countries includes load frequency control (LFC),

economic dispatch (ED) and interchange scheduling (IS). These are implemented asapplication programs in Energy Management System (EMS) software located in Energy

Control Centers. (ECC).

The implementation scheme for AGC is shown in Fig. 14 .The AGC function withinSCADA/EMS will receive frequency, generations (MW) etc., signals through remote

terminal units (RTUs).

Fig. 14 Typical implementation schemeof Automatic Generation Control (AGC)

When there is a frequency change primary control action is performed by the governors

of prime movers. After few seconds Secondary Control function by Automatic generationcontroller (AGC) is initiated. AGC computes the set point changes required to restore the

frequency to the set value and issues commands to participating generating units.

8.0 CONCLUSIONS

The basic concepts of power system load frequency control system are described in this

article. In the literature, it is also referred to as Automatic Generation Control (AGC)where apart from load frequency control, economic allocation is also included. The

Energy

Management

System(EMS)

-AutomaticGeneration

Control (AGC)

ElectroHydraulic

Governor

(EHG)

Electro

HydraulicGovernor

(EHG)

Electro

HydraulicGovernor

(EHG)

Electro

HydraulicGovernor

(EHG)

Turbine-

Generator

(TG)

Turbine-

Generator

(TG)

Turbine-Generator

(TG)

Turbine-

Generator

(TG)

Set Point

Set Point

Set Point

Set Point

Frequency

(f)

f

f

f

SYSTEM CONTROL

CENTER (SCC)

HYDRO POWER PLANTS

Telemetry

------

Generation Signals

(MW)

System Frequency

7/16/2019 Lecture 44 45 AGC 1 and 2


12

computer based Energy Management System (EMS) installed in modern power systems

includes AGC also.

The concepts of Free governor mode of operation (FGMO) and implementation are also

described.

9.0 REFERENCES

1. Frequency Control Concerns In The North American Electric Power SystemDecember 2002 by B. J. Kirby, J. Dyer, C. Martinez, Dr. Rahmat A. Shoureshi

R. Guttromson, J. Dagle, December 2002, ORNL Consortium for Electric Reliability

Technology Solutions

2. N. Jaleeli, D.N. Ewart, and L.H. Fink, “Understanding Automatic Generation Control,

“IEEE Transactions on Power System, Vol. 7, No. 3 August 1992, pp. 1106- 1122.

3. A.J. Wood and B.F. Wollenberg, Power Generation, Operation, & Control, JohnWiley & Sons, 1984.

4. R.L. King and R. Luck, “Intelligent Control Concepts for Automatic Generation

Control of Power Systems,” NSF Annual Report ECS-92-16549, March 31, 1995.

5. P. Kundur, Power System Stability and Control, The EPRI Power System Engineering

Series, McGraw-Hill, 1994

6. C. Concordia, F. P. deMello, L.K. Kirchmayer and R. P. Schulz, "Effect of Prime-

Mover Response and Governing Characteristics on System Dynamic Performance,"American Power Conference, 1966, Vol. 28, pp. 1074-85, IEEE transactions on Power

Systems, Vol. XX, 1999

7. Dynamic Analysis of Generation Control Performance Standards Tetsuo Sasaki,Kazuhiro Enomoto

8. Nasser Jaleeli, Louis S. VanSlyck: “NERC’S NEW CONTROL PERFORMANCESTANDARDS”, IEEE Trans. on Power Systems,Vol.14,No.3,pp.1092-1099,1999

9. North American Electric Reliability Council, NERC Operating Manual, Policy 10,

available at ⟨http://www.nerc.com.

Lecture 44 45 AGC 1 and 2

Documents

Transcript of Lecture 44 45 AGC 1 and 2