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Syed Hamza Kazmi

GTE – ElectricalBatch 11

FINAL PRESENTATION

Syed Hamza Kazmi (GTE) 1

Presentation Geography - Comprehensive


Technical Overview

• Generators (Operating Modes & Control Mechanism)

Annual Progress Review

• Highlights• Technical Initiatives• Extracurricular Initiatives

Generators Operating Modes & Control Mechanisms


PRIME MOVER GENERATOR

GOVERNOR AVR

Generator Control Mechanisms

There are two types of controls associated with a generator:a) Governor (controls the MW and frequency)b) AVR (controls the MVAr and Terminal Voltage)


Mechanical Power Electrical Power

Presentation Geography

• In the next 25 minutes we shall go through the following:

Operating Schemes

• Islanded Operating Scheme• Parallel Operating Scheme

Governor Control

• Droop Mode• Isochronous Mode• Case Studies (Practical Considerations)

Excitation Control

• Fundamentals & Types• Capability Diagrams & V-Curves• Case Studies (Practical Considerations)


GENERATOR OPERATING SCHEMESBrief description of control modes


Generator Operating Schemes

A number of Operating Schemes are employed worldwide. Considering FFL’s system, today’s discussion will deal with following schemes only:• Islanded operation with one generator• Islanded operation with multiple generators (parallel)


GTG A GTG BGTG A


Operating Schemes Islanded Operation with Single GTG

Islanded Operation (Single GTG)

When operating in isolation, an increase in load will have two effects:– Speed (frequency) will initially fall. The speed reduction is detected by the

governor, which opens the prime mover fuel valve by the required amount to maintain the required speed (frequency).

– Voltage will initially fall. The voltage reduction is detected by the AVR which increases the excitation by an amount required to maintain output voltage.



Operating Schemes Islanded Operation with Multiple Sources

Parallel Operation

• When a machine operates in parallel with a power system, the voltage and frequency will be fixed mainly by the system. – The fuel supply to the prime mover determines the Power which is supplied

by the generator and this is controlled by the governor. – The generator excitation determines the internal emf of the machine and

therefore affects the power factor when the terminal voltage is fixed by the power system.


Points to Remember

In single and parallel operation it is important to realize that PRIME MOVER Active Power (by varying Fuel Supply)EXCITATION Voltage (Islanded Operation) &

Voltage + Power Factor or Q of Machine (Parallel Operation)


GOVERNOR CONTROLModes of Operation, Case Studies and Practical Examples


Governor Operating Modes

Governor Operation Modes

Isochronous Mode Droop Mode Base load Mode

Governor Droop Mode


Droop Mode - Introduction

What does a droop of 3, 4 or 5% indicate ?


The percentage of frequency change required to move a unit from no-load to full load is called Percentage Droop

Droop Mode - Explanation

In this graph both the frequency (f) and Power (P) are plotted relatively (i.e. in terms of relative ratios)

• Vertical axis represents

f / fo

• Horizontal axis represents

P / Po

Hence the final formula for droop becomes:

0.9 o

%

- Δf / fo

ΔP / Po


Droop Mode – Explanation (Contd…)

• Droop of 4 % :– A change in 25% of the rated load of the machine results in a change of 1% in

its rated speed (Frequency)– A change in 100% of the rated load of the machine results in a change of 4%

in its rated speed (Frequency)– A 4 % change in frequency, means

• 50 Hz x 0.04 = 2 Hz or for a 4 pole generator, 1500 rpm x 0.04 = 60 rpm.

50 Hz

f [%]

60 rpm, 2Hz or 4%

P [%]100%


Droop Mode – Explanation (Contd…)

• Droop of 5 % :– A change in 20% of the rated load of the machine results in a change of 1% in

its rated speed (Frequency)– A change in 100% of the rated load of the machine results in a change of 5%

in its rated speed (Frequency)– A 5 % change in frequency, means

• 50 Hz x 0.05 = 2.5 Hz or for a 4 pole generator, 1500 rpm x 0.05 = 75 rpm.

50 Hz

f [%]

75 rpm, 2.5Hz or 5%

P [%]100%


Droop Mode – Case Study

8000 MW 50 Hz

G1max 50 MW

G2max 50 MW

G3max 50 MW

For our case study, let us consider a grid whose total generating capacity is 8000 MW rated at 50 Hz

An IPP, having three generators of 50 MW each, is synchronized with the grid and are supplying 37 MW each initially

All the 3 generators are operating at droop mode with a droop setting of 4%

Each of the 3 generators will take up 50 / 8000 i.e. 0.625% of any load demand changes that may occur on the grid

For this context, let a load of 5MW be added to the grid.

Lets examine what happens next…

5 MW

37MW 37MW 37MW


4%4%

f [%]

P [%]100%

RAISE LOWERRAISE

Droop Mode – Case Study

G1max 50 MW

8000 MW 50 Hz

50 Hz

For any demand load, each generator must increase 50 MW / 8000 MW = 0.625% = 0.00625 of that demand

For 5 MW increase in demandG1 = 0.00625 x 5 MW = 0.03125 MW 37.03125 MWG2 = 0.00625 x (5- 0.03125) MW = 0.03105 MW 37.03105

MWG3 = 0.00625 x (5- 0.03125- 0.03105) MW = 0.03086 MW

37.03086 MW

G2max 50 MW

G3max 50 MW

37 MW

37 MW

37 MW

What happens to frequency ?50 Hz - (0.04 x 50 Hz x 5 MW / 8000 MW) =

49.9987 Hz

How? Lets revisit the formula we just studied

5 MW

OPERATOR


Governor Isochronous Mode


Isochronous Mode - Explanation

• In this mode, the speed of governor (also frequency) remains constant regardless of any change in the load.

• Also called Frequency Control Mode or Swing Generator Mode

A system running in Islanded Scheme is required to run at least one of its Generators on Isochronous mode


f [Hz]

P [%]100%50%

RAISE LOWER

SP Regulator

RAISE

Isochronous Mode – Case Study

Referring to previous case, with one of the three generators being operated in Isoch mode


Isoch & Droop Modes - Control principle

A generator that can be operated in both Isoch and droop modes necessarily incorporates a feedback control system

Take a look at these 3 abbreviations first:

DSP: Digital Set Point (for speed of governor)AS: Actual Speed (of governor)VCE: Velocity Control Error

where, VCE= AS – DSP(difference b/w Actual and Set speed of governor)

Shaft RotatesTurbine Fuel Adjust

DSP VCE

Governor

Gear Box &

Alternator

Optical or MP EncoderAS



For Isoch Control, the control system is mechanized as:

DSP: Digital Set Point AS: Actual Speed VCE: Velocity Control Error

The circle represents an amplifier

It amplifies the ‘Error’ (VCE = AS – DSP) and sends it to the governor speed controller

Greater the ‘Error’, Greater the ‘change in speed of governor’

Hence, AS recurs to DSP Syed Hamza Kazmi (GTE) 26


For Droop Control, the control system is mechanized as

In this case, the VCE is fed back to amplifier’s input as Δ VCE

This addition of Δ VCE compensates for the difference b/w AS and DSP

Hence VCE is minimized and Governor Speed Controller does not change its speed

DSP: Digital Set Point AS: Actual Speed VCE: Velocity Control Error


Case Study

The Generation system at FFL is currently in Island ModeLet us simplify the generation system by considering GTG-A & GTG-B only

Let the GTGs be rated to a capacity of 20 MW each which accounts to a total generation capacity of 40 MW (considering STG is not being operated)

We shall discuss the following 3 cases:

Case 1: Both the GTGs are operated in Isoch modeCase 2: Both the GTGs are operated in Droop modeCase 3: GTG-A in Isoch mode & GTG-B in Droop mode


Case 1: Both the GTGs are operated in Isoch mode



Isoch

GTG A

GTG B Isoch

Let us assume our system is stable initially with following characteristics

System: 50 Hz , 15 MWGTG-A: 50 Hz , 15 MWGTG-B: Not in operation

GTG A GTG BF (Hz)

MWGTG B = 0 MWGTG A = 15 MW

System = 15 MW

50 Hz


Hence Finally,GTG-A: 50 Hz, 0 MWGTG-B: 50.1 Hz, 20 MWSystem: 50.1 Hz, 20 MW

In fact, GTG-A will finally trip on Reverse Power


Isoch

GTG A

GTG B Isoch

Now the system load gradually increases to 20 MW. Hence GTG-B is brought in service to share load with GTG-A

GTG A

GTG BF (Hz)

MWGTG B = 0 MWGTG A = 20 MW

System = 20 MW

GTG B = 20 MW

GTG A = 0 MW

50 Hz

When GTG-B is about to be synched with the systemSystem: 50 Hz , 20 MWGTG-A: 50 Hz , 20 MWGTG-B: 50.1 Hz 50.1

Hz



Explanation

Since frequency setting of GTG-B is above System’s frequency, it gains more load and keeps on gaining until System’s frequency becomes equal to GTG-B

(which happens when GTG-B serves the entire load of the System)

Consecutively, GTG-A will loose its entire load while GTG-B begins to feed the entire load. (GTG-A may reach the point of Reverse Power Trip

as well)

Conclusion

Since the frequency of the Incoming generator will be greater than that of the system (for synchronism), this method of operation is strictly

unfeasible


Case 2: Both the GTGs are operated in Droop mode


Droop

GTG A

GTG B

Droop

Let both the GTGs be operated in DROOP mode (with same Droop setting)

Let us assume our system is stable initially with following characteristics

System: 50 Hz , 30 MWGTG-A: 56 Hz (@ no load) , 18 MWGTG-B: 53 Hz (@ no load) ,12 MW

GTG A GTG BF (Hz)

MWGTG B = 12 MW

GTG A = 18 MW

System = 30 MW

50 Hz


56 Hz

53 Hz


Droop

GTG A

GTG B

Droop

Meanwhile, Refrigeration Compressor at NP (1.5 MW) is started As a result the load on both GTGs will increase in equal proportions (b/c of same droop settings)

GTG A GTG BF (Hz)

MWGTG B = 12 MW

GTG A = 18 MW

System = 30 MW

50 Hz


GTG A = 18.75 MW GTG A = 12.75 MW

System = 31.5 MW

As a result, the overall frequency of the System will decrease to meet load requirement

49.4Hz

Therefore, in order to bring the system back to 50 Hz, operator must raise the ‘no load frequency’ of either one or both the GTGs.



Explanation

In this case, an increase in system load will decrease its frequency(operator will have to increase the ‘no load frequency set point’ of either

both GTGs or any one)

While, a decrease in system load will increase its frequency(operator will have to decrease the ‘no load frequency set point’ of either

both GTGs or any one)

Conclusion

Hence, this method of operation is feasible in load stable systems (where load doesn’t vary in large proportions). Otherwise continuous

load monitoring is necessary.


Case 3: GTG-A in Isoch mode & GTG-B in Droop mode


Droop

GTG A

GTG B

Isoch

This case is explained using a number of sub-cases

Let us assume our system is stable initially with following attributes

System: 50 Hz , 20 MWGTG-A: 53 Hz (@ no load) , 10 MWGTG-B: 50 Hz (Isoch) , 10 MWGTG A GTG B

F (Hz)

MWGTG B = 10 MW

GTG A = 10 MW

System = 20 MW

50 Hz

53 Hz

Case 3: GTG-B in Isoch mode & GTG-A in Droop mode

Rated Capacity: 20 MW each

NOTE: In each of the following sub-cases, operator is not allowed to change the no load frequency set point of GTG-

A


Droop

GTG A

GTG B

Isoch

Subcase ‘a’: System load increases by 1.5 MW (NP Refrigeration Compressor starts)

System: 50 Hz , 21.5 MWGTG-A: 53 Hz (@ no load) , 10 MWGTG-B: 50 Hz (Isoch) , 11.5 MW

GTG A GTG BF (Hz)

MWGTG B = 10 MW

GTG A = 10 MW

System = 20 MW

50 Hz


GTG B = 11.5 MW

System = 21.5 MW


Consequence: No action required


Droop

GTG A

GTG B

Isoch

Subcase ‘b’: System load decreases by 5 MW

System: 50 Hz , 15 MWGTG-A: 53 Hz (@ no load) , 10 MWGTG-B: 50 Hz (Isoch) , 5 MW

GTG A GTG BF (Hz)

MWGTG B = 10 MW

GTG A = 10 MW

System = 20 MW

50 Hz


GTG B = 5 MW

System = 15 MW


Consequence: No action required


Droop

GTG A

GTG B

Isoch

Subcase ‘c’: System load decreases to 10 MW

System: 50 Hz , 10 MWGTG-A: 53 Hz (@ no load) , 10 MWGTG-B: 50 Hz (Isoch) , 0 MW

GTG A GTG BF (Hz)

MWGTG B = 10 MW

GTG A = 10 MW

System = 20 MW

50 Hz


GTG B = 0 MW

System = 10 MW

Consequence: No load ‘f’ set-point of GTG-A should be decreased



Droop

GTG A

GTG B

Isoch

Subcase ‘d’: System load decreases to 5 MW

System: >50 Hz , 5 MWGTG-A: 53 Hz (@ no load) , 5 MWGTG-B: 50 Hz (Isoch) , 0 MW

GTG A GTG BF (Hz)

MWGTG B = 10 MW

GTG A = 10 MW

System = 20 MW

50 Hz


GTG B = 0 MW

System = 5 MW

GTG A = 5 MW

51.5HzConsequence: No load ‘f’ set-point of GTG-A should be decreased



Droop

GTG A

GTG B

Isoch

Subcase ‘e’: System load increases to 40 MW

System: < 50 Hz , 40 MWGTG-A: 56 Hz (@ no load) , 14 MWGTG-B: 50 Hz (Isoch) , 26 MW

GTG A GTG BF (Hz)

MWGTG B = 10 MW

GTG A = 10 MW

System = 20 MW

50 Hz


GTG B = 26 MW

System = 40 MW

After crossing rated capacity

GTG A = 14 MW

< 50 Hz

Consequence: No load ‘f’ set-point of GTG-A should be increased


Explanation

In this case, an increase in system load will not affect system frequency (The GTG running in Isoch mode provides the additional load without

affecting the frequency of system – if load change is with in prescribed limit)

While, a decrease in system load will not affect system frequency either(The GTG running in Isoch mode reduces its own fed load without affecting

the frequency of system – if load change is with in prescribed limit)

If load changes are not in ‘Prescribed Limits’, operator will have to step in and increase or decrease the ‘No load frequency set point’ of droop GTG

Conclusion

Hence, this method of operation is feasible in all systems running in Island mode. Isochronous GTG serves as the Swing Generator.



EXCITATION CONTROLControl Functions, Types, Capability Curves & Case Study


Functions of Excitation Systems


The basic functions of an excitation system are• To provide direct current to the synchronous generator field winding• To perform control and protective functions essential to the satisfactory

operation of the power system

Performance Requirements of AVR


These control and protective functions include:

Secondary Functions of AVR

Generator Considerations(Follow Capability Curve,

Maintain V/Hz ratio)

System Considerations(Ensure System stability)

Brushless Excitation System


AVR Operation Principle


The line voltage (provided by VT) is compared to a Reference Voltage.

The difference (error) signal is amplified and then used to control the output of a thyristor rectifier

This rectifier supplies a portion of the PMG output to the exciter field

Load Increment:

If Generator Load is increased, Terminal voltage drops.

Error Signal is amplified, which causes an increase in exciter field current

This results in an increased Main Field Current

Hence, Generator Voltage is restored.

Conversely, Load Reduction will lead to actuation of Opposite series of steps

Vt

AVR Operation Principle – Parallel Scheme


The discussed AVR principle is relevant for Islanded Operation with singular source or even multiple sources

But for Parallel operation (especially with Infinite Bus), Terminal Voltage is not influenced by the Generator’s Excitation.

Instead, Excitation now determines the Reactive Power developed by the Generator

ConsequencesSystem Voltage Excitation

CurrentReactive Power

Consequence

Vsys < Vref Increased by AVR Excessive Lagging Q

Excessive Rotor Heating

Vsys > Vref Decreased by AVR Excessive Leading Q

Generator Pole Slipping (Asynchronism)

AVR Operation Principle - QCC


Hence to overcome this problem, the AVR Voltage Control System is modified using QCC (Quadrature Current Compensation)

This compensation replicates the ‘frequency/MW’ relation for ‘Voltage/MVAr’

Note: QCC Schematic Diagram and Operation Principle can be discussed in detail if required*

QCC Operation (Islanded Scheme with Multiple Machines)


The mentioned system has 3 Generators which share Total Load VArs on QCC Principle

In this example, machines A and B have identical droop and at a particular line voltage will supply equal VARs.

Machine C has less droop and will therefore supply more VARs than A or B, at the same line voltage

Practical ExperimentComprehensive Governor & Excitation

Response


Comprehensive Governor & Excitation Behavior

The test presented to explain this behavior was practically conducted on 8th May 2010.The system was initially running with following attributes:

GTG-A’s MW and MVAr outputs were varied and comprehensive system response was analyzed


GTG A GTG B

Pa=8.5 MW Qa=5 MVAr p.f=0.86 Pb=8.5 MW Qb=5 MVAr p.f=0.86

Pt=17 MWQt=10 MVArp.f=0.86

Isoch ModeDroop Mode

Varied using Governor set-point

Varied using AVR QCC set-point


Manual Action 1:• Pa decreased only (using droop set-point of GTG-A)• Qa not changed (i.e. AVR QCC set-point not disturbed)

Automatic Result:– Pb increased (Isochronous operation)– Qb not changed

– Hence, • P.F. of GTG-A = Decreased (because Pa/Qa ratio decreased)• P.F. of GTG-B= Increased (because Pb/Qb Ratio increased)


GTG A GTG B



Ptot Qtot P Q p.f P Q p.fMW MVAR MW MVAR --- MW MVAR ---

17 10 8.5 5 0.86 8.5 5 0.86

Action 1 Pa Decreased Manually* Pb Increased Automatically

17 10 6 5 0.77 11 5 0.91

Action 2 Qa Decreased Manually** Qb Increased Automatically

17 10 6 3.529 0.86 11 6.471 0.86

Action 3 Pa Increased Manually* Pb decreased Automatically

17 10 8.5 3.529 0.92 8.5 6.471 0.80

Action 4 Qa Increased Manually** Qb decreased Automatically

17 10 8.5 5 0.86 8.5 5 0.86

GTG-A GTG-B

* performed using droop set-point** performed using AVR QCC set-point

Explanation through V-Curve (for GTG-A only)


Action-1

Action-2

Action-3

Action-4

CAPABILITY CURVEGenerator Limitations,


Capability Diagram of Generator

This diagram determines the limitations of a generator’s output.• Following Constraints define the entire limitation:

– Current heating of the stator (armature).– Power Output of the prime mover.– Current heating of the rotor (field).– Stability of the rotor angle.

Capability Diagram of GTGs

Stator Current Limit

Rotor Current Limit

Rotor Stability Limit

Capability Diagram (Explanation)

P (p.u.)

Q (p.u.)Lagging QLeading Q

Constraint # 1:STATOR CURRENT

1.0

1.5

1.0 1.0 O

VI

Stator HeatingMVA Limit

Ø

P (p.u.)


Constraint # 2:Prime Mover Output1.5

O

1.0

1.0 1.0

Max MW Output

Arbitrary Operating Point


P (p.u.)


Constraint # 3:ROTOR CURRENT

(Generated Voltage)Eg α Rotor Current

1.5

O

1.0

1.0 1.0

VIEg V / Xs

Sq(V) / Xsᵟ


IXsEg

V

OXL

OXM

Note: Xd of GTGs is 2.13 p.u. This determines the position of this point

P (p.u.)


Constraint # 4:STABILITY OF THE ROTOR1.5

O

1.0

1.0 1.0


UEL

UEM

Theoretical Stability Limit

P (p.u.)


1.5

O

1.0

1.0 1.0


OXL

OXM

UEL

UEM

Theoretical Stability Limit

Max MW Output

Queries?


Thank you !


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