NLDC Petition regarding inadequate FGMO response

Annexure-1

Fig.1

Fig.2

49.00

49.40

49.80

50.20

50.60

51.00H

z --

>

Date -->

ER / NEW GRID MAXIMUM AND MINIMUM FREQUENCY JANUARY'2013 ONWARDS

MAXIMUM MINIMUM

0.3

0.5

0.7

0.9

1.1

1.3

De

c-1

2

Ma

r-1

3

Ju

n-1

3

Oc

t-1

3

Jan

-14

Ap

r-1

4

Ju

l-1

4

No

v-1

4

Hz

MONTH -->

ER/NEW GRID FREQUENCY FLUCTUATIONS (MAXIMUM-MINIMUM) JANUARY'2013 ONWARDS

31

Annexure-I

Fig.3

Fig.4

49.80

50.00

50.20

De

c-1

2

Mar-

13

Ju

n-1

3

Oc

t-1

3

Ja

n-1

4

Ap

r-1

4

Ju

l-1

4

No

v-1

4

Hz -

->

MONTH -->

EASTERN REGION / NEW GRID AVERAGE FREQUENCY SCATTER PLOT January'2013 ONWARDS

48.50

49.00

49.50

50.00

50.50

51.00

51.50

52.00

52.50

53.00

Ja

n-9

8

Ju

l-9

8

Ja

n-9

9

Ju

l-9

9

Ja

n-0

0

Ju

l-0

0

Ja

n-0

1

Ju

l-0

1

Ja

n-0

2

Ju

l-0

2

Ja

n-0

3

Ju

l-0

3

Ja

n-0

4

Ju

l-0

4

Ja

n-0

5

Ju

l-0

5

Ja

n-0

6

Ju

l-0

6

Jan

-07

Ju

l-0

7

Ja

n-0

8

Ju

l-0

8

Ja

n-0

9

Ju

l-0

9

Ja

n-1

0

Ju

l-1

0

Ja

n-1

1

Ju

l-1

1

Ja

n-1

2

Ju

l-1

2

Ja

n-1

3

Ju

l-1

3

Ja

n-1

4

Ju

l-1

4

Hz -

->

MONTH -->

EASTERN REGION / NEW GRID AVERAGE FREQUENCY SCATTER PLOT JANUARY'98 ONWARDS

32

Annexure-I

Fig.5

Fig.6

0.3

0.8

1.3

1.8

2.3

2.8

3.3

3.8

4.3

4.8

5.3

5.8J

an

-98

Ju

l-9

8

Jan

-99

Ju

l-9

9

Jan

-00

Ju

l-0

0

Jan

-01

Ju

l-0

1

Jan

-02

Ju

l-0

2

Jan

-03

Ju

l-0

3

Jan

-04

Ju

l-0

4

Jan

-05

Ju

l-0

5

Jan

-06

Ju

l-0

6

Jan

-07

Ju

l-0

7

Jan

-08

Ju

l-0

8

Jan

-09

Ju

l-0

9

Jan

-10

Ju

l-1

0

Jan

-11

Ju

l-1

1

Jan

-12

Ju

l-1

2

Jan

-13

Ju

l-1

3

Jan

-14

Ju

l-1

4

Hz

MONTH -->

ER/NEW GRID FREQUENCY FLUCTUATIONS (MAXIMUM-MINIMUM) JANUARY'98 ONWARDS

47

48

49

50

51

52

53

54

Hz -

->

Date -->

ER / NEW GRID MAXIMUM AND MINIMUM FREQUENCY JANUARY'98 ONWARDS

MAXIMUM MINIMUM

33

Annexure-I

Fig.7

Fig.8

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.1

1.2

1.3

1.4D

ec

-12

Ju

n-1

3

Dec

-13

Ju

n-1

4

Dec

-14

HZ

--->

DAYS --->

SOUTHERN REGION FREQUENCY FLUCTUATIONS (MAXIMUM-MINIMUM) SCATTER PLOT

January'2013 ONWARDS

48.5

49.0

49.5

50.0

50.5

51.0

Dec-1

2

Ju

n-1

3

De

c-1

3

Ju

n-1

4

Dec-1

4

FR

EQ

UE

NC

Y I

N H

Z -

-->

DAY ---->

MAXIMUM, MINIMUM & AVERAGE FREQUENCY PLOT FROM January'2013 ONWARDS(Southern Region)

MAXIMUM MINIMUM AVERAGE

34

Annexure-I

Fig.9

Fig.10

48.5

49.0

49.5

50.0

50.5

51.0D

ec-1

2

Ju

n-1

3

Dec-1

3

Ju

n-1

4

Dec-1

4

FR

EQ

UE

NC

Y I

N H

Z -

-->

DAY ---->

MAXIMUM, MINIMUM FREQUENCY PLOT FROM January'2013 ONWARDS(Southern Region)

MAXIMUM MINIMUM

0.2

0.7

1.2

1.7

2.2

2.7

3.2

Ap

r-01

Oct-

01

Ap

r-02

Oct-

02

Ap

r-03

Oct-

03

Ap

r-04

Oct-

04

Ap

r-05

Oct-

05

Ap

r-06

Oct-

06

Ap

r-07

Oct-

07

Ap

r-08

Oct-

08

Ap

r-09

Oct-

09

Ap

r-10

Oct-

10

Ap

r-11

Oct-

11

Ap

r-12

Oct-

12

Ap

r-13

Oct-

13

Ap

r-14

Oct-

14

HZ

--->

DAYS --->

SOUTHERN REGION FREQUENCY FLUCTUATIONS (MAXIMUM-MINIMUM) SCATTER PLOT

APRIL-2001 ONWARDS

35

Annexure-I

Fig.11

Fig.12

47.5

48.0

48.5

49.0

49.5

50.0

50.5

51.0

51.5

Ap

r-01

Oct-

01

Ap

r-02

Oct-

02

Ap

r-03

Oct-

03

Ap

r-04

Oct-

04

Ap

r-05

Oct-

05

Ap

r-06

Oct-

06

Ap

r-07

Oct-

07

Ap

r-08

Oct-

08

Ap

r-09

Oct-

09

Ap

r-10

Oct-

10

Ap

r-11

Oct-

11

Ap

r-12

Oct-

12

Ap

r-13

Oct-

13

Ap

r-14

Oct-

14

Ap

r-15

FR

EQ

UE

NC

Y I

N H

Z -

-->

DAY ---->

MAXIMUM, MINIMUM & AVERAGE FREQUENCY PLOT FROM APRIL-01 ONWARDS(Southern Region)

MAXIMUM MINIMUM AVERAGE

47.5

48.0

48.5

49.0

49.5

50.0

50.5

51.0

51.5

Ap

r-01

Oct-

01

Ap

r-02

Oct-

02

Ap

r-03

Oct-

03

Ap

r-04

Oct-

04

Ap

r-05

Oct-

05

Ap

r-06

Oct-

06

Ap

r-07

Oct-

07

Ap

r-08

Oct-

08

Ap

r-09

Oct-

09

Ap

r-10

Oct-

10

Ap

r-11

Oct-

11

Ap

r-12

Oct-

12

Ap

r-13

Oct-

13

Ap

r-14

Oct-

14

Ap

r-15

FR

EQ

UE

NC

Y I

N H

Z -

-->

DAY ---->

MAXIMUM, MINIMUM FREQUENCY PLOT FROM APRIL-01 ONWARDS(Southern Region)

MAXIMUM MINIMUM

36

Annexure-I

Fig.13

49.70

49.80

49.90

50.00

50.10

50.20

50.300

:00

:00

1:0

0:0

0

2:0

0:0

0

3:0

0:0

0

4:0

0:0

0

5:0

0:0

0

6:0

0:0

0

7:0

0:0

0

8:0

0:0

0

9:0

0:0

0

10

:00

:00

11

:00

:00

12

:00

:00

13

:00

:00

14

:00

:00

15

:00

:08

16

:00

:00

17

:00

:00

18

:00

:00

19

:00

:00

20

:00

:00

21

:00

:00

22

:00

:00

23

:00

:00

24 hour Frequency Plot of a normal day(20th Jan'15)

37

Power System Control and Stability

Power Plant Testing

Process Control

Engineering Management

Nuclear Power Safety

Solvina International Annexure-2

38

Voltage stability research 1992-1995

Consultant since 1996

Focus: Dynamic behavior of Power systems

Introduction

0

2

Niclas Krantz Managing Director

Lic. Eng. Power Systems [email protected]

+46 31 709 6304

Annexure-2

39

1. Solvina Introduction

2. Methodology adopted for testing

3. Brief outcome of the testing of the units andcomments on FGMO/RGMO

4. International practices and regulatory provisionsregarding periodic testing of frequency control

5. Suggestions for Control strategies and RegulatoryInterventions reg. testing in India

Presentation outline Annexure-2

40

Holistic and dynamic approach to Process, Power and Control engineering is our speciality.

Core business Annexure-2

41

Nuclear Power

Power Plants (Thermal, Hydro)

Cogeneration/Captive plants

Pulp Mills

Steel Mills

Chemical sites

Electric grid utilities

Customers Annexure-2

42

”Generators are the pillars of power grid stability…”

Grid Stability

Dr. Prabha Kundur

To ensure power grid and power plant stability Solvina carry out and optimize:

Frequency control, Governors

Load control

Voltage control, AVR

Power System Stabilizers, PSS

Plant operation capabilities

Load rejection into House Load operation

System simulation studies

Annexure-2

43

During 2014, Solvina International has carried our test of primary response of five units in India, under a contract with Power Grid /POSOCO.

Reports for each test is under way and will be submitted in a final report shortly.

(Observe that this is a preliminary presentation and should not be taken in detail for implementation straight off.

Background to primary response testingAnnexure-2

44

Test method /SSPS function Annexure-2

45

By breaking up the control loop for frequency control, any test signal may be injected to study the response of the machine while still synchronized to the main grid (online testing!)

Tests may be carried out

- ”open loop”, with a predefined signal

- ”closed loop”, with a simulated signal depending on the unit output

Test principle Annexure-2

46

What is desired to know in normal operation in the large grid is the

- Magnitude of response (MW/Hz)

- Speed of response (Time constant)

Injecting a frequency step (open loop) gives both these variables in a very clear way.

FGMO ”primary response” Annexure-2

47

Example Dadri II, 100% load

-0.05, +0.13 Hz steps

Annexure-2

48

What is desired to know in Islanded conditions is the ability of the unit to respond to load changes and how it can maintain the stability of the system frequency following different contingencies.

Full scale tests can be made if allowed, but this is both costly and hazardous. Furthermore, rarely the load level may be chosen.

So, by simulating islanded conditions and giving the simulated frequency to the unit, islanded conditions can be evaluated.

FGMO ”Islanded systems” Annexure-2

49

Example Dadri II, 75 % load

± 23 MW

Annexure-2

50

Unit / Test FGMO RGMO Islanding (FMGO)

Chamera (180MW)

As Expected 60 MW/Hz, 10-60s

OK, meets grid code

Stable, can manage large load change (>10%)

Tehri, (250MW) Expected behavior but gate feedback causes nonlinear load response. 50-250MW/Hz, (125) 100-200s

Works but not as intended in some cases

Stable, can manage large load change (>10%)

Dadri II (490MW) Expected beavior 196MW/Hz, 15-85s

- Stable f-control but unstable process

Dadri I (210MW) Expected behavior, but maybe too reponsive 84MW/Hz, 3-8s

- Unstable f-control and process

Bawana (216MW) Expected behavior 110MW/Hz, 5-10s

- Not tested due to inability to arrange test input

Test results Annexure-2

51

Hydro power plants are generally well suited for frequency control, including islanding. Response is practically only limited by limit of the turbine. The process itself is quite simple and robust.

Thermal Power Plants (boilers) can provide a fast response, but the thermal process is complex and slow, which requires special attention.

Gas Turbines can usually respond very quickly, and are ideal both for fast primary response and for Islanding.

General comments Annexure-2

52

RGMO is implemented as per the Grid Code in both Chamera and Tehri but the interpretations are different. Hence, the Grid Code is not completely clear.

RGMO is not acting in proportion to the frequency deviation and is NOT strictly a frequency governing mode, rather a logic to increase the generated load at frequency drops.

RGMO is missing controller feedback and consequently, no stable dynamic equilibrium can be reached with this mode.

RGMO comments Annexure-2

53

FGMO is not an internationally used expression

FGMO seems to have different interpretations in India.

A combined Frequency / Load Control with Droop is commonly used internationally, and could be found in Dadri and Chamera for instance.

FGMO comments Annexure-2

54

Primary control – intends to maintain the power balance in the system and hence keep the frequency reasonably close to 50Hz.

Should be automatic and always present.

Response in seconds (0-60)

Secondary control – intends to control the average frequency level at 50.0 Hz.

Response in minutes - hours

Can be automatic or manual in combination with forecasting tools and scheduling

On Frequency Dynamics Annexure-2

55

Large units, when operating in FSM (Article 10): Response according to droop within certain limits

ENTSO-E Annexure-2

56

Large units, when operating in FSM (Article 10): Full response within 30 s, start within 2 s.

ENTSO-E Annexure-2

57

Testing of FSM (Article 39)

a) The Power Generating Module shall demonstrate its technical capability to continuously modulate Active Power over the full operating range between Maximum Capacity and Minimum Regulating Level to contribute to Frequency Control and shall verify the steady- state parameters of regulations, such as Droop and deadband and dynamic parameters, including robustness through Frequency step change response and large, fast Frequency changes.

b) The test shall be carried out by simulating Frequency steps and ramps big enough to activate the whole Active Power Frequency response range, taking into account the Droop settings, the deadband and the Real Power headroom or deload (margin to Maximum Capacity in operational timescale). Simulated Frequency deviation signals shall be injected simultaneously into the references of both the speed governor and the load controller of the unit or plant control system if required, taking into account the speed governor and load controller scheme. (Equipment Certificate may be used instead of part or all of the test)

ENTSO-E Annexure-2

58

LFSM-O (Article 8) Medium and large units must respond to severe overfrequency (threshold 50.2 .. 50.5 Hz) by reducing output according to droop.

ENTSO-E Annexure-2

59

Testing of LFSM-O (Article 38)

a) The Power Generating Module shall demonstrate its technical capability to continuously modulate Active Power to contribute to Frequency Control in case of large increase of Frequency in the system and shall verify the steady-state parameters of regulations, such as Droop and deadband, and dynamic parameters, including Frequency step change response.

b) The test shall be carried out by simulating Frequency steps and ramps big enough to activate at least 10 % of Maximum Capacity change in Active Power, taking into account the Droop settings and the deadband. Simulated Frequency deviation signals shall be injected simultaneously at both the speed and power control loops of the control systems if required, taking in account the scheme of these control system. (Equipment Certificate may be used instead of part or all of the test)

ENTSO-E Annexure-2

60

LFSM-U (Article 10) Large units must, if possible, respond to severe underfrequency (threshold 49.8 .. 49.5 Hz) by increasing output according to droop.

ENTSO-E Annexure-2

61

Testing of LFSM-U (Article 39)

a) The Power Generating Module shall demonstrate its technical capability to continuously modulate Active Power at operating points below Maximum Capacity to contribute to Frequency Control in case of large drop of Frequency in the system.

b) The test shall be carried out by simulating at appropriate Active Power load points (e.g. 80 %) with low Frequency steps and ramps big enough to activate at least 10 % of Maximum Capacity Active Power change, taking into account the Droop settings and the deadband. Simulated Frequency deviation signals shall be injected simultaneously into both the speed governor and the load controller references if required, taking into account the speed governor and the load controller scheme. (Equipment Certificate may be used instead of part or all of the test)

ENTSO-E Annexure-2

62

Testing

No details given on how simulating Frequency steps and ramps shall be done.

• Internal governor function?

• External equipment?

ENTSO-E Annexure-2

63

Grid code ’FIKS’ developed in a specific technical environment:

• Almost exclusively hydropower

• Mainly Francis and Pelton turbines – fast response possible

• Weak grid and long distances – large risk for islanding

Norway Annexure-2

64

Governor response testing (Appendix to FIKS)

1. Servo loop time constant Test during shutdown (dry unit) recommended. Test is specific for hydropower

2. Delay – from frequency rise to start of gate movement Breaker trip suggested

Norway Annexure-2

65

Governor response testing (Appendix to FIKS)

3. Droop Logging during interconnected operation.

4. Islanding Real life tests, single or multiple units

Norway Annexure-2

66

Primary control support is an ancillary service, and is purchased in blocks of XXMW/Hz

Time constant shall be <60s (Mostly Hydro)

Testing by step response is required to show compliance (common practice)

Island operation ability is contracted between the TSO and the plants, or regionally and utilize a combination of real tests and SSPS online method for evaluation.

Sweden Annexure-2

67

Require plants to have an external analog frequency test input, where the National Load Dispatch Center (EGAT) can inject a test signal and evaluate the primary response regularly. (Grid code does not clearly express

this but is based on discussions with system planning department)

Thailand Annexure-2

68

Phase out RGMO gradually

Implement PI(D) Frequency control (FGMO) with droop integrated with Load control.

”Power Feedback” in normal operation for predictible response

”Gate Feedback” in Islanding for best possible stability

Recommendations for Plants Annexure-2

69

For Primary response in normal operation, step response tests should be carried out to get the magnitude and time constant

For islanding, either online ”simulator testing” or real life full scale tests should be considered. Nothing else is sufficient.

For checking of the participation in frequency control, the generated power and frequency can be used for verification

Any testing should be carried out by an independent party

Recommendations for Testing Annexure-2

70

Work out clear Crid Code for Primary Control response and for testing of the same. The requirements should be based on the unique circumstances in India.

Grid topology

Grid bottlenecks

Generation mix, geograpical distribition

”Design base” contingencies

Market aspects

Recommendations for Grid Control Annexure-2

71

Thanks for your attention!

0

35

Niclas Krantz [email protected]

+46 31 709 6304

Contact in India:

Mr. Shahzad Alam +91 99 10 611184

Welcome to contact us for clarifications!

Annexure-2

72

Solvina International AB Document template: Solvina International Report.dot. Last change made by VOl 20st of October 2010

Gruvgatan 37 Phone +46 031 - 709 63 00 Internet www.solvina.com Org no 556782-3280 SE-421 30 Västra Frölunda Location: Göteborg SWEDEN

Valid date

2014-11-23 Project (no - customer)

2014018- POSOCO Report No:

2014018-20 Page (no pages)

1 (39) Author

Shweta Tigga/Niclas Krantz Reviewed

Sven Granfors

Bengt Johansson

Approved

Niclas Krantz

Title

2014018-20-1.0 Testing of Primary Response of Chamera I Unit 3.docx

Distribution

Nodal officers NTPC, NHPC, THDC, PPCIL, POSOCO

SUMMARY

This document presents the results of primary response tests, including island operation tests of a

180 MW hydroelectric unit at Chamera I Power Plant, India, conducted from 13th

Oct – 15th

October 2014.

The report describes the test setup, conditions and results from the measurements made by

Solvina International. Tests show that both FGMO and RGMO work as expected and that

FGMO can be used to control the frequency both in interconnected mode and in islanded mode.

In the latter case power feedback should be set OFF.

The following tests were performed at Chamera-I unit 3:

- Step response tests with FGMO mode, power feedback ON: The step response tests

performed show a consistent behaviour in accordance with droop, with the expected

value of 60MW/Hz. However, the time constant varies vastly due to actuator

imperfection, i.e mechanical backlash.

- Step response tests with FGMO mode, power feedback OFF: The performed step

response tests show longer delay compared to power feedback ON and a varying

response of the generated load magnitude. This is according to expected behaviour due to

mechanical backlash in the actuator system. The tests in this mode show that the

generated load response is only approximately in accordance with the droop setting,

whereas the gate position response is in accordance with the droop, which can be

expected considering the mechanical backlash.

- Step response tests with RGMO mode: The tests conducted in RGMO mode show a

consistent behaviour and in line with the grid code. The generated load increases by 5 %

of the actual generated load for 5 min for a drop in frequency.

- Small Island test: From the tests it was concluded that the unit is able to control the

frequency in a stable way. Up to 20MW load changes were tested without any problems.

Due to mechanical backlash, continuous but stable oscillations in the generated load were

observed.

- Large Island test: The test shows that the power plant responds well to load steps on a

large grid as well. The oscillations on application of the load step are quite damped due to

the presence of inertia of other plants. In this case 30MW load changes were tested

successfully.

Annexure-3

73

C:\Temp\2014018 - INT, POSOCO, Testing of Primary Response\2014018-20-1.0 Testing of Primary Response of Chamera I Unit 3.docx

Page 2 of 39 Printed 2014-11-23 14:37

CONTENTS

1 INTRODUCTION .......................................................................................... 4 1.1 Background ....................................................................................................... 4 1.2 Tests performed ................................................................................................ 4

2 DESCRIPTION OF TESTED UNIT ............................................................ 5 2.1 Basic unit data .................................................................................................. 5 2.2 Governor ........................................................................................................... 5 2.3 Actuator system ................................................................................................ 6

3 DESCRIPTION OF TESTS PERFORMED ................................................ 7 3.1 Definitions ........................................................................................................ 7 3.2 Method for island operation testing .................................................................. 8 3.3 Test procedure .................................................................................................. 9

3.3.1 Test equipment/function/signal check ............................................................... 9 3.3.2 Step response tests ............................................................................................ 9 3.3.3 Small island tests .............................................................................................. 9 3.3.4 Large island test ............................................................................................. 10

4 TEST RESULTS ........................................................................................... 11 4.1 Executive summary ........................................................................................ 11 4.1.1 Primary frequency response ........................................................................... 11 4.1.2 Island operation .............................................................................................. 11 4.2 Primary frequency response, step response tests ............................................ 11 4.2.1 Step response tests in FGMO mode ................................................................ 11 4.2.2 Step response tests in RGMO mode ................................................................ 19 4.3 Island operation tests – Small island .............................................................. 27 4.3.1 Small island – generated load 10 %. .............................................................. 28

4.3.2 Small island – generated load 75% ................................................................ 31 4.4 Island operation tests – Large island .............................................................. 33

5 CONCLUSIONS ........................................................................................... 36 5.1 FGMO ............................................................................................................. 36 5.2 RGMO ............................................................................................................ 36 5.3 ISLAND OPERATION .................................................................................. 36 5.3.1 Small Island test: ............................................................................................ 36 5.3.2 Large island test ............................................................................................. 37

6 RECOMMENDATIONS ............................................................................. 38 6.1 Normal (grid connected) operation ................................................................ 38 6.2 Island operation .............................................................................................. 38

6.3 Mechanism ..................................................................................................... 38

7 REFERENCES ............................................................................................. 39

Annexure-3

74


Page 3 of 39 Printed 2014-11-23 14:37

REVISION RECORD

Rev.

No.

Date Section Cause Revised

by

Distributed to

1.0 2014-11-23 All Draft report submitted NKr Nodal officers

Annexure-3

75


Page 4 of 39 Printed 2014-11-23 14:37

1 INTRODUCTION

1.1 Background

After the large disturbance/outage in northern India in July 2012 it was concluded

that there is a need to verify the primary response of generating units in India. In

March 2013 it was decided that a pilot project to carry out primary frequency

response would be carried out, and this was then described in terms of reference

document (annexure to contract agreement) [1].

Solvina International was awarded this pilot project after a global tender process and

signed a contract agreement with Power Grid PGCIL/POSOCO in August 2014 [1].

The purpose of these tests was to record and verify the following capabilities on the

specified generating units:

Primary Frequency Response in normal operation under Restricted governor

mode (RGMO) and Free governor mode (FGMO).

Primary Response of the machine to a simulated frequency signal

corresponding to islanded conditions in small island (one unit) and large

island (2000MW system load).

The following units are included in the project:

490 MW thermal unit at Dadri NCTPS


216 MW gas turbine at Bawana GPS

180 MW hydro unit at Chamera-1 HPS

250 MW hydro unit at Tehri HPS

This report is for the tests at unit 3 (180MW) at Chamera, NHPC.

1.2 Tests performed

The following tests were carried out on Chamera-I unit 3 as per the test program [2]:

13th

Oct 2014 Test equipment/function/signal check

Connections completed with signal check and test equipment

function check.

14th

Oct 2014 Step Response tests

Step response tests at 10%, 75% and 100% of rated generated load

under FGMO and RGMO mode.

15th

Oct 2014 Small Island test: 10% and 75% of rated generated load.

Large Island test: 75% of rated generated load.

Annexure-3

76


Page 5 of 39 Printed 2014-11-23 14:37

2 DESCRIPTION OF TESTED UNIT

Chamera hydro power station has three units of 180 MW each. The turbines are

Francis type.

2.1 Basic unit data

Table 1: Basic data Chamera unit 3

Turbine Make BHEL

Age 1994

Size 180MW

Speed 214.3 rpm

Generator Make BHEL

Age 1994

Size 200MVA

Governor Make ALSTOM

Age 2011

Type Digital

2.2 Governor

The governor is supplied by Alstom. It has two frequency control modes for normal

operation

1. FGMO (Free Governor Mode of Operation) is a linear power/frequency

control, based on a PI controller with droop. The feedback which is used for

forming the droop response can be taken from either the measured generated

active power (referred to as power feedback ON) or from the corresponding

wicket gate position (referred to as power feedback OFF). This is selected by

a switch in the control room. The normal condition is power feedback ON.

FGMO is also suitable for islanding.

2. RGMO (Restricted Governor Mode of Operation) is a non-linear control

especially adapted for the grid code requirements. Certain conditions of

decreasing grid frequency within the RGMO frequency band will cause the

governor to increase the generated load by 5 % of actual generated load for 5

minutes. If the grid frequency goes above the limit of the RGMO, the

governor will decrease the generated load by an amount calculated from

droop (which is in this case referred to rated generated load).

Annexure-3

77


Page 6 of 39 Printed 2014-11-23 14:37

2.3 Actuator system

The wicket gate of each unit is controlled by a hydraulic actuator cylinder that rotates

a wicket gate ring in proportion to the governor output. The gate sections are linked

to this ring and are rotated by it, as indicated in the figure below. The sensor of the

wicket gate position is placed on the actuator piston rod, which means that it cannot

sense if there is any mechanical play or backlash in the link between the piston and

the ring or between the ring and the gate sections. The gate position in the figures in

this report is the position as measured by this sensor. The actual angle of the gate

sections may differ from this measured position in case of mechanical play or

backlash.

The hydraulic actuator has a pressure reserve that enables rapid movement of the

wicket gate. Repeated large movements could theoretically deplete this reserve faster

than it can be refilled, but no such problems were seen during the tests.

Figure 1. Simplified diagram of the wicket gate control mechanism.

The results from the tests indicate that there is in fact a significant play or backlash in

the mechanism. This is the case for both the step response tests and the island

operation tests, see section 5.

Sensor

ACTUATOR

CYLINDER

Piston rod

Ring

Gate

sections Links

Annexure-3

78


Page 7 of 39 Printed 2014-11-23 14:37

3 DESCRIPTION OF TESTS PERFORMED

3.1 Definitions

Simulated frequency: This is the signal generated by the test

equipment, SSPS.

It can be used as input to the

frequency/speed controller instead of the

actual speed from the frequency/speed

sensor.

Actual frequency: Signal from generator frequency/speed

sensor.

Generated load: Active power of generating unit

[Active power (used in plots) ]

System load: Total active power consumption in the

grid

Simulated system load System load simulated in the test

equipment

System base load: Start value of simulated system load when

starting the island simulation test.

Annexure-3

79


Page 8 of 39 Printed 2014-11-23 14:37

3.2 Method for island operation testing

Solvina has developed a test equipment to be used for evaluation of the island

operation capability of power turbines. The equipment is called SolvSim Power

Station, SSPS.

The test method uses the principle of “HardWare In the Loop”, i.e. a simulator

simulating that a small power system is connected to the speed governor of a turbine.

The speed controller will then act as if it is actually running in island operation. The

active power produced by the turbine is measured and summed up with simulated

contributions to calculate the active power balance of the simulated island.

Gen.

Grid

Turbine

Mea

sure

d Si

gnal

s

Governor

Simulated

island

Actual Frequency

Simulated

FrequencySSPS

Relay

Figure 2. Hardware-in-the-loop simulation of island operation.

Models of loads as well as other power producers can be included in the model of the

electric island.

Using the active power balance and the total moment of inertia of the island, the

island frequency can be calculated and fed back to the speed controller of the turbine

tested. In this way, the capability of running in island operation can be tested while

the turbine is still synchronized to a strong grid.

SSPS is also used to inject simulated frequency steps for primary response tests.

Annexure-3

80


Page 9 of 39 Printed 2014-11-23 14:37

3.3 Test procedure

3.3.1 Test equipment/function/signal check

Before commencement of actual tests, all the values/scalings of the measured signals

and the installation of the test equipment were checked to ensure correct

measurements and safe operation. The switching between the actual and the

simulated frequency was tested several times to verify a bumpless transition. The

internal safety functions of the SSPS system were also verified.

3.3.2 Step response tests

With commencement of the test sequence, initially the simulated frequency was kept

at 50Hz. The primary response was tested by injecting a frequency step to the

governor frequency input. The frequency step was calculated from the droop settings,

to produce an generated load change of up to approx. 5% of rated load.

The step tests with RGMO/ FGMO engaged in governor were performed at 10%,

75% and 100% of rated generated load with positive and negative steps in frequency.

3.3.3 Small island tests

This test was performed to assess the ability of the turbine to control the frequency as

sole production on an island grid. Simulated load steps of different sizes were

applied (see section 4.3), which resulted in a change in simulated frequency.

For the tests at Chamera, Table 2 below summarizes the grid model with a total

simulated system base load of 18 and 135 MW respectively. The simulated system

load comprises frequency dependent and frequency independent loads.

Table 2 Simulator parameters for small island test.

System

Base load

Rated apparent

power (Sn) of

generator

System load with

linear frequency

characteristic

System load without

frequency

dependence, no inertia

Small

Island

@10%

18MW 200 MVA

(Inertia 4,07 s)

8 MW

(Inertia 0,70 s)

10 MW

Small

Island

@75%

135 MW

60 MW

(inertia 0,70 s)

65 MW

Annexure-3

81


Page 10 of 39 Printed 2014-11-23 14:37

Simulated load steps were added to this base load as shown in section 4.3. After each

load step, the generated load and the simulated frequency were allowed to stabilize

(near to 50 Hz).

The tests were repeated at 10% and 75% generated load with FGMO engaged in

governor. The size of the acceptable system load steps was decided by increasing the

step size gradually until the simulated frequency limits or other limitations were

reached.

3.3.4 Large island test

This test was performed to assess the ability of the turbine to control the frequency

together with other power plants on a local grid. All other power plants were

simulated to act according to power control. Simulated load steps of different sizes

were applied (see section 4.4) to determine the size of the load changes that the

power plant could handle.

The summary of the total simulated base load was 2000 MW. Table 3 below

summarizes the grid model. The simulated load comprises frequency dependent and

independent loads.

Table 3 Simulator parameters for large island test

Total

system

base load

Rated

apparent

power (Sn) of

generator

System load with

linear frequency

characteristic

System load

without

frequency

dependence,

no inertia

Additional

simulated

power

plants

Large

island:

2000 MW

200 MVA

(inertia 4,07 s)

1000 MW

(Inertia 0,70 s) 1000 MW

2000 MVA

(Inertia 4,0 s)

1800 MW

Annexure-3

82


Page 11 of 39 Printed 2014-11-23 14:37

4 TEST RESULTS

4.1 Executive summary

4.1.1 Primary frequency response

FGMO works as expected in both “power feedback ON” and “power feedback

OFF”. The magnitude of the response is as per the droop settings. However, the time

constant varies vastly, mainly because of mechanical backlash in the actuator system.

In “power feedback OFF” (meaning gate opening feedback), the gate opening

responds according to droop, but due to the mechanical backlash, the load responds

to various extent only. During the tests, both positive and negative frequency steps

up to 0.15 Hz were tested.

RGMO works as intended and in accordance with the Grid Code. Simulated

frequency steps were made to test functionality both within and outside the RGMO

frequency range 49.0-50.05 Hz.

4.1.2 Island operation

The unit is very capable of controlling the frequency both in small island grids and

large island grids. The capacity of handling load changes was tested up to ±20MW

(11%) with very moderate frequency variations (1,5Hz). It is believed that up to

±30MW should not be a problem in islanding.

Due to the mechanical backlash of the actuator there is a slow spontaneous frequency

oscillation of ±0.3-0.4 Hz that however does not at all tend to cause instability.

4.2 Primary frequency response, step response tests

4.2.1 Step response tests in FGMO mode

The step response tests are carried out to investigate how well the plant supports the

power system at frequency changes of the grid. The speed droop is the parameter that

decides the magnitude of response. The response has two characteristics that are

interesting to examine, the magnitude and the time constant (67% value, T67).

For the tests in FGMO mode the droop setting during test was 6%. Both power

feedback ON and power feedback OFF were tested.

Steps were carried out to give up to 5% load change, which is 9MW, and the

frequency step size giving that response would be 0.05*0.06*50 = 0.15 Hz.

Consequently 9MW is the expected response for the steps to be carried out.

Similarly, expressed in MW/Hz, the response is expected to be 60MW/Hz for any

step (9/0.15).

Annexure-3

83


Page 12 of 39 Printed 2014-11-23 14:37

4.2.1.1 Step response in FGMO, generated load 10%, power feedback ON

The step response tests were carried out at 10% generated load with power feedback

ON.

Table 4 Frequency steps in FGMO, generated load 10 %, power feedback ON – part 1

Simulated

frequency (Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change , ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

50 50,1 20 14 -6 60 48

50,1 50 14 20 +6 60 59

5049,9

20 26 +6 60 25

49,9 50 26 20 -6 60 65

50 49,85 20 29 +9 60 42

49,85 50 30 20 -10 67 47

Figure 3. Frequency steps in FGMO, generated load 10 %, power feedback ON – part 1.

Annexure-3

84


Page 13 of 39 Printed 2014-11-23 14:37

Table 5. Frequency steps in FGMO, generated load 10%, power feedback ON – part 2

Simulated

frequency (Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change , ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

Load setpoint changed from 20 25 MW @ 50 Hz

50 50,15 25 15 -10 67 30

50,1550 15 25 +10 67 45

Figure 4. Frequency steps in FGMO, generated load 10%, power feedback ON – part 2.

It can be concluded that the response is correct and in accordance with the droop

settings at all steps. The spread of time constant values mainly depends on

mechanical backlash of the actuator linkage as explained in section 2.3 and 5.1. It

can be seen from the above figure that the measured gate position opening varies

depending on step sequence whereas the load response is constant, which is expected

as power feedback is ON. The measured gate position is moved further to

compensate for the existing mechanical backlash (see section 5.1). For steps in the

same (decreasing) direction, the effect of mechanical backlash is reduced as the gate

position is already moving in upward direction so a shorter traveling distance is

required by the actuator piston rod.

Annexure-3

85


Page 14 of 39 Printed 2014-11-23 14:37

4.2.1.2 Step response in FGMO, generated load 10%, power feedback OFF

The tests with power feedback OFF were carried at 10% generated load.

Table 6. Frequency steps in FGMO, generated load 10 %, power feedback OFF

Simulated

frequency

(Hz)

Initial

generated

load

(MW)

Post step

generated

load

(MW)

Gen. load

change ,

ΔP (MW)

MW

contribution

(MW/Hz)

Gate

position

change

(%)

Time

constant,

T67 (s)

5049,85 22 25 +3 20 5 57

49,8550 25 23 -2 13 5 78

50 50,15 23 13 -10 67 5 27

50,1550 13 14 +1 7 5 75

Figure 5. Frequency steps in FGMO, generated load 10 %, power feedback OFF.

The test shows that the gate opening response is according to the droop setting. The

measured gate position change of 5% is in perfect accordance with the set droop

value of 6%. However, looking at load response to frequency, steps have a varying

magnitude. This is mainly because of the mechanical backlash, where certain gate

opening value causes different values in real gate value and hence generated load.

The generated load change after a step is dependent on the direction of the previous

step. For example, for two steps in the same consecutive directio, the response of the

active load is immediate with frequency steps in increasing direction and the effect of

the mechanical backlash is not there. This is because the movement of the gate

position is already in the downward direction and requires shorter piston traveling

distance.

Annexure-3

86


Page 15 of 39 Printed 2014-11-23 14:37


The same procedure as above tests is repeated. The power feedback being ON so the

response is expected to be faster as mentioned in section 4.1.1.

Table 7 Frequency steps in FGMO, generated load 75 %, power feedback ON.

Simulated

frequency (Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change , ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

50 49,85 Hz 133 142 +9 60 11

49,85 50 Hz 142 133 -9 60 42

50 50,15 Hz 133 122 -10 67 31

50,1550 Hz 122 133 +10 67 18

Figure 6. Frequency steps in FGMO, generated load 75 %, power feedback ON.

The test shows that the response to frequency steps has a consistent magnitude which

is in accordance with the droop setting. The response of the measured gate position

signal is immediate. The response of the active load is immediate for some steps but

delayed by 7-10 seconds for some steps, due to the mechanical backlash as described

in sections 2.3 and 5.1.

Annexure-3

87


Page 16 of 39 Printed 2014-11-23 14:37


Tests were performed at 75% generated load with the same conditions as previous

tests mentioned in above sections.

Table 8 Frequency steps in FGMO, generated load 75 %, power feedback OFF.

Simulated

frequency

(Hz)

Initial

generated

load

(MW)

Post step

generated

load

(MW)

Gen. load

change ,

ΔP (MW)

MW

contribution

(MW/Hz)

Gate

position

change

(%)

Time

constant,

T67 (s)

50 50,15 136 127 -9 60 5 47

50,15 50 127 133 +9 60 5 79




value of 6%.

However, the generated load response magnitude varies. This is mainly because of

the mechanical backlash, where certain measured gate opening value causes different

values in real gate value and hence load.

Annexure-3

88


Page 17 of 39 Printed 2014-11-23 14:37


Tests were performed at 100% generated load with the same conditions as for

previous tests.

Table 9 Frequency steps in FGMO, generated load 100 %, power feedback ON.

Simulated

frequency (Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change , ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

50 49,85 180 189 +9 60 29

49,85 50 189 179 -10 67 26

50 50,15 179 169 -10 67 14

50,1550 169 180 +10 67 30

Figure 8. Frequency steps in FGMO, generated load 100 %, power feedback ON.

The test shows that the generated load response to frequency steps has a consistent

magnitude in accordance with the droop setting. The response of the gate position

signal is immediate. The response of the active load is immediate for some steps but

delayed by 7-10 seconds for some steps, due to the mechanical backlash as described

in sections 2.3 and 5.1.

Annexure-3

89


Page 18 of 39 Printed 2014-11-23 14:37


Tests were performed at 100% generated load with power feedback OFF and with

same conditions as for the previous tests.

Table 10 Frequency steps in FGMO, generated load 100 %, power feedback OFF.

Simulated

frequency

(Hz)

Initial

generated

load

(MW)

Post step

generated

load

(MW)

Gen. load

change ,

ΔP (MW)

MW

contribution

(MW/Hz)

Gate

position

change

(%)

Time

constant,

T67 (s)

50 50,15 179 170 -9 60 5 34

50,1550 170 177 +7 47 5 38

50 49,85 177 190 +13 87 5 24

49,85 50 190 186 -4 27 5 52




value of 6%. However, looking at load response to frequency, steps have a varying

magnitude. This is mainly because of the mechanical backlash, where certain gate

opening value causes different values in real gate value and hence generated load.

Annexure-3

90


Page 19 of 39 Printed 2014-11-23 14:37

4.2.2 Step response tests in RGMO mode

The purpose of this test is to elaborate the function of RGMO. Frequency steps of

different size and different levels are generated to excite the response of the RGMO.

The response in this mode should be in accordance with the grid code, which states

that, “There should not be any reduction in generation in case of improvement in

grid frequency below 50.05 Hz. Whereas for any fall in grid frequency, generation

from the unit should increase by 5 % limited to 105% of the MCR of the unit

subject to machine capability”.

In Chamera, the RGMO frequency band is 49-50.05 Hz. The droop setting kept

during these tests in RGMO was 6%. The following sections give the results of the

tests performed.

Annexure-3

91


Page 20 of 39 Printed 2014-11-23 14:37

4.2.2.1 Step response in RGMO, generated load 10%

For the tests at 10% generated load in RGMO mode, it is expected that for any

decrease in frequency below the RGMO upper band limit of 50.05 Hz, the generated

load should increase by 5%.

Table 11 Frequency steps in RGMO mode, generated load 10%, part 1of 2.

Simulated frequency

(Hz)

Initial generated

load (MW)

Post step generated

load (MW)

Generated load

change, ΔP (MW)

50 49,95 24 22 -2

49,95 50 22 23 +1

50 50,10 23 16 -7

50,10 50 16 23 +7

50 50,15 23 13 -10

50,1550 13 23 +10

Figure 10. Frequency steps in RGMO mode, generated load 10%, part 1of 2

Annexure-3

92


Page 21 of 39 Printed 2014-11-23 14:37

Figure 11: Frequency steps in RGMO, generated load 10 % - part 2 of 2.

From the above figure, it can be seen that for a decrease in frequency, the generated

load increases by 5% of the actual value which is 1MW at that level. With increase in

frequency to 50 Hz, no change in generated load is seen. For a step change in

frequency outside the RGMO frequency band 50.05 Hz, the generated load is

decreased in accordance with the droop setting referred to the rated load. The

behavior is correct and in accordance with the grid code.

Annexure-3

93


Page 22 of 39 Printed 2014-11-23 14:37


The same procedure is repeated as per the above tests were performed at 75%

generated load.

Table 12 Frequency steps in RGMO, generated load 75 % - part 1 of 2

Simulated

frequency (Hz)

Initial generated

load (MW)

Post step generated

load (MW)

Generated load

change, ΔP (MW)

50 49,85 133 140 and ramp back to

133 MW after 5 min

+7

49,85 50 133 133 0

50 49,80 133 141 +8

49,80 50 141 No initial response. Ramps back to 134

MW after 5 min

Figure 12. Frequency steps in RGMO, generated load 75 % - part 1 of 2


load increases by 5% of the actual value which is 7 MW at that level. With increase

in frequency to 50 Hz, no change in generated load is seen. The behavior is in

accordance with the grid code.

Annexure-3

94


Page 23 of 39 Printed 2014-11-23 14:37

Table 13 Frequency steps in RGMO, generated load 75 % Part 2 of 2

Simulated

frequency (Hz)

Initial generated

load (MW)

Post step generated

load (MW)

Generated load

change, ΔP

(MW)

50 50,15 134 124 -10

50,15 50 124 134 +10

50 49,95 135 141 +6

49,9550 141 141 0

Figure 13. Frequency steps in RGMO, generated load 75 % Part 2 of 2

The test shows that when the frequency goes above 50.05 Hz, the generated load is

decreased in accordance with the droop setting. When the frequency decreases, the

generated load is increased by 5 % of actual generated load for 5 minutes. This is in

accordance with the grid code.

Annexure-3

95


Page 24 of 39 Printed 2014-11-23 14:37


The same procedure is repeated for tests carried out at 100% generated load. The

behavior is expected to be according to grid code.

Table 14 Frequency steps in RGMO, generated load 100 % - part 1 of 2.

Note: generated load changes after 5350 s are caused by water head

oscillations due to starting of another unit.

Simulated frequency

(Hz)

Initial generated

load (MW)

Post step generated

load (MW)

Generated load

change, ΔP

(MW)

50 49,85 Hz 179 188 +9

49,85 50Hz 188 179 -9

50 50,15 Hz 179 168 -11

50,15 50 Hz 168 187 +19 *)

*)Simulated frequency going in and out of RGMO band, so result is not taken

into account.

Figure 14. Frequency steps in RGMO, generated load 100 % - part 1 of 2. Note:

generated load changes after 5350 s are caused by water head oscillations due

to starting of another unit.


load increases by 5% of the actual generated load which is 9MW at that level. With

increase in frequency to 50 Hz, no change in generated load is seen. The behavior is

in accordance with grid code.

Annexure-3

96


Page 25 of 39 Printed 2014-11-23 14:37

Table 15 Frequency steps in RGMO, generated load 100 % - part 2 of 2

Simulated frequency

(Hz)

Initial generated

load (MW)

Post step generated

load (MW)

Generated load

change, ΔP

(MW)

50 50,10 Hz 178 171 -7

50,10 50 Hz 171 187 +16

50 50,2 Hz 178 164 -14

50,20 50 Hz 164 186 +22

50 49,98 Hz 178 178 0

49,98 50 Hz 178 178 0

5050,02 Hz 178 178 0

50,0250 Hz 178 178 0

5049,99 Hz 178 178 0

49,9950 Hz 178 178 0

50 50,04 Hz 178 178 0

50,0450 Hz 176 186 +10

5050,05 Hz 186 176* -10

50,0550 Hz 176 186* +10

*Simulated frequency going in and out of RGMO band

Annexure-3

97


Page 26 of 39 Printed 2014-11-23 14:37

Figure 15. Frequency steps in RGMO, generated load 100 % - part 2 of 2

The test shows that when the frequency goes above 50.05 Hz, the generated load is

decreased in accordance with the droop setting. When the frequency decreases, the

generated load is increased by 5 % of actual generated load.

Annexure-3

98


Page 27 of 39 Printed 2014-11-23 14:37

4.3 Island operation tests – Small island

This test shows the ability of the plant to control the frequency when the tested unit

is the only generating source of the system. By simulating system load changes of the

simulated island, the simulated frequency will change. The tested unit will try to

control the simulated frequency. This way, it can be seen if the unit is stable. The

island operation tests were performed with power feedback off.

Droop setting was 6 %.

It was decided that the testing would be made at 10% and 75% load.

For the following figures, the legend is as below:

Blue Simulated frequency. This denotes the grid frequency in

real Island operation.

Red Generated load (= measured active power). This denotes

the mechanical turbine load in real island operation.

Green Gate position feedback. Please note that this is measured on

the actuator piston, see section 2.3.

Purple Simulated system load. This denotes the actual system load

in real island operation.

Annexure-3

99


Page 28 of 39 Printed 2014-11-23 14:37

4.3.1 Small island – generated load 10 %.

The tests were carried out at only 10% of generated load. Simulated system load

steps were applied and the frequency deviations were recorded.

Table 16 Simulated island operation, generated load 10 %, all applied load steps.

Total range of

generated load (MW)

Simulated system load

step (MW)

Max. frequency deviation,

Δf (Hz)*

23-40 MW

+6 MW -0,8

-6 MW +0,4

+8 MW -0,9

-8 MW +1,0

+10 MW -1,2

-10 MW +0,5

+12 MW -0,8

-12 MW +0,8

+14 MW -1,4

-14 MW +0,7

+16 MW -1,5

-16 MW +1,2

+18 MW -1,2

-18 MW +1,3

+20 MW -1,3

-20 MW +1,1

*Please note: All frequency deviations are measured from the instant the step is

applied.

Annexure-3

100


Page 29 of 39 Printed 2014-11-23 14:37

Figure 16. Simulated island operation, generated load 10 %, load step ±16 MW.


Annexure-3

101


Page 30 of 39 Printed 2014-11-23 14:37


The test shows that the unit is able to control the frequency in a stable way. There is

a continuous slow oscillation while in island operation, due to mechanical backlash

as earlier described, causing frequency deviations of around ±0.3-0.4 Hz. (The cause

of the oscillation is further described in section 5.) Nevertheless, the unit responds

well to system load steps and the frequency stabilizes quickly. The largest simulated

load steps were ±20 MW. It is likely that the unit can handle even larger steps but the

test was halted after ±20 MW to avoid overstressing of the turbine.

Annexure-3

102


Page 31 of 39 Printed 2014-11-23 14:37

4.3.2 Small island – generated load 75%

The tests were carried out at only 75% of rated generated load. Simulated system

load steps were applied and the frequency deviations were recorded.

Table 17 Simulated island operation, generated load 10 %, all applied load steps.

Total range of

generated load

(MW)

Simulated system load step

(MW)

Max. frequency deviation, Δf

(Hz)*

134-155 MW

+4 MW -0,4

-4 MW +0,6

+8 MW -0,5

-8 MW +0,7

+12 MW -0,5

-12 MW +1,0

+16 MW -1,2

-16 MW +1,0

+20 MW -1,3

-20 MW +1,0

Annexure-3

103


Page 32 of 39 Printed 2014-11-23 14:37

Figure 19. Simulated island operation, generated load 75%, load step ±16 MW.


The test shows that the unit is able to control the frequency in a stable way. There is

a continuous slow oscillation while in island operation, due to mechanical backlash

as earlier described, causing frequency deviations of around ±0.3-0.4 Hz.

Nevertheless, the unit responds well to load steps and the frequency stabilizes

quickly. The largest simulated load steps were ±20 MW. It is likely that the unit can

handle even larger steps but the test was halted after ±20 MW to avoid overstressing

of the turbine.

Annexure-3

104


Page 33 of 39 Printed 2014-11-23 14:37

4.4 Island operation tests – Large island


together with other power plants on a local grid. The summary of the simulated base

load is described in section 3.3.4. The large island tests were performed at 75% of

rated generated load. Simulated system load steps were applied and the frequency

deviations were recorded. The droop setting during test was 6%.

Table 18 Simulated large island operation, generated load 75 %, all applied steps.

Total range of

generated load

(MW)


step (MW)

Max. frequency

deviation, Δf (Hz)*

134-168 MW

+12 MW -0,33

-12 MW +0,26

+20 MW -0,32

-20 MW +0,40

+25 MW -0,40

-25 MW +0,56

+30 MW -0,63

-30 MW +0,62

Annexure-3

105


Page 34 of 39 Printed 2014-11-23 14:37

Figure 21. Simulated large island operation, generated load 75 %, load steps ±25, ±30

MW. Simulated frequency and simulated system load are shown.

Figure 22. Simulated large island operation, generated load 75 %, load steps ±25, ±30

MW. Generated load (active power) and gate position along with simulated

frequency are shown.

Annexure-3

106


Page 35 of 39 Printed 2014-11-23 14:37

The test shows that the power plant responds well to load steps on a large grid. The

largest simulated system load steps were ±30 MW. It is likely that the unit can

handle even larger steps but the test was halted after ±30 MW to avoid overstressing

of the turbine.

From the above figure it can be seen that the load follows the same profile as the

frequency because of the inertia and linear frequency dependency characteristic of

the load model described in section 3.3.4. Together with the inertia of the other

simulated power plants, this has a stabilizing effect of the grid frequency.

Annexure-3

107


Page 36 of 39 Printed 2014-11-23 14:37

5 CONCLUSIONS

5.1 FGMO

The results for step response tests in FGMO mode show a consistent behavior. Tests

were performed both with power feedback ON and OFF.

Test performed with power feedback ON, show that response of load for a step

change was as per droop, but with a variation in time constant.

Tests with power feedback OFF show that the response with regard to gate opening

value was as per droop. However, a longer delay compared to power feedback ON

was noticed, as well as a varying response of the load magnitude depending on the

character of the step sequence.

The delay in response is attributed to mechanical backlash of the actuator system.

This cause shows in several ways. The measured gate position is seen to increase by

3-4% before the load actually starts to increase. It was also observed that this

phenomenon was not so pronounced when consecutive steps in frequency were

applied in the same direction (either positive or negative), because the backlash at the

second step then is zero.

In the case of power feedback is ON, the control compensates for this mechanical

backlash by further moving the gate position. The tests with power feedback OFF

show a larger time delay for the response of the load. Here the delay is longer as the

governor does not compensate for the existing mechanical backlash as there is no

feedback of generated load (active power).

5.2 RGMO

The grid code states that, “There should not be any reduction in generation in case

of improvement in grid frequency below 50.05 Hz. Whereas for any fall in grid

frequency, generation from the unit should increase by 5 % limited to 105% of the

MCR of the unit subject to machine capability”.

All tests show that the behavior is in accordance with the grid code. The time delays

caused by mechanical backlash has not been considered here because it is not part of

the requirements, but the same variation in delay is present in RGMO.

5.3 ISLAND OPERATION

5.3.1 Small Island test:

The unit could handle the ±20MW system load steps very well, with very moderate

frequency variations. The tested load changes correspond to 11% of rated load, and

that is considered being very good.

Annexure-3

108


Page 37 of 39 Printed 2014-11-23 14:37


For the large island test, the highest system load step of ±30 MW was applied which

generated a frequency deviation of approx. ±0.63 Hz. From Figure 22, it can be seen

that there is a delay in the response of the load but there exists no continuous

oscillations. This delay in the response is again caused by the mechanical backlash.

As the system inertia is higher in a large island, the plant can more easily keep the

frequency in a large island than in a small island. It is most likely that the unit can

handle much bigger system load changes in such a large island, at least double the

tested amount, i.e 60MW.

Annexure-3

109


Page 38 of 39 Printed 2014-11-23 14:37

6 RECOMMENDATIONS

The results from the tests were analyzed to see what could further be done to

improve the performance. In this section some recommendations are presented.

6.1 Normal (grid connected) operation

FGMO is useful for providing frequency control to the national grid. While

connected to the national grid, the governor should be set to power feedback ON for

best accuracy of generated load and fastest possible response.

RGMO has a consistent response which is according to the settings. No actions are

recommended regarding this function.

6.2 Island operation

FGMO is also useful for frequency control while in island operation, either with one

unit as sole production on the grid or together with other units which may operate in

frequency or load control. The unit responds well to load changes in the grid and can

handle load changes of at least ±20 MW as sole production, and more if operating

together with other units. While operating on an island grid, the governor should be

set to power feedback OFF for best stability.

While operating on a small island grid, there may be some slow continuous

oscillations, caused by mechanical backlash in the wicket gate control mechanism.

This oscillation does not impede the ability of the unit to respond to load changes in

the grid. It could however cause some difficulty or delay in the synchronization of

the island grid to another grid.

RGMO should not be used while in island operation.

6.3 Mechanism

It is likely that a reduced mechanical backlash between the gate position sensor and

the angle of the gate sections will provide less continuous oscillations in island

operation, as well as faster load control in grid connected operation.

One way of compensating for the backlash could be to move the gate position

feedback sensor so that it senses the angle of the gate section rather than the position

of the piston that rotates the wicket gate ring.

Annexure-3

110


Page 39 of 39 Printed 2014-11-23 14:37

7 REFERENCES

[1] Contract Agreement No.: CC-CS/422-CC/CON-2241/3/G8/CA/5002 dated

19/08/2014

[2] Test Program - Chamera : 2014 018-14-1.0

Annexure-3

111



Valid date




1 (61) Author

Shweta Tigga

Bengt Johansson

Reviewed Niclas Krantz

Approved Niclas Krantz

Title

2014018-28-1.0 Testing of Primary Response of Dadri I Unit 4

Distribution

Nodal officer NTPC; POSOCO

SUMMARY

This document presents the results of primary response tests, including island operation tests of a

210 MW thermal unit at Dadri Power Plant, India, conducted from 20th

- 22nd

November 2014.


Solvina International. Tests show that the droop of the FGMO works as intended, but the

response is very fast which makes the unit unable to achieve stable operation on a small island

grid.

The following tests were performed at Dadri (Stage I), unit 4:

- Step response tests in FGMO mode: The step tests were performed at 75%, 90% and

100% generated load levels with a droop setting of 5%. Steps corresponding to a

generated load change of up to 5 % were tested. The generated load response corresponds

well to the droop setting. The response time T67 is very fast, in the range of 2-8 seconds,

and it has a distinct overshoot. This is due to the settings of the load controller.

- Small Island tests: The unit was unable to operate in small island tests at 75% and 90%

load levels with 5% droop. A continuously growing oscillation occurred as soon as the

island simulation was started, and the simulation had to be stopped. The tests were also

performed with droop setting of 8% but with the same result.

- Large Island test: The large inertia of the simulated grid made it possible for the unit to

achieve stable island operation. The response to a simulated system load change was

oscillatory but reasonably well damped. Simulated system load changes of ±14 MW were

tested successfully.

It was observed during the tests that the boiler control had problems responding to the load

changes and large steam pressure fluctuations were seen. This caused, at different times, both

operation of the HP bypass valve due to overpressure and load reduction due to underpressure.

The load control system itself started oscillating under certain conditions when the IP valve was

active.

Annexure-3

112

of 61 Printed 2015-01-15 09:29

CONTENTS


2 DESCRIPTION OF TESTED UNIT ............................................................ 5 2.1 Basic unit data .................................................................................................. 5 2.2 Operation principle of Thermal power plants................................................... 6 2.4 Governor ........................................................................................................... 9

3 DESCRIPTION OF TESTS PERFORMED .............................................. 12 3.1 Definitions ...................................................................................................... 12 3.2 Method for island operation testing ................................................................ 13

3.3 Test procedure ................................................................................................ 14 3.3.1 Test equipment/function/signal check ............................................................. 14 3.3.2 Step response tests .......................................................................................... 14 3.3.3 Small island tests ............................................................................................ 14 3.3.4 Large island test ............................................................................................. 15 3.4 Recorded signals ............................................................................................. 16

4 TEST RESULTS ........................................................................................... 17 4.1 Executive summary ........................................................................................ 17 4.1.1 Primary frequency response ........................................................................... 17 4.1.2 Island operation .............................................................................................. 17 4.2 Primary frequency response, step response tests in FGMO ........................... 18 4.2.1 Step response in FGMO, generated load 75%, droop 5% ............................. 19 4.2.2 Step response in FGMO, generated load 90%, droop 5% ............................. 34

4.2.3 Step response in FGMO, generated load 100%, droop 5% ........................... 37 4.3 Island operation tests – Small island .............................................................. 41 4.3.1 Small Island test, generated load 75%, droop 5% ......................................... 42 4.3.2 Small Island test, generated load 75%, droop 8% ......................................... 44 4.3.3 Small island – generated load 90%, droop 5% .............................................. 46 4.3.4 Small island – generated load 90%, droop 8% .............................................. 47 4.4 Island operation tests – Large island .............................................................. 50

5 CONCLUSIONS ........................................................................................... 57 5.1 FGMO ............................................................................................................. 57

5.2 ISLAND OPERATION .................................................................................. 57 5.2.1 Small Island test: ............................................................................................ 57 5.2.2 Large island test ............................................................................................. 57


7 REFERENCES ............................................................................................. 61

Annexure-3

113

of 61 Printed 2015-01-15 09:29

REVISION RECORD

Rev.

No.

Date Section Cause Revised by Distributed to

1.0 2015-01-12 All Document created BJo POSOCO

Annexure-3

114

of 61 Printed 2015-01-15 09:29

1 INTRODUCTION

1.1 Background










Primary Frequency Response in normal operation under Free governor mode

(FGMO).


corresponding to islanded conditions in small island (one unit) and large

island (2000MW system load).







This report is for the tests at unit 4 (210MW) at Dadri I, NTPC

1.2 Tests performed

The following tests were carried out on unit 4 of Stage-I Dadri as per the test

program [2]:

20th

Nov 2014 Test equipment/function/signal check


function check.

Step Response tests

Step response tests at 75% of rated generated load under FGMO

mode.

21st Nov 2014 Step Response tests: Step response tests at 90% and 100% of

rated generated load under FGMO mode.

Small Island test: 75% and 90 % of rated generated load.

Large Island test: 90% of rated generated load.

Annexure-3

115

of 61 Printed 2015-01-15 09:29


The total installed capacity of NTPC Dadri power plant is 2642 MW. The plant

comprises six thermal units with a total capacity of 1820 MW; four units of 210 MW

each and two units of 490 MW. In addition to the thermal plants, NTPC Dadri also

has 817 MW gas based thermal plant and 5 MW solar plant.

2.1 Basic unit data

Table 1: Basic data Dadri I Unit 4

Turbine Type KWU

Speed 3000 rpm

Generator Rating 247 MVA, 210 MW

Governor Make BHEL

Type Analog

Figure 1. Interior of power plant

Annexure-3

116

of 61 Printed 2015-01-15 09:29

2.2 Operation principle of Thermal power plants

The thermal power plant is based on the principle of Rankine cycle. Figure shows the

processes involved in a Rankine cycle. The water is first pumped from step 12,

thereby increasing the pressure, which requires some input energy. From step 23,

the water at high pressure is heated in a boiler at constant pressure by an external

heat source which turns it into steam. The steam is then allowed to expand in a

turbine, thereby generating power (step 34). The steam is finally allowed to

condense to water in a condenser at constant pressure (step 41), thereby removing

heat from the cycle. The same process repeats continuously.

Figure 2: Rankine cycle

In thermal power plants, however, different applications of the Rankine cycle exist.

Various stages of turbines can be added for the expansion of steam so as to maximize

the efficiency of the cycle.

Figure 3 below shows the schematic of a basic thermal power plant. The pulverized

coal from the coal mill enters the furnace where combustion takes place. The heat

generated turns the water into steam which is used to rotate the steam turbine which,

in turn, drives the generator. After the steam passes through the steam turbine, it is

heated again.

Vaporizer

Condenser

P

ExpanderPump

1

2

3

4

Annexure-3

117

of 61 Printed 2015-01-15 09:29

Figure 3: Schematic of a general thermal power plant

The plant can be divided into four main circuits, namely:

Fuel and Ash circuit

The coal from the storage is fed to the boiler via coal handling plant. The

Ash produced after the combustion process is collected and moved to the

ash handling plant.

Air and Gas circuit

Air from the atmosphere is supplied to the furnace via induced draught

fans (ID) and/or forced draught (FD) fans. The air before passing to the

furnace is preheated in the Air preheater using the heat of the flue gases.

The flue gases first pass through the boiler tubes in the furnace, next

through a precipitator or dust collector and then through the economizer.

Finally, the flue gases are released through the chimney.

Feed water and steam circuit

The condensate leaving the condenser is first heated through extracted

steam from the turbine. The feed water then passes through a deaerator

and HP heaters before it goes into the boiler through the economizer. The

wet steam from the boiler drum is further heated in the superheater before

it is sent to the high pressure turbine. After the expansion of steam in the

HP turbine, it is retaken to the boiler for reheating before it passes through

the intermediate pressure turbine and low pressure turbine. From the LP

turbine, the steam after expansion condenses to water in the condenser.

Cooling water circuit

A continuous flow of cooling water is required to condense the steam in

the condenser and also to maintain a low pressure in it.

LP Turbine

Furnace

Deaerator

HP

heaters

IP

TurbineHP

Turbine Generator

Condenser

Boiler

Drum

LP

heaters

Chimney

Dust

collector

Coal

hopper

Pulveriser

Air

Hot airPulverised

Coal

Flue

gases

Annexure-3

118

of 61 Printed 2015-01-15 09:29

Unlike hydro power plants, where water is always available for load changes, a

thermal power plant has limited ability to handle large load changes. It is commonly

known that boiler response is rather slow, that drum level variations may be critical

etc. However, by designing and tuning for optimal dynamic performance,

improvements can usually be achieved.

2.3 Details of tested unit

Some additional information is required to understand the operation of the tested

unit. Figure 4 shows a simplified schematic of the steam system diagram above, but

with some additional details that are explained below.

LP Turbine

Furnace

HP

heaters

IP

Turbine

HP

Turbine Generator

Condenser

Boiler

Drum

LP

heaters

Air

Pulverised

Coal

Flue

gases

HP

Valve

HP

Bypass

IP

Valve

LP

Bypass

Feed

water

Figure 4: Schematic diagram of the steam system of the tested unit.

HP bypass = valve for shunting steam past the HP turbine. The HP bypass increases

the steam consumption from the boiler without increasing the generated load and is

used for reducing the steam pressure in case of overpressure, which may occur when

the turbine is using less steam than the boiler produces. This valve is normally closed

but opened partially during one of the tests performed.

LP bypass = valve for shunting steam past the IP and LP turbines. This valve was

closed during all of the tests performed.

IP valve = IP turbine steam inlet valve, which is used for controlling the pressure in

the reheater. The valve normally fully open but closes partially in case of high HP

steam pressure and small HP valve opening, which occured during some of the tests

performed.

Annexure-3

119

of 61 Printed 2015-01-15 09:29

2.4 Governor

The governor has the following control modes/functions for normal operation

1. FGMO (Free Governor Mode of Operation) is a power/frequency control

mode in which a load offset is calculated from the measured frequency using

an adjustable gain function which is set to produce the desired droop, which

in this case is 5 % (the adjustment range is 2.5 to 8 %). The frequency

dependent load offset is limited to ± 5 % of rated load, which consequently

limits the frequency range for the response in FGMO operation. (It can be

noted that for other types of units, for example hydro power, there is usually

no such limitation for the frequency dependent load adjustment.) The load

offset is added to the load setpoint and the resulting load value is used as

setpoint by the load controller, which in turn is a PI controller which controls

the generated load by adjusting the HP valve position. The load controller

uses the measured active power as feedback. Figure 5 shows a simplified

block diagram for this control mode and Figure 6 shows the load/frequency

characteristic for the stationary condition in this mode. The load offset is zero

when the frequency is exactly 50 Hz. FGMO is suitable for islanding but

requires some adjustments for optimal performance.

2. Co-ordinated mode control (CMC). In this mode, the HP valve opening is

coordinated with the boiler to keep the steam pressure stable. The generated

load is basically according to the steam production.

3. RGMO is implemented on this unit but, on request fron NTPC, this mode was

not tested by Solvina. The implementation is made in the Co-ordinated mode

control and increases the fuel infeed to the boiler depending on the grid

frequency and with a certain droop and deadband. The generated load

changes with the steam production. This makes the response very slow

(several minutes) but the method ensures that the unit operation remains

stable. Though being slow, it will have a beneficial effect on the long term

frequency stability of the national grid.

There is also a separate speed controller but it is only used for idling and

syncronization purposes.

Furthermore, the governor contains a number of additional functions for ensuring

safe operation, for example:

1. The pressure controller may take over the control of the HP valve in case of

large HP steam pressure deviations, typically by reducing the generated load

in case the steam pressure becomes too low.

2. The over pressure limiter will open the HP bypass valve in case the HP steam

pressure becomes too high.

3. The IP valve is controlled together with the HP valve for maintaining the

pressure in the reheater.

Annexure-3

120

of 61 Printed 2015-01-15 09:29

Figure 5. Simplified block diagram for FGMO.

Figure 6. Load/frequency characteristic in FGMO mode. The slope is adjusted

according to the droop.

Generator

frequency

Droop

setting

P(f)

Lim

±5%

Load

setpoint

Active

power

Load

controller

To HP

valve Selector

Pressure

controller

x

Frequency

sensitivity

on/off

Generator

frequency

Load setpoint +5%

50.00

Hz

Load setpoint -5%

Load setpoint

49.87

Hz

50.13

Hz

Annexure-3

121

of 61 Printed 2015-01-15 09:29

Figure 7. Parts of governor front panel: Speed controller (upper) and load controller

including FGMO circuitry (lower). The location of the droop control knob is

indicated with an arrow.

Annexure-3

122

of 61 Printed 2015-01-15 09:29


3.1 Definitions


equipment, SSPS.




sensor.

Actual frequency: Signal from generator frequency/speed

sensor.


System load: Total active power consumption in the

grid

Simulated system load System load simulated in the test

equipment

System base load: Start value of simulated system load when

starting the island simulation test.

Annexure-3

123

of 61 Printed 2015-01-15 09:29

3.2 Method for island operation testing

Solvina has developed a test equipment to be used for evaluation of the island

operation capability of power turbines. The equipment is called SolvSim Power

Station, SSPS.

The test method uses the principle of “HardWare In the Loop”, i.e. a simulator

simulating that a small power system is connected to the speed governor of a turbine.

The speed controller will then act as if it is actually running in island operation. The

active power produced by the turbine is measured and summed up with simulated

contributions to calculate the active power balance of the simulated island.

Gen.

Grid

Turbine

Mea

sure

d Si

gnal

s

Governor

Simulated

island

Actual Frequency

Simulated

FrequencySSPS

Relay

Figure 8: Hardware-in-the-loop simulation of island operation.

Models of loads as well as other power producers can be included in the model of the

electric island.

Using the active power balance and the total moment of inertia of the island, the

island frequency can be calculated and fed back to the speed controller of the turbine

tested. In this way, the capability of running in island operation can be tested while

the turbine is still synchronized to a strong grid.

SSPS is also used to inject simulated frequency steps for primary response tests.

On this particular unit, the connection of the simulated frequency was different from

the normal case shown above. Instead of switching between actual and simulated

frequency, the switching was made between a fixed signal corresponding to 50.00 Hz

and the simulated frequency.

Annexure-3

124

of 61 Printed 2015-01-15 09:29

3.3 Test procedure


Before commencement of actual tests, all the values/scalings of the measured signals

and the installation of the test equipment were checked to ensure correct

measurements and safe operation. The switching between the actual and the

simulated frequency was tested several times to verify a bumpless transition. The

internal safety functions of the SSPS system were also verified.


Initially, before beginning the test sequence, the simulated frequency was kept at

50Hz. The primary response was tested by injecting a frequency step to the governor

frequency input. The frequency step was calculated from the droop settings, to

produce an generated load change of up to approx. 5% of rated load.

The step tests with FGMO engaged in governor were performed at 75%, 90% and

100% of rated generated load with positive and negative steps in frequency.

3.3.3 Small island tests

This test was performed to assess the ability of the turbine to control the frequency as

sole production on an island grid. Simulated load steps of different sizes were

intended to be applied but this could not be done since the island operation was

unstable (see section 4.3). The tests were repeated at 75% and 90% generated load

with FGMO engaged in governor.

For the tests at Dadri Unit -4, Table 2 below summarizes the grid model with a total

simulated system base load of 155 and 190 MW respectively. The simulated system

load comprises frequency dependent and frequency independent loads.

Table 2 Simulator parameters for small island test.

System

Base load

Rated apparent

power (Sn) of

generator

System load with

linear frequency

characteristic

System load without

frequency

dependence, no inertia

Small

Island

@75%

155 MW 247 MVA

(Inertia 3.52 s)

70 MW

(Inertia 0.70 s)

85 MW

Small

Island

@90%

190 MW

85 MW

(inertia 0.70 s)

105 MW

Annexure-3

125

of 61 Printed 2015-01-15 09:29



together with other power plants on a local grid. All other power plants were

simulated to act according to power control. Simulated load steps of different sizes

were applied (see section 4.4) to determine the size of the load changes that the

power plant could handle.

The summary of the total simulated base load was 2000 MW. Table 3 below

summarizes the grid model. The simulated load comprises frequency dependent and

independent loads.

Table 3 Simulator parameters for large island test

Total

system

base load

Rated

apparent

power (Sn) of

generator

System load with

linear frequency

characteristic

System load

without

frequency

dependence,

no inertia

Additional

simulated

power

plants

Large

island:

2000 MW

247 MVA

(Inertia 3.52 s)

1000 MW

(Inertia 0.70 s) 1000 MW

2000 MVA

(Inertia 4.0 s)

2000 MW

Annexure-3

126

of 61 Printed 2015-01-15 09:29

3.4 Recorded signals

The following signals were recorded during the tests for analysis of the unit

performance, including the boiler and steam system:

Simulated frequency = the frequency signal injected into the governor from the test

equipment SSPS (switched between simulated signal and a fixed signal

corresponding to 50 Hz).

Active power = generated load of the unit, as measured by a transducer from PT and

CT outputs.

Frequency correction = output from limiter in Figure 5, corresponding to the load

offset added to the load setpoint

HP valve position = opening position of HP turbine steam inlet valve, which is the

main valve for controlling the steam flow to the turbine and hence also the generated

load.

IP valve position = opening position of IP turbine steam inlet valve, which is used

for controlling the pressure in the reheater. This valve is normally fully open but

closed partially during some of the tests performed (Step response 75/900/100%).

HP pressure = steam pressure before HP valve, corresponding to pressure at

overheater outlet.

IP pressure = steam pressure before IP valve, corresponding to pressure at reheater

outlet.

Feed water flow = flow of feed water into boiler. This is controlled to keep the

boiler drum level within limits.

Boiler drum level = level of water in the steam drum, should ideally be kept

constant by the feed water control.

HP bypass = opening position of valve for shunting steam past the HP turbine. The

HP bypass increases the steam consumption from the boiler without increasing the

generated load and is used for reducing the steam pressure in case of overpressure.

This valve is normally closed but opened partially during one of the tests performed

(Step response 75%).

LP bypass = opening position of valve for shunting steam past the IP and LP

turbines. This valve was closed during all of the tests performed.

Reactive power = reactive output of generator, positive corresponding to lagging

system load.

Generator voltage = AC voltage measured at generator terminal PTs.

Actual frequency = frequency of the voltage measured at generator terminal PTs.

Total Load = Simulated system load on island grid (only for island test).

Additionally, some signals were monitored for safety reasons and for facilitating

trouble shooting in case of unexpected problems. These are omitted from the list

above.

Annexure-3

127

of 61 Printed 2015-01-15 09:29

4 TEST RESULTS



Step response tests were performed at 75%, 90% and 100% of rated generated load.

FGMO works as expected and the magnitude of response is according to the droop

settings. The generated load response in the step tests corresponds to 5% droop. The

response time T67 is very fast, in the range 2-8 seconds, and it has a distinct

overshoot, all due to the settings of the load controller.

Due to slow boiler control, the changes in generated load cause a slow but large

variation in the HP steam pressure. The upper limit of steam pressure was reached

and the HP bypass valve operated during the step response tests at 75%.


The small island tests were performed at 75% and 90% load levels respectively with

a droop setting of 5% initially. The unit was unable to handle islanding operation at

both load levels. As soon as the simulated frequency was switched in, growing

oscillations occurred and the simulation was aborted. The tests were repeated with

droop setting of 8% at both load levels of 75% and 90%. The results, however,

remained unchanged. It was concluded that the unit is unable to operate during

islanding operation as sole production on the grid. This is all due to the settings of

the load controller.

The unit was capable of keeping the frequency stable on a large island grid while

using the inertia of other units for stability. System load steps of up to ±14 MW were

applied, which caused frequency deviations of only up to ±0.2 Hz.

Annexure-3

128

of 61 Printed 2015-01-15 09:29

4.2 Primary frequency response, step response tests in FGMO





For the tests in FGMO mode the droop setting during test was 5%.

Steps were carried out to give up to 5% load change, which is approx. 10.5 MW, and

the frequency step size giving that response would be 0.05*0.05*50 = 0.125 Hz.

Consequently 10.5 MW is the expected response for the steps to be carried out.

Similarly, expressed in MW/Hz, the response is expected to be 84 MW/Hz for any

step (10.5/0.125), given a rated generated load of 210 MW.


Blue Simulated frequency.

Light blue Grid frequency (equal to the generator frequency) during

test.

Red Generated load (= measured active power).

Purple HP pressure.

Green Frequency correction voltage, corresponding to the setpoint

offset sent to the load controller from the droop circuitry.

Dark blue HP valve position.

Pink IP valve position.

Orange HP bypass valve position. This signal is only seen in the

figures where the valve is active.

Annexure-3

129

of 61 Printed 2015-01-15 09:29

4.2.1 Step response in FGMO, generated load 75%, droop 5%

The step response tests were carried out at 75% generated load with 5 % droop.

Initially, some smaller steps were tested to determine the behaviour of the unit and to

check that the steps expected to cause 5 % generated load change could be handled

safely.

Table 4 Frequency steps in FGMO, generated load 75 %, droop 5%, part 1

Simulated

frequency

(Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

50 50.05 154 149 Approx.

-4.5

Approx.

90

2

(oscillating)

50.05 50 149.5 153.6 +4.1 82 3

5049.95 153.6 158 +4.4 88 3

49.9550 158 153.5 -4.5 90 4

With a droop setting of 5 %, a 0.05 Hz step is expected to cause a generated load

change of approx. 4 MW (84 MW/Hz).

Figure 9: Frequency steps in FGMO, generated load 75 %, part 1

Annexure-3

130

of 61 Printed 2015-01-15 09:29

Figure 10: Frequency steps in FGMO, generated load 75 %, part 1. The frequency

correction signal, corresponding to the load setpoint offset, is proportional to

the deviation in simulated frequency.

Figure 11: Frequency steps in FGMO, generated load 75 %, part 1. The operation of the

HP, IP valve and the HP bypass valve is shown.

The test shows that the response of the generated load to a step change in frequency

is approximately in accordance with the droop settings. The response is very fast and

there is a small overshoot in the generated load. A small oscillation in the generated

load is seen in the beginning of the figures, this coincides with the IP valve being

partially closed.

Annexure-3

131

of 61 Printed 2015-01-15 09:29

The test was continued with further steps.


Simulated

frequency

(Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

5049.95 153.4 157.8 +4.4 88 2

49.9550 158.2 153.9 -4.3 86 2

5050.1 153.9 145.3 Approx.

-8.6

Approx.

86

3

The steam pressure increases to 136 bar and the HP bypass opens, but is closed by

manual intervention. Severe oscillations in the generated load occur. The output is

then manually increased for a short time to reduce the oscillations.


change of approx. 4 MW, and, correspondingly, a 0.1 Hz step is expected to cause a

generated load change of approx. 8 MW (84 MW/Hz).


Annexure-3

132

of 61 Printed 2015-01-15 09:29





HP, IP valve and the HP bypass valve with increase in steam pressure is

shown.

Annexure-3

133

of 61 Printed 2015-01-15 09:29

The test shows that the response of the generated load is in accordance with the

droop settings. The response is very fast and there is a certain overshoot in the

generated load.

The generated load depends on the HP steam pressure and the HP valve opening. As

a result, the HP valve opening varies in proportion to the generated load and in

reverse proportion to the HP steam pressure.

A small oscillation in the the HP and IP valves, and consequently also in the

generated load, in the beginning of the figures. This coincides with the IP valve

being partially closed. Later on, an larger oscillation is seen. The oscillation is

probably related to the tuning of the load controller. Frequency steps are seen by the

load controller as load setpoint steps since the droop calculation is a simple gain

function. The load controller has a very fast step response with a distinct overshoot in

the and a response time T67 of only a few seconds, to be compared to Dadri II unit 6

which has a response time T67 of 15-85 seconds and no overshoot. The overshoot

indicates a small stability margin and in that situation an increased total closed loop

gain or an additional delay can make the system unstable. It appears that the

operation if the IP valve causes either one (or possibly both) of these. The gain in the

load controller will have to be reduced significantly to ensure stable operation also in

a situation when the IP valve is active.

After the step 5050.1 Hz, the steam pressure increases steadily due to the slow

boiler control and reaches the upper limit. At approx. 136 bar, the HP bypass valve

operates to reduce the excess pressure. When the bypass is closed through manual

intervention, the oscillation grows drastically. Figure 15 shows the sequence in more

detail. The oscillation does not stop until the load is increased manually.

Figure 15: Zoom-in on previous figure. The operation of the HP, IP valve and the HP

bypass valve with increase in steam pressure is shown.

Annexure-3

134

of 61 Printed 2015-01-15 09:29

When the generated load oscillated, severe oscillations were seen also in reactive

power and generator voltage, which were being monitored during the tests. Most

likely, it is the power system stabiliser (PSS) that causes these effects. The PSS

cannot sufficiently filter out the load changes caused by variations in the turbine

torque and therefore respond to these in a similar way as it responds to the power

oscillations that it is intended to counteract.

Figure 16: Active and reactive power during the oscillation of generated load shown in

previous figure.

Annexure-3

135

of 61 Printed 2015-01-15 09:29

After the oscillations have been successfully stopped, the steam pressure decreases

steadily. The generated load depends on the HP steam pressure and the HP valve

opening. As a result, the HP valve opening varies in proportion to the generated load

and in reverse proportion to the HP steam pressure. Consequently, the HP valve

keeps opening to maintain the generated load. After around 10 minutes, the pressure

is so low that the HP valve has opened fully, and the generated load drops slightly.

As soon as the pressure starts increasing the HP valve begins to close to balance the

load at 154 MW. The sequence is shown in Figure 18. During all this time the

simulated frequency is kept at 50.1 Hz.

Figure 17: Frequency steps in FGMO, generated load 75 %. The 50.1 step is maintained

between part 2 and 3. The operation of the HP, IP valve and the HP bypass

valve with decrease in steam pressure is shown.

Annexure-3

136

of 61 Printed 2015-01-15 09:29



Simulated

frequency

(Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

50.150 155 163 +8 80 3

5050.1 163 155 -8 80 2

50.150 154 163 +9 90 2

Load setpoint changed back to 154 MW.

5049.90 155 164 +9 90 6

49.9050 165 156 -9 90 7



Figure 18: Frequency steps in FGMO, generated load 75 %, part 3. At 10200 s the load

setpoint is increased manually.

Annexure-3

137

of 61 Printed 2015-01-15 09:29





HP and IP valve along with steam pressure and the generated load is shown.



generated load.

Annexure-3

138

of 61 Printed 2015-01-15 09:29

The test was continued with further steps. With a droop setting of 5 %, a 0.125 Hz

step is expected to cause a generated load change of approx. 11 MW (84 MW/Hz).

For practical reasons the magnitude of the applied frequency step was rounded to

0.13 Hz.

Table 7 Frequency steps in FGMO, generated load 75%, droop 5%, part 4

Simulated

frequency (Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

5050.13 156 145 -11 85 3

The steam pressure increases to 125 bar and the HP bypass opens, but is the closed

by manual intervention. Severe oscillations in the generated load occur. The output

is then manually increased to reduce the oscillations.


change of approx. 11 MW. For practical reasons the magnitude of the applied

frequency step was rounded to 0.13 Hz.


Annexure-3

139

of 61 Printed 2015-01-15 09:29





HP,IP and HP bypass valve during the excess steam pressure is shown.

Annexure-3

140

of 61 Printed 2015-01-15 09:29



reverse proportion to the HP steam pressure. The step change from 5050.13 Hz

causes the HP valve to close in order to reduce the generated load according to the

droop settings. However, the closing of the HP valve and the slow boiler control

causes an increase in the steam pressure, which in turn makes the HP valve close

even more. On reaching the upper limit at approx. 124 bar, the HP bypass opens to

lower the excess steam pressure. During the operation of the bypass valve, an

oscillation is seen in the the HP and IP valves, and consequently also in the generated

load. The oscillation is shown in detail in Figure 24.

The occurence of the oscillation at the time the bypass valve opens does not

automatically imply that it is the bypass valve that causes the oscillation. More

likely, it is related to the IP valve operation together with the the load controller, as

discussed previously (for example, see Figure 15).

The bypass valve is closed through manual intervention and the oscillation is

stopped. The steam pressure still continues to increase and reaches approx. 127 bar.

To control the pressure, the generated load is increased manually for a few minutes

(seen as repeated steps in the figures above).

Figure 24: Zoom-in on previous figure. The operation of the HP, IP valve and the HP

bypass valve with increase in steam pressure is shown.

Once again, when the generated load oscillated, severe oscillations were seen also in

reactive power and generator voltage, which were being monitored during the tests.

the magnitude was simlar to that in Figure 16.

Annexure-3

141

of 61 Printed 2015-01-15 09:29


Table 8 Frequency steps in FGMO, generated load 75%, droop 5%, part 5

Simulated

frequency (Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

50.1350 145 156 +11 85 4

5050.13 155 145 -10 77 6

50.1350 145 156 +11 85 3

5049.87 156 167 +11 85 5

49.8750 167 156 -11 85 6


change of approx. 11 MW. For practical reasons the magnitude of the applied

frequency step was rounded to 0.13 Hz (84 MW/Hz).


Annexure-3

142

of 61 Printed 2015-01-15 09:29




Figure 27: Frequency steps in FGMO, generated load 75 %, part 5.The operation of the

HP and IP valves is shown along with the generated load.

Annexure-3

143

of 61 Printed 2015-01-15 09:29



generated load.

It can be concluded that despite the slow response from the boiler, the unit is still

able to maintain the level of the generated load and the results are in accordance with

the droop settings.

The overshoot in the response of the generated load for the last two steps is shown in

detail in Figure 28. As seen in Figure 26, the frequency correction signal that

corresponds to the load setpoint offset has no overshoot. The overshoot is instead

caused by a very high proportional gain setting in the load controller.

Figure 28: Zoom-in on previous figure. The operation of the HP valve is shown along

with the generated load.

Annexure-3

144

of 61 Printed 2015-01-15 09:29


The tests in FGMO mode were carried at 90% generated load with droop 5%. The

result is shown in Figure 29 and Figure 30.


Simulated

frequency

(Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant,

T67 (s)

5050.05 190 185.4 -4.6 92 5

50.0550 185.5 190 +4.5 90 4

5049.87 190 200 +10 77 6

49.8750 200 190 -10 77 8


change of approx. 4 MW and a 0.13 Hz step is expected cause a generated load


The test was continued with further steps. The result is shown in Figure 31 and

Figure 32.


Simulated

frequency

(Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant,

T67 (s)

5050.13 190 179 -11 85 4

50.1350 179 190 +11 85 3

With a droop setting of 5 %, a 0.13 Hz step is expected cause a generated load

change of approx. 11 MW.

The response of the frequency correction signal is similar to the one seen at 75%

generated load and is therefore omitted here.

Annexure-3

145

of 61 Printed 2015-01-15 09:29

Figure 29: Frequency steps in FGMO, generated load 90 %, part 1.





generated load. No major problems related to the steam pressure are seen.

Annexure-3

146

of 61 Printed 2015-01-15 09:29







Annexure-3

147

of 61 Printed 2015-01-15 09:29


The same procedure as above tests is repeated at 100 % generated load. The result is

shown in Figure 33 and Figure 34.Figure 33: Frequency steps in FGMO,

generated load 100 %, part 1.

Table 11 Frequency steps in FGMO, generated load 100 %, droop 5%, part 1.

Simulated

frequency (Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

5050.05 211.2 207.3 -3.9 78 6

50.0550 207.6 211.8 +4.2 84 5

50 50.13 211.5 201 -11 85 6

50.1350 201 211 +11 85 5


change of approx. 4 MW and a 0.13 Hz step is expected cause a generated load


The test was continued with further steps. The result is shown in Figure 35 and

Figure 36.

Table 12 Frequency steps in FGMO, generated load 100 %, droop 5%, part 2.

Simulated

frequency (Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

5049.87 211 218 +7* 54 -

49.8750 218 211 -7* 54 -

5049.87 211.9 222.4 +10.5 80 7

49.8750 222 211 +10.5 80 8

*) Due to insufficient steam pressure



reverse proportion to the HP steam pressure. At the first step 5049.87 Hz, the

steam pressure is low and drops further as the generated load is being increased.

Since the steam pressure is insufficient to produce the desired generated load, the HP

valve opens to its maximum, but still without fully reaching 105 % generated load.

At the instant of the step back to 50 Hz, the HP valve takes some time to close from

the fully open position, causing a delayed response.

The steam pressure is allowed to increase before the second attempt.

The response of the frequency correction signal is similar to the one seen at 75%

generated load and is therefore omitted here.

Annexure-3

148

of 61 Printed 2015-01-15 09:29


Figure 34: Frequency steps in FGMO, generated load 100 %, part 1. The operation of

the HP and IP valves is shown along with the generated load.




Annexure-3

149

of 61 Printed 2015-01-15 09:29


Figure 36: Frequency steps in FGMO, generated load 100 %, part 2. The operation of

the HP and IP valves is shown along with the generated load.


droop settings, provided that there is sufficient steam production. The response is

very fast and there is a certain overshoot in the generated load.

Annexure-3

150

of 61 Printed 2015-01-15 09:29

4.2.4 Notes concering island operation

The different effects seen in the step response tests above could have serious effects

if they occured during island operation.

The intervention of the pressure controller makes the load/frequency controller

unable to control the frequency. The island grid would most likely collapse in this

case and the unit trip unless immediate (within seconds) load shedding of correct size

is made. The same goes for the case when the HP valve opens fully due to

insufficient steam pressure.

The opening of the HP bypass valve would however not have such dramatic

consequences. Since the HP valve is still controlled by the load/frequency controller,

the frequency of the grid would only suffer a minor disturbance.

The oscillations seen in some situations would in themselves not be a big problem as

long as they are sufficiently small, although the island grid frequency would

fluctuate. Large oscillations would cause excessive grid frequency deviations and

the island grid would most likely collapse in this case and the unit would trip. It

must be remembered that it will not be possible to manually adjust the generated

load at the power plant during island operation as sole production. The generated

load will then always be equal to the system load in the island grid.

Annexure-3

151

of 61 Printed 2015-01-15 09:29

4.3 Island operation tests – Small island

This test shows the ability of the plant to control the frequency when the tested unit

is the only generating source of the system. By simulating system load changes of the

simulated island, the simulated frequency will change. The tested unit will try to

control the simulated frequency. This way, it can be seen if the unit is stable. Ideally,

balance between generated load and system load will be reached quickly and the

frequency will stabilise.

However, for this unit, the frequency control was not stable enough for the unit to

operate as the only generating source of the system. As soon as the simulation was

started, a quickly growing oscillation started and the simulation had to be aborted

before any simulated system load steps could be applied.

It was decided that the tests would be made at 75% and 90% load. The tests were

made with droop settings of 5%, but also a droop of 8% was tested to determine

whether this would improve the stability due to a lower total system gain. This was

not the case. It was, for safety reasons, not possible to test any other governor

settings to improve the performance while the power plant was running.


Blue Simulated frequency. This denotes the grid frequency in

real Island operation.

Light blue Grid frequency (equal to the generator frequency) during

test.

Red Generated load (= measured active power). This denotes

the mechanical turbine load in real island operation.

Purple HP pressure

Green Frequency correction voltage, corresponding to the setpoint

offset sent to the load controller from the droop circuitry.

Dark blue HP valve position

Pink IP valve position

Dark green Simulated system load

Note that the time scale of the island test figures is zoomed in compared to the

figures for step response tests.

Since the simulated load is partially frequency dependent, it will deviate from the

final value when the frequency is not equal to 50 Hz. This has a small stabilizing

effect on the simulated island grid, although in this case far from enough to keep the

operation stable.

Annexure-3

152

of 61 Printed 2015-01-15 09:29

4.3.1 Small Island test, generated load 75%, droop 5%

The test was carried out at 75% of rated generated load and with 5% droop. As soon

as the simulation was started, a growing oscillation began. The simulation was

aborted to avoid excessive load swings and no simulated system load steps were

applied.

Figure 37: Small Island test, generated load 75%, droop 5%. The simulation is started at

A and aborted at B.

A B

Annexure-3

153

of 61 Printed 2015-01-15 09:29

Figure 38: Small Island test, generated load 75%, droop 5%. The frequency correction,

corresponding to the load setpoint offset, is proportional to the deviation in

simulated frequency but is limited at 0.4 volts.

Figure 39: Small Island test, generated load 75%, droop 5%. The operation of the HP

and IP valves is shown along with the generated load.

It was concluded that the unit could not handle islanding operation as the sole

production on the grid.

Annexure-3

154

of 61 Printed 2015-01-15 09:29

4.3.2 Small Island test, generated load 75%, droop 8%

The test above was repeated with 8% droop. Also in this case, a growing oscillation

began a soon as the simulation was started, but at a somewhat slower rate. The

simulation was aborted to avoid excessive load swings and no simulated system load

steps were applied.


A and aborted at B.

A B

Annexure-3

155

of 61 Printed 2015-01-15 09:29






It was concluded that an increased droop to 8 % was not sufficient to achieve stable

island operation.

Annexure-3

156

of 61 Printed 2015-01-15 09:29

4.3.3 Small island – generated load 90%, droop 5%

The test was carried out also at 90% of rated generated load and with 5% droop. As

soon as the simulation was started, a growing oscillation began. The simulation was

aborted to avoid excessive load swings and no simulated system load steps were

applied.


A and aborted at B, after which the simulated frequency is ramped back.

A B

Annexure-3

157

of 61 Printed 2015-01-15 09:29






It was concluded that the unit could not handle islanding operation as the sole


Annexure-3

158

of 61 Printed 2015-01-15 09:29

4.3.4 Small island – generated load 90%, droop 8%

The test above was repeated with 8% droop. Also in this case, a growing oscillation

began a soon as the simulation was started. The simulation was aborted to avoid

excessive load swings and no simulated system load steps were applied.


A and aborted at B.

A B

Annexure-3

159

of 61 Printed 2015-01-15 09:29



simulated frequency.



It was concluded that an increased droop to 8 % was not sufficient to achieve stable

island operation.

Annexure-3

160

of 61 Printed 2015-01-15 09:29

4.4 Island operation tests – Large island


together with other power plants on a local grid with a total production of approx.

2000 MW. The summary of the simulated base load is described in section 3.3.4. The

large island tests were performed at 90% of rated generated load. Simulated system

load steps were applied and the frequency deviations were recorded. The droop

setting during test was 5%. Figures for all steps except the two first are presented

below.

Table 13 Simulated large island operation, generated load 90 %, all applied steps.

Total range of

generated load

(MW)


step (MW)

Max. frequency

deviation, Δf (Hz)*

190-202 MW

+5 MW -0.06

-5 MW +0.06

+10 MW -0.12

-10 MW +0.12

+12 MW -0.15

-12 MW +0.15

+14 MW -0.18

-14 MW +0.20

*Please note: All frequency deviations are measured from the instant the step is

applied.

For convenience, the simulated system load is shown using the same scale as the

generated load. For this reason, an offset of 1840 MW (being the total output of the

other simulated power plants) has been subtracted from the simulated system load

curve.

Annexure-3

161

of 61 Printed 2015-01-15 09:29

Figure 49: Simulated large island operation, generated load 90 %, load steps ±10 MW.

The simulated system load has an offset of 1840MW subtracted.


The frequency correction, corresponding to the load setpoint offset, is

proportional to the deviation in simulated frequency. No limit is reached.

Annexure-3

162

of 61 Printed 2015-01-15 09:29


HP pressure, HP bypass valve, HP valve are shown together with the

generated load.

Annexure-3

163

of 61 Printed 2015-01-15 09:29





proportional to the deviation in simulated frequency but is limited at 0.4 volts.

Thie limit is reached only briefly.

Annexure-3

164

of 61 Printed 2015-01-15 09:29



generated load.

Annexure-3

165

of 61 Printed 2015-01-15 09:29





proportional to the deviation in simulated frequency but is limited at 0.4 volts.

The signal is at the limit as long as the load step is maintained.

Annexure-3

166

of 61 Printed 2015-01-15 09:29



generated load.

The test shows that the unit responds well to a load steps on a large grid, and thanks

to the large total inertia it is able to keep the frequency stable. The stability margin is

however relatively small. This is seen in the oscillatory behaviour when the

frequency correction signal is not in limitation. The largest simulated load steps

applied were ±14 MW, causing a maximum frequency deviation of ±0.2 Hz. The test

was halted after these steps as they were estimated to be at the limit of what the unit

could handle.

The response of the unit is limited to around 5 % of rated generated load. This

limitation is seen clearly in the figures showing the frequency correction signal after

the +12 and +14 MW steps. After the step of +14 MW, the generated load is held

back continuously by this limit and it is the frequency denendence of the simulated

grid that prevents the frequency form dropping further. A slightly larger load step

would have caused a significantly larger frequency deviation, as was seen during the

tests at Dadri II unit 6 which has a similar type of limitation.

The steam pressure fluctations were relatively small during the test.

Annexure-3

167

of 61 Printed 2015-01-15 09:29

5 CONCLUSIONS

5.1 FGMO

FGMO works as expected and the magnitude of response is approx. according to the

droop settings. The generated load response in the step tests corresponds to 5 %

droop. The response time T67 is very fast, in the range 2-8 seconds, and it has a

distinct overshoot. This is due to the settings of the load controller. The load

controller is also the cause for that the load control system itself started oscillating

under certain conditions when the IP valve was active.

Due to slow boiler control, the changes in generated load cause a slow but large

variation in the HP steam pressure. The upper limit of steam pressure was reached

and the HP bypass valve operated during the step response tests at 75%. The load

control system itself started oscillating under certain conditions when the IP valve

was active.

In order to safely operate the plant in FGMO while connected to the national grid and

without manual interventions, the boiler control will have to be revised and the load

controller will require improved tuning.

5.2 ISLAND OPERATION

5.2.1 Small Island test:

The small island tests were performed at 75% and 90% load levels respectively with

a droop setting of 5% initially. The unit was unable to handle islanding operation at

both load levels. As soon as the simulated frequency was switched in, growing

oscillations occurred and the simulation was aborted.

The tests were repeated with droop setting of 8% at both load levels of 75% and

90%. The results, however, remained unchanged and the simulation was aborted.

Unfortunately, it was for safety reasons not possible to test any other governor

settings to improve the performance while the power plant was running.

It was concluded that the unit is unable to operate during islanding operation as sole



The unit was capable of keeping the frequency stable on a large island grid while

using the inertia of other units to for stability. System load steps of up to ±14 MW

were applied, which caused frequency deviations of only up to ±0.2 Hz.

Annexure-3

168

of 61 Printed 2015-01-15 09:29

6 RECOMMENDATIONS

The results from the tests were analyzed to see what could further be done to

improve the performance. In this section some recommendations are presented.


The tuning of the load controller will have to be revised for stable operation in

FGMO. At present, the gain is very high and severe oscillations have been observed

in conditions when the IP valve is active. The gain should be reduced at least as

much as is necessary to provide stable load control in all steam system conditions,

which probably means a reduction by 50 % or more. The integration time and other

parameters may also need adjustment. Normally, the gain set to give a moderately

slow response with a time constant T67 being tens of seconds or even a few minutes.

The boiler control is in its present state ill fitted running the unit in FGMO or any

other control mode in which anything else than the steam pressure controls the HP

valve. The pressure fluctuates severely just from load changes of 5 %. Boiler control

is slow by nature but it should be possible to improve stability by using

1. a feed-forward function so that the fuel input is increased already when the

generated load is increased, instead of when the pressure has dropped.

2. improved control parameter tuning.

Also the governor limit of ±5 % affects the ability to operate in FGMO. With a droop

of 5 %, the generated load will be at its upper limit for a grid frequency of 49.87 Hz

and at its lower limit at 50.13 Hz. The grid frequency, however, is at present varying

between 49.7 and 50.3 Hz. With a droop of 5 %, this corresponds to load variations

of ±12.5 %, which would very difficult for the steam system to handle if the

variations are fast. The governor limit is thus probably necessary to limit the stress

on the steam system, but if the boiler control is improved it could probably be

extended somewhat. Nevertheless, for successful FGMO operation, assuming that a

quick response is required, it may be a good idea to increase the droop. The response

for a given frequency change would be smaller but the response would be present in

a larger frequency range.

It should however be considered that thermal units such as this should not participate

in the short term frequency control of the grid (using FGMO) other than in grid

emergency situations, but rather in the long term frequency control (using RGMO in

combination with Co-ordinated mode control such as it is implemented here), for

which the unit is better adapted.


Load controller tuning is necessary also if island operation as sole production on a

grid is desired. The present parameters make it impossible to achieve stable island

operation. The gain reduction required can be determined for example by simulated

island tests as the one performed, or by simulations provided that sufficient model

data can be obtained. The best path would however be to perform this tuning at the

time of commissioning of the new control system that is scheduled in a year.

Annexure-3

169

of 61 Printed 2015-01-15 09:29

Furthermore, a digital controller makes it possible to arrange a special control mode

for islanding which can be tuned without affecting the load control of normal

operation. This mode may, but does not have to be, the same as the FGMO for grid

connected operation.

The same issues with the boiler control that are described above apply also during

islanding conditions, but the consequences of being unable to maintain the steam

pressure will be much worse. The most important issue during island operation as the

sole prodution on a grid is that the steam pressure must never be allowed to drop so

low that the generated load is reduced by the pressure control. In that case the island

grid will collapse and the unit will probably trip. When operating in islanding

together with other units on a large island grid, the task of frequency control would

be placed on the other units. Overpressure, on the other hand, can be handled by the

bypass valves and is not such a big problem in itself, provided that the steam system

remains stable.

If load controller tuning (or FGMO/island mode implementation) is successful, it

will be the steam system that puts the limit for how large island loads that can be

connected at a time. The frequency control itself would be capable of handling

relatively large load changes on an island grid, provided that the governor limit of ±5

% is sufficiently extented. It can anyway be assumed that the controller will have be

significantly slower to enable stable island operation. It is therefore estimated that the

limit should be at least in the order of ±10 % during island operation to handle a grid

load change of ±5 % well.

As always during island operation, it will be the responsibility of the grid operator to

keep the size of the load connections sufficiently small for the power plant to handle,

and communication between the grid operator and the power plant operator will be

necessary to ensure that the power plant, especially considering the steam system

conditions, is ready each time more load is to be connected to the island grid.

After a load is connected to (or disconnected from) the island grid, and the frequency

has stabilised, the stationary frequency will be different from 50 Hz due to the droop.

It will then be necessary to bring the frequency back to 50 Hz by adjusting the load

setpoint to be equal to the generated load at the time, thereby ensuring that the

stationary frequency does not get too close to the governor limit, outside which there

is no further response to frequency variation. The wider the limit is, the easier this

handling will be.

In an emergency situation requiring island operation, one possible way of keeping

the steam system parameters within limits could be to manually set the boiler output

slightly higher than the steam flow required for a generated load equal to the highest

expected island grid load at the time, thereby ensuring that the steam pressure never

drops too low to provide the required generated load. The resulting overproduction of

steam would then have to be handled by the bypass valves to keep the pressure

within limits, which of course requires stable bypass control. This way of operating a

unit has been successfully tested at simulated island tests on at least one thermal unit

in Sweden.

For best frequency stability during islanding, especially in a situation where the unit

is the sole production on an island grid, the feedback signal to the load controller

should not be the measured active power, but a signal corresponding to the active

power but calculated from the HP valve position (with adjustment for HP steam

Annexure-3

170

of 61 Printed 2015-01-15 09:29

pressure and possibly other parameters). This applies for islanding only and is best

handled by a software function that automatically changes the feedback type in case

of islanding, and possibly also the governor limit from ±5 % to a suitable higher

value. This will however require a digital governor.

Finally, it is recommended that the PSS is disabled during island operation. It is not

useful in island operation but instead causes unnecessary voltage fluctuation that

could disturb the grid.

Annexure-3

171

of 61 Printed 2015-01-15 09:29

7 REFERENCES


19/08/2014

[2] Test Program – 2014 018-11-1.0 Dadri II

Annexure-3

172



Valid date




1 (23) Author

Shweta Tigga, Niclas Krantz

Reviewed Niclas Krantz

Bengt Johansson

Approved Niclas Krantz

Title

2014018-29-1.0 Testing of Primary Response of Bawana.docx

Distribution

Nodal officers PPCL, POSOCO

SUMMARY

This document presents the results of primary response tests of a 216 MW gas turbine unit #2 at

Bawana Power Plant, India, conducted on 24th

November 2014. The tests were carried out with a

built in step response function by GE and witnessed by Solvina, and the signals were recorded as

decided in the meeting held on 24.10.2014 [3].


Solvina International. Tests show that FGMO works as expected and that FGMO can be used to

support the control of grid frequency in interconnected mode.

The following tests were performed:

Step response tests in FGMO mode: The steps tests were performed at 75%, 90% and 100% of

rated generated load with a droop setting of 4%. The generated load response in the step tests

corresponds well to the droop setting. The response time T67 is in the range 3-10 seconds. The

frequency control in itself operates in a stable manner.

Annexure-3

173

of 23 Printed 2015-01-15 11:05

CONTENTS


2 DESCRIPTION OF TESTED UNIT ............................................................ 6 2.1 Basic unit data .................................................................................................. 6 2.2 Operation principle of Gas based plants ........................................................... 7

3 DESCRIPTION OF TESTS PERFORMED .............................................. 10 3.1 Definitions ...................................................................................................... 10 3.2 Method for step response tests ....................................................................... 10 3.3 Test procedure ................................................................................................ 11 3.3.1 Test equipment/function/signal check ............................................................. 11

3.3.2 Step response tests .......................................................................................... 11

4 RECORDED SIGNALS ............................................................................... 12

5 TEST RESULTS ........................................................................................... 13 5.1 Executive summary ........................................................................................ 13 5.1.1 Primary frequency response ........................................................................... 13 5.1.2 Island operation .............................................................................................. 13 5.2 Primary frequency response, step response tests in FGMO ........................... 13 5.2.1 Step response in FGMO, generated load 70%, droop 4% ............................. 14 5.2.2 Step response in FGMO, generated load 90%, droop 4% ............................. 16 5.2.3 Step response in FGMO, generated load 100%, droop 4% ........................... 18

6 CONCLUSIONS ........................................................................................... 21 6.1 Step response in FGMO ................................................................................. 21 6.2 Island Operation ............................................................................................. 21


8 REFERENCES ............................................................................................. 23

Annexure-3

174

of 23 Printed 2015-01-15 11:05

REVISION RECORD

Rev.

No.

Date Section Cause Revised

by

Distributed to

1.0 2014-01-12 All Report submitted. NKr POSOCO, Pragati Power

Annexure-3

175

of 23 Printed 2015-01-15 11:05

1 INTRODUCTION

1.1 Background










Primary Frequency Response in normal operation under Free Governor Mode

of Operation (FGMO).


corresponding to islanded conditions in “small island” (one unit) and “large

island” (2000MW system load).







This report is for the primary frequency response tests conducted on a 216 MW gas

turbine unit-2, at Bawana Power station.

Due to the inability of the plant OEM, GE, to prepare a software switch in the

governor for connection of a simulated signal as agreed, the test equipment SSPS

could not be connected, and the tests could not be carried out as agreed.

Hence, on request from POSOCO, Solvina agreed to still carry out the step response

tests using the governor built-in function for step responses.

Annexure-3

176

of 23 Printed 2015-01-15 11:05

1.2 Tests performed

The following tests were carried out at Bawana as per the test program [2]:

24th

Nov 2014 Test equipment/function/signal check


function check.

Step Response tests

Step response tests at 75%, 90% and 100% of rated generated load

under FGMO mode.

Annexure-3

177

of 23 Printed 2015-01-15 11:05


The total installed capacity of Bawana is 1500 MW. It comprises 4 gas turbine units

of 250 MW each. The power plant also has 2 steam turbine units of 250 MW each.

2.1 Basic unit data

Table 1: Basic data Bawana power ststation

Turbine Type BHEL, 9 FA advance class GT

Speed 3000 rmp

Generator Make BHEL

Rating 216 MW (250MVA)

Governor Make Mark VI, GE

Type Digital

Annexure-3

178

of 23 Printed 2015-01-15 11:05

2.2 Operation principle of Gas based plants

A Gas power plant is based on the principle of Brayton cycle. Figure 1 show the

processes involved in a Brayton cycle. In a simple gas turbine plant the main

components are namely; compressor, combustion chamber and the turbine. The

ambient air is first compressed in a compressor from Step 12, thereby increasing

the pressure, which requires some input energy. From step 23, the compressed air

is mixed with the fuel and combustion takes place in a combustion chamber at

constant pressure. The resulting hot gases after combustion are allowed to pass

through a turbine, thereby generating power (step 34). In the case of an open

system, the exhaust gases are not reused and released to the atmosphere (step 41).

Figure 1: The principle of gas based plants (open cycle)

The efficiency of the plant can further be increased by utilizing the high temperature

of the exhaust gases coming out of the turbine in a gas turbine-steam turbine cycle,

known as a combined cycle arrangement. In the case of combined cycle plants (see

Figure 2), the exhaust gases from the outlet of the turbine are used further to generate

steam in a heat recovery boiler. The steam is then used to drive a turbine, thereby

generating electricity.

Combustion

Chamber

CompressorGas

Turbine

FuelFuel

Ambient airAmbient air

GasesGases

AmbientAmbient

AirAir2

2

11

33

44

~

Exhaustgases

Exhaustgases

Annexure-3

179

of 23 Printed 2015-01-15 11:05

Figure 2: Principle of combined cycle plants.

This combination of gas turbine- steam turbine utilizes two thermodynamic cycles;

gas turbine operating by the Brayton cycle (as explained for open cycle) and steam

turbine operating by the Rankine cycle. The main difference between these two

cycles is that the working medium in a gas turbine is air and in a steam turbine, the

working fluid is steam.

A steam turbine in a thermal power plant is based on the principle of Rankine cycle.

Figure 3 shows the processes involved in a Rankine cycle. The water is first pumped

from Step12 which requires little input energy. From step 23, the water at high

pressure is heated in a boiler at constant pressure by an external heat source which

turns it into steam. The steam is then allowed to expand in a turbine, thereby

generating power (step 34). The steam is then allowed to condense to water in a

condenser at constant pressure (step 41) and the same process repeats.

Combustion

Chamber

CompressorGas

Turbine

FuelFuel

Ambient airAmbient air

GasesGases

ExhaustGases

ExhaustGases

AirAir2

2

11

33

44

~

Heat

recovery

boiler~

Steam

Turbine

Steam

Annexure-3

180

of 23 Printed 2015-01-15 11:05

Figure 3: Principle of thermal power plants with steam turbines.

Vaporizer

Condenser

P

ExpanderPump

1

2

3

4

Annexure-3

181

of 23 Printed 2015-01-15 11:05


3.1 Definitions


equipment, SSPS.




sensor.

Grid frequency: Signal from generator frequency/speed

sensor.


3.2 Method for step response tests

The Step response tests were executed by GE on the system and the signals were

provided to Solvina for recording as per the signal list given in section 4.

For performing the step tests, the grid frequency signal was replaced with the GE

simulated frequency signal. After application of each step, the simulated frequency

was switched back to the grid frequency.

The test was carried out in the same manner as in the previous units tested, with

frequency steps giving around 5% generated load change, at 70%, 90% and 100%

generated load.

The built-in test function is described in [4].

Annexure-3

182

of 23 Printed 2015-01-15 11:05

3.3 Test procedure


Before commencement of actual tests, all the values/scaling of the measured signals

and the connections to the test equipment were checked to ensure correct

measurements. The frequency steps were applied using a built-in tests function of the

governor by GE and the same were verified with the recorded signals.


Initially, before beginning the test sequence, the GE simulated frequency was kept

same as the grid frequency. The primary response was then tested by applying a

simulated frequency step to the governor frequency input. The frequency step was

calculated from the droop settings, to produce a generated load change of up to

approx. 5% of rated load.

The step tests with FGMO engaged in governor were performed at 70%, 90% and

100% of rated generated load with positive and negative steps in frequency.

Annexure-3

183

of 23 Printed 2015-01-15 11:05

4 RECORDED SIGNALS

The following signals were recorded during the tests for analysis of the power plant

performance:

Simulated frequency = the frequency signal injected into the governor from the test

equipment SSPS.

Active power = generated load of the unit, as measured by a transducer from PT and

CT outputs.

Generator voltage = AC voltage measured at generator terminal PTs.

Generator frequency = frequency of the voltage measured at generator terminal

PTs. This is equal to the grid frequency.

Annexure-3

184

of 23 Printed 2015-01-15 11:05

5 TEST RESULTS



Step response tests were performed at 70%, 90% and 100% of rated generated load.

The tests were conducted according to the built-in tests function of the governor. The

frequency steps were carried out as per the GE test procedure [4]

FGMO works as expected and the magnitude of response is approx. according to the

droop settings. The generated load response in the step tests corresponds to 4%

droop. The response time T67 is in the range 3-10 seconds, measured for steps

causing a change in generated load equal to 5 % of rated load.


The islanding operation tests were not performed as discussed in minutes of the

meeting [2] and [3].

Although the unit is able to maintain stable operation during primary frequency

response tests, it can however, not be concluded that it can operate during islanding

conditions without specific testing.

5.2 Primary frequency response, step response tests in FGMO





For the tests in FGMO mode the droop setting during test was 4%.

Steps were carried out to give up to 5% load change, which is approx. 11 MW, and

the frequency step size giving that response would be 0.05*0.04*50 = 0.1 Hz.

Consequently 11 MW is the expected response for the steps to be carried out.

Similarly, expressed in MW/Hz, the response is expected to be 110 MW/Hz for any

step.

Annexure-3

185

of 23 Printed 2015-01-15 11:05


The step response tests were carried out at 70% generated load with 4 % droop.


change of approx. 11 MW.

Table 2 Frequency steps in FGMO, generated load 70 %, droop 4%, Part 1

Simulated

frequency

(Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change , ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

5049.90 149.3 161.2 +11.9 119 9

49.9050 161.2 149.6 -11.6 116 3

Figure 4: Frequency steps in FGMO, generated load 70%, droop 4%, Part 1

Annexure-3

186

of 23 Printed 2015-01-15 11:05

Table 3 Frequency steps in FGMO, generated load 70%, droop 4%, Part 2

Simulated

frequency

(Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change , ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

5050.1 149.4 137.3 -12.1 121 5

50.150 137.1 149.6 +12.5 125 6

Figure 5: Frequency steps in FGMO, generated load 70%, droop 4%, Part 2

In the simulated step tests conducted by GE, the simulated frequency was switched

back to the grid frequency after reaching 50 Hz.

From the above figure we can see that with the application of the frequency steps, the

response of the generated load is immediate. The response is also in approx.

accordance with the droop setting.

Annexure-3

187

of 23 Printed 2015-01-15 11:05


The tests in FGMO mode were carried at 90% generated load with droop 4%. As

before, with a droop setting of 4 %, a 0.1 Hz step is expected to cause a generated

load change of approx. 11 MW.


Simulated

frequency

(Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change ,

ΔP (MW)

MW

contribution

(MW/Hz)

Time

constant,

T67 (s)

5049.90 194.3 206.5 +12.2 122 6

49.9050 206 193.7 -12.3 123 4

Figure 6: Frequency steps in FGMO, generated load 90 %, droop 4%, Part 1

Annexure-3

188

of 23 Printed 2015-01-15 11:05


Simulated

frequency

(Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change ,

ΔP (MW)

MW

contribution

(MW/Hz)

Time

constant,

T67 (s)

50 50.1 194.2 182.6 -11.6 116 3

50.150 182 194.8 +12.8 128 5


It can be seen that with the application of the frequency steps, the response of the

generated load is immediate. The response is also approximately in accordance with

the droop setting.

Annexure-3

189

of 23 Printed 2015-01-15 11:05


The same procedure as above tests was repeated at 100 % load. As before, with a

droop setting of 4 %, a 0.1 Hz step is expected to cause a generated load change of

approx. 11 MW.


Simulated

frequency (Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change , ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

50 49.90 215.4 224.5 +9.1 91 7

49.90 50 224.6 215.1 -9.5 95 5

50 50.1 214.5 203.3 -11.2 112 10

50.150 203.2 215.1 +11.9 119 7


Annexure-3

190

of 23 Printed 2015-01-15 11:05

Figure 9: Frequency steps in FGMO, generated load 100 %, droop 4%, Part 1 (Showing

the interval 370 – 470 seconds)

Figure 10: Results received from GE show the interval of during oscillations.

For the step change in frequency from 50 49.90 Hz, certain oscillations are seen in

the generated load response. The oscillations in the generated load as shown in

Figure 9 and Figure 10 are likely caused due to the power system stabiliser (PSS)

Annexure-3

191

of 23 Printed 2015-01-15 11:05

that causes these effects. The PSS cannot sufficiently filter out the load changes

caused by variations in the turbine torque and therefore responds to these in a similar

way as it responds to the power oscillations that it is intended to counteract.


Simulated

frequency (Hz)

Initial

generated

load (MW)

Post step

generated

load (MW)

Gen. load

change , ΔP

(MW)

MW

contribution

(MW/Hz)

Time

constant

T67 (s)

50 50.1 214.5 203.3 -11.2 112 10

50.150 203.2 215.1 +11.9 119 7


The overall response of the unit is approximately in accordance with droop.

Annexure-3

192

of 23 Printed 2015-01-15 11:05

6 CONCLUSIONS

6.1 Step response in FGMO

FGMO works as expected and the magnitude of response is according to the droop

settings. The generated load response in the step tests corresponds to 4 % droop. The

response time T67 is in the range 3-10 seconds, measured for steps causing a change

in generated load approx. equal to 5 % of rated load.

6.2 Island Operation

The island operation tests were not performed as agreed and discussed in the

meetings 24/10/2014 [2] and 25/11/2014 [3].

Annexure-3

193

of 23 Printed 2015-01-15 11:05

7 RECOMMENDATIONS

The results from the tests were analysed to see what could further be done to improve

the performance. In this section some recommendations are presented.


No recommendations.


The island operation tests were not performed as mention in the meeting [2] and [3].

However, for a stable operation of the unit during islanding operation, island

operation tests are recommended to verify the performance.

Annexure-3

194

of 23 Printed 2015-01-15 11:05

8 REFERENCES


19/08/2014

[2] Minutes of the meeting held on 24.10.2014.

[3] Minutes of the meeting held on 25.11.2014 for primary frequency response

testing at Bawana Gas station Unit-2.

[4] GE Test procedure: Testing of governor response (Fuel gas)

Annexure-3

195

1 Punjab 13.3 1 Maharashtra 7.6

2 Haryana 23.5 2 Gujarat 2.4

3 Rajasthan 18.4 3 MP 2.3

4 Delhi 12.4 4 Chhattisgarh -3.6

5 Uttar Pradesh 5.5 5 DNH 0

6 Uttarakhand* 147.6 6 DD 0

7 Chandigarh* 135.1 7 Goa* 312.7

8 HP 6.8

9 J&K* -63.4

1 AP 30 1 WB 19.22 TN 21 2 BSEB -54.23 KAR 21 3 OPTCL 6.94 KER 70 4 JSEB 11.65 Telangana 45 5 DVC 14.26 Pondi* 343 6 Sikkim 18.2

1 Assam 23.4

2 Meghalaya -0.2

3 Tripura 16

4 Manipur 31

5 Mizoram 38.4

6 Nagaland* -270.3

7Arunachal

Pradesh*-170.4

** the constituent with highest positive value of FRC contributes maximum to frequency response and that with highest

–negative value severely aggravates the frequency deviation.

* For smaller states, small error in Telemetry can cause large impact in calculation result.Data pertaining to these states

can be interpreted accordingly

TABLE 1 Control Area wise - Percentage of Ideal Response** (%)

Control AreaPercentage of Ideal

Response (%)

Sl. No. Control AreaPercentage of Ideal

Response (%)

ER


Response (%)

NR WR

SR


Response (%)Sl. No.

NER


Response (%)

Annexure-4

196

1 Sri Cement 5.4 18 Pong 17.8 1 Korba 0

2 Jhajjar-MGTPS -10.3 19 Singrauli 0.3 2 Vindhyachal 2.5

3 Chamera-I -3 20 Rihand -6.3 3 Sipat -35.1

4 Chamera-II -22.1 21 Dadri -13.8 4 NTPC-SAIL 8.2

5 URI 0 22 Dadri-Gas 2.4 5 JINDAL -8.9

6 Salal 1.2 23 Unchahar 0 6 LANCO -1.7

7 Bairasul 9.9 24 ANTA 2.7 7 KAWAS 0

8 Tanakpur 0 25 Auraiya 0 8 SSP 9.8

9 Dhauliganga 0 26 Narora 0 9 UMPP-Mundra 0.6

10 Dulhasti -3.2 27 RAPPB 0 10 Tarapur -32.8

11 SEWA2 0 28 RAPP C 0 11 KSK Mahanadi 4.1

12 Karcham -8.2 29 Jhajjar-PG 5.8 12 Balco -24.4

13 Malana 0 30 ADHydro 0 13 Mouda 25.3

14 TEHRI 0 31 Koteshwar -5.2 14 Emco -25.2

15 Naphtha 0 15 Sasan 0

16 Bhakra 6.4 16 Essar -26.8

17 DEHAR 0.9

Sl. No.Generating

Station

Percentage of

Ideal Response

(%)

TABLE 2 Generating Station- Percentage of Ideal Response* (%)

NR WR

Sl. No.Generating

Station

Percentage of

Ideal Response

(%)

Sl. No.Generating

Station

Percentage of

Ideal

Response (%)

Annexure-4

197

1 Ramagundam 0.2 1 Farraka -0.8 1 KAITHALGURI -6.2

2 Simhadari 34 2 Kahalgaon 2.4 2 AGARTALA -24.2

3 Neyveli-II 13.2 3 TSTPS-I 5.4 3 KHANDONG -18.1

4 Neyveli Exp 0 4 MPL 9.1 4 KOPILI -3.7

5 Kaiga 1.8 5 Sterlite 57.9 5 DOYAN 3.7

6 MAPS -3.2 6 Adhunik 54.2 6 RANGANADI 3.8

7 KNPP 0 7 Teesta -31.2 7 LOKTAK 2.8

8 Vallur 0 8 RHEP -2.5 8 PALATANA 0

9 CHEP 0

*generating station with highest –negative value of FRC is contributing maximum to frequency response and generating station with

highest positive value of FRC is aggravating the frequency deviation.

Sl. No.Generating

Station

Percentage of

Ideal Response

(%)

ER

Sl. No.Generating

Station

Percentage of

Ideal

Response (%)

Sl. No.Generating

Station

Percentage of

Ideal Response

(%)

SR NER

Annexure-4

198


Response (%)Sl. No. Control Area

Percentage of

Ideal Response

(%)1 Haryana 23.5 1 Maharashtra 7.6

2 Rajasthan 18.4 2 Gujarat 2.4

3 Punjab 13.3 3 MP 2.3

4 Delhi 12.4 4 Chhattisgarh -3.65 Uttar Pradesh 5.5

1 KER 70 1 WB 19.2

2 Telangana 45 2 DVC 14.2

3 AP 30 3 OPTCL 6.9

4 TN 21 4 BSEB -54.2

5 KAR 21

Percentage of Ideal

Response (%)Sl. No. Control Area

Percentage of

Ideal Response

(%)

Sl. No. Control Area

TABLE 3 Ranking Control Area wise (Demand Met 2000MW and Above) Based on

Percentage of Ideal Response (%)

NR WR

SR ER

Annexure-4

199

1 Chamera-II -22.1 1 Sipat -35.1 1 MAPS -3.2

2 Dadri -13.8 2 Tarapur -32.8 2 Neyveli Exp 0

3 Jhajjar-MGTPS -10.3 3 Essar -26.8 3 KNPP 0

4 Karcham -8.2 4 Emco -25.2 4 Vallur 0

5 Rihand -6.3 5 Balco -24.4 5 Ramagundam 0.2

6 Koteshwar -5.2 6 JINDAL -8.9 6 Kaiga 1.8

7 Dulhasti -3.2 7 LANCO -1.7 7 Neyveli-II 13.2

8 Chamera-I -3 8 Korba 0 8 Simhadari 34

9 URI 0 9 KAWAS 0

10 Tanakpur 0 10 Sasan 0

11 Dhauliganga 0 11 UMPP-Mundra 0.6

12 SEWA2 0 12 Vindhyachal 2.5

13 Malana 0 13 KSK Mahanadi 4.1

14 TEHRI 0 14 NTPC-SAIL 8.2

15 Naphtha 0 15 SSP 9.8

16 Unchahar 0 16 Mouda 25.3

17 Auraiya 018 Narora 019 RAPPB 020 RAPP C 021 ADHydro 0

22 Singrauli 0.323 DEHAR 0.9 1 Teesta -31.2 1 AGARTALA -24.224 Salal 1.2 2 RHEP -2.5 2 KHANDONG -18.125 Dadri-Gas 2.4 3 Farraka -0.8 3 KAITHALGURI -6.226 ANTA 2.7 4 CHEP 0 4 KOPILI -3.7

27 Sri Cement 5.4 5 Kahalgaon 2.4 5 PALATANA 0

28 Jhajjar-PG 5.8 6 TSTPS-I 5.4 6 LOKTAK 2.8

29 Bhakra 6.4 7 MPL 9.1 7 DOYAN 3.7

30 Bairasul 9.9 8 Adhunik 54.2 8 RANGANADI 3.8

31 Pong 17.8 9 Sterlite 57.9

ER NER

Sl. No.Generating

Station

Percentage of

Ideal Response

(%)

Sl. No.Generating

Station

Percentage of

Ideal Response

(%)

TABLE 4 Ranking of Generating Station Based on Percentage of Ideal Response (%)NR WR SR

Sl. No.Generating

Station

Percentage of

Ideal Response

(%)

Sl. No.Generating

Station

Percentage of

Ideal Response

(%)

Sl. No.Generating

Station

Percentage of

Ideal Response

(%)

Annexure-4

200

Annexure-V

Over Fluxing of Transformers

In normal operation, if an electrical power transformer is subjected to carry more than specified

flux density as per its design limitations, the transformer is said to have faced over

fluxing problem and consequent bad effects towards its operation and life. The magnetic

flux density is proportional to the quotient of voltage and frequency (V/f). Over fluxing can,

therefore, occur either due to increase in voltage or decrease in-frequency or both. Over fluxing

in transformer has sufficient harmful effect towards its life.

In the normal Grid Operations it is observed that frequency keeps varying throughout the day. In

the events of sudden large Generation Loss such as that of CGPL Outage, frequency plunged to a

very low value and thereby posed as severe threat to system operation. Such sudden Generation

Loss causing frequency to plunge to a low value can eventually lead to over fluxing operation of

transformers. Therefore it is very important to check this sudden fall of frequency by

implementation of FGMO. The Voltage and Frequency scatter plots of important stations across

the Grid for the month of January 2015 is given below as Fig.1 to Fig.8 for better understanding.

In the plots it is observed that second quadrant operation is present in almost all the stations. The

second quadrant operation indicates that voltage is high and frequency is low in the system.

Therefore the condition for overfluxing of transformers is satisfied during such operation.

201

http://www.electrical4u.com/electrical-power-transformer-definition-and-types-of-transformer/

http://www.electrical4u.com/what-is-magnetic-field/#Magnetic-Flux-or-Magnetic-Lines-of-Force

http://www.electrical4u.com/what-is-magnetic-field/#Magnetic-Flux-or-Magnetic-Lines-of-Force

http://www.electrical4u.com/voltage-or-electric-potential-difference/

http://www.electrical4u.com/voltage-or-electric-potential-difference/

Annexure-V

Fig:1

Fig:2

750

760

770

780

790

800

810

820

830

49.6 49.8 50 50.2 50.4 50.6 50.8

Vol

tage

(kV

)

Frequency(Hz)

V/F Plot for Wardha(765kV) (For the month of Jan'15)

730

740

750

760

770

780

790

800

49.60 49.80 50.00 50.20 50.40 50.60 50.80

Vo

ltag

e(k

V)

Frequency(Hz)

V/F Plot for Seoni (765kV) ( For the month of Jan'15)

202

Annexure-V

Fig:3

Fig:4

735

740

745

750

755

760

765

770

775

780

49.60 49.80 50.00 50.20 50.40 50.60 50.80V

olta

ge(k

V)

Frequency(Hz)

V/F plot for Sipat (765kV) ( For the month of Jan'15)

730

740

750

760

770

780

790

800

810

49.60 49.80 50.00 50.20 50.40 50.60 50.80

Volta

ge(k

V)

Frequency(Hz)

V/F plot for Agra (765kV) ( For the month of Jan'15)

203

Annexure-V

Fig:5

Fig:6

720

730

740

750

760

770

780

790

800

49.60 49.80 50.00 50.20 50.40 50.60 50.80Vo

ltag

e(kV

)Frequency(Hz)

V/F plot for Fatehpur (765kV) ( For the month of Jan'15)

395

400

405

410

415

420

425

430

435

440

49.60 49.80 50.00 50.20 50.40 50.60 50.80

Volt

age(

kV)

Frequency(Hz)

V/F plot for Kurnool (400kV) ( For the month of Jan'15)

204

Annexure-V

Fig:7

Fig:8

395

400

405

410

415

420

425

430

435

440

49.60 49.80 50.00 50.20 50.40 50.60 50.80

Vo

ltag

e(k

V)

Frequency(Hz)

V/F plot for Malkaram (400kV) ( For the month of Jan'15)

395

400

405

410

415

420

425

430

435

49.60 49.80 50.00 50.20 50.40 50.60 50.80

Vo

ltag

e(k

V)

Frequency(Hz)

V/F plot for Hyderabad (400kV) ( For the month of Jan'15)

205

NLDC Petition regarding inadequate FGMO response

Documents

Transcript of NLDC Petition regarding inadequate FGMO response