221661A - QGX-CLP - Relay Coordination-Rev1

Electrical System Studies for QGX-CLP Development Project Relay Co-ordination Studies

CTJV

         

OCT 2007

Mott MacDonald 1 Atlantic Quay Broomielaw Glasgow G2 8JB UK Tel: 44 (0)141 222 4500 Fax: 44 (0)141 221 8083

221661/02/B - OCT 2007/ P:\Glasgow\PSB\EEG\3Jobs\221661 QGX\CLP Studies\Report\221661A - QGX-CLP - Relay Coordination-Rev1.doc/CLP

Mott MacDonald CTJV


Mott MacDonald CTJV

List of Contents

Page

Chapters and Appendices 1 Introduction

1-1

2 Model Description and Modelling Methodology

2-1

2.1

Introduction

2-1

2.2

ETAP Software Package

2-1

2.3

System model Data 2.3.1 System Earthing 2.3.2 System Operation

2-2 2-2 2-2

3 Relay Setting Results and Discussion

3-1

3.1

Introduction

3-1

3.2

Relay Setting and Co-ordination Studies 3.2.1 Fault current matrix for relay settings 3.2.2 Guidelines for relay settings for 51, 50, 51N and 51G protection function 3.2.3 Guidelines for relay setting for 27 protection function 3.2.4 Guidelines for relay setting for 59 protection function 3.2.5 Guideline for relay setting for 49 protection function 3.2.6 Guidelines for relay setting for 46 protection function 3.2.7 Guidelines for relay setting for 66 protection function 3.2.8 Guidelines for relay setting for 37 protection function 3.2.9 Relay setting for 87 protection function / Interface with Kahramaa 3.2.10 Setting of 25 function for ATS at 33 kV and 6.6 kV levels 3.2.11 Over current protection for the LV systems

3-1 3-1 3-4 3-6 3-8 3-9 3-11 3-12 3-12 3-13 3-25 3-26

Appendix - A: Relay setting schedules

A1

A-1: LV relays setting schedule

A2

A-2: HV feeders relay setting schedule

A20

A-3: Interface with Kahramaa - Schedule for 87L and 87T protection

A25

A-3: 33/6.6 kV and 6.6/0.415 kV transformer relay setting schedule

A29

A-4: MV motor relay setting schedule

A33

Appendix - B: TCC for relay co-ordination

B1

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Table 1-1: Main protection functions set and relay used for the protection Table 3-1: Fault levels at 132 kV main switchboard of the Kahramaa substation Table 3-2: Current matrix for various ratings of transformer Table 3-3: Fault current matrix for over current relay setting Table 3-4: Permissible time delay for over current relay co-ordination Table 3-5: Guideline for relay setting for under voltage protection Table 3-6: Guideline for relay setting for over-voltage protection Table 3-7: Setting group for REM 543 relay for thermal over load protection Table 3-8: Time constant – heating; Data assumed if not available Table 3-9: Setting of 87L protection for 33 kV feeders from SB-27101 A/B Table 3-10: Setting group for REF 542+ relay for 87T protection Table 3-11: Setting of 87M protection for MV BOG compressors Table 3-12: Direct on line starters with MCCB and INSUM-2, load up to 45kW Table 3-13: Direct on line starters with MCCB and INSUM-2, load more than 45kW

Mott MacDonald CTJV

1-1 3-1 3-2 3-3 3-4 3-6 3-8 3-9 3-10 3-14 3-21 3-24 3-27 3-28

Figure 3-1: Sample circuit diagram for relay setting guideline 3-4 Figure 3-2: Setting of 87L protection for 33 kV out going feeders from SB-27101 A/B on the relay characteristic 3-15 Figure 3-3: Representation of 87L protection for 132 kV cable 3-16 Figure 3-4: Representation of 87T protection for TR-27101 A/B 3-19 Figure 3-5: Characteristic for the differential protection of REF 542 + 3-21 Figure 3-6: Three-phase stabilized differential protection for motors 3-23

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Mott MacDonald CTJV

Summary and Conclusion This report describes the results of the relay co-ordination studies performed for the QGX-CLP development Project. In this report, relay setting and co-ordination for QGX-CLP electrical distribution system (SS-2702 and SS-2701) are carried out for all voltage levels from 132 kV to 0.415 kV. Setting of protections functions such as 87L, 87T, 87M, 81U, 27, 59, 49, 46, 47, 66, 50, 51, 50N, 51N, 51G etc. (as defined in the relaying scheme documents) are covered. Down stream over-current relays are co-ordinated with the up stream relays. At 0.415 kV level, MCCBs are co-ordinated with the up-stream over-current relays. At all voltage levels the proper co-ordination of the relays and setting of various protection functions are ensured for both minimum and maximum fault currents. Time current characteristics (TCC) of the over-current relays at different voltage levels are presented in the report. TCCs shows that the protection setting adopted are in line with the selective, sensitive and fast operation of relays. Siemens relays are mainly used in the HV system at 132 kV level while ABB relays are mainly used in 33kV and below voltage levels. Relay setting schedules are presented in Appendix - A and TCCs of the over-current protection are presented in Appendix - B.

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1

Mott MacDonald CTJV

Introduction

This report describes the relay co-ordination studies performed by Mott MacDonald on behalf of Chiyoda Technip Joint Venture (CTJV) for the QGX-CLP (Qatar Gas II – Common Lean LNG Project) development project. The electrical distribution system of the CLP network comprises of the substation SS-2701, SS-2702 and SS-2703. The substation SS-2701 is having option of power supply either from QGX system or from the SS-2702. The substation SS-2702 (Lean LNG storage tank substation-2) is connected to the Kahramaa substation through two 132 kV underground cables and the substation SS-2703 is supplied from SS-2701. For the CLP system study the substation SS-2701 is considered to be supplied from the substation SS-2702. In this report, integrated relay setting of various protection functions and co-ordination of various relays are presented. Main protection functions for which the relay settings are carried out are shown in Table 1-1.

S.No.

ANSI Number

Protection Name

Relay Type used

87-T & 87-N

Transformer differential

7UT612, REF542+

87-L

Line differential

7SD53, SOLKOR-N, REL 561

87-M

Motor differential

REM 543

2

49

Motor Thermal

REM 543

3

27

Under voltage

REF 542+, REM 534

4

59

Over voltage

REF 542+, REM 543

5

46

Unbalance current

REM 543

6

47

Phase sequence voltage

REM 543

7

66

Max. motor starts

REM 543

8

37

Under power

REM 543

9

51, 51N, 51G

Over current / EF

REF 542+, REM 543

10

50, 50N

Instantaneous O/C and E/F

REF 542+, REM 543

11

81U

Under frequency

REF 542+

1

Table 1-1: Main protection functions set and relay used for the protection

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2

Mott MacDonald CTJV

Model Description and Modelling Methodology

2.1

Introduction

This section describes the electrical distribution system for the QGX-CLP development project, the modelling methodology adopted and the data used in performing the electrical system studies. Included within this section is a description of the following: •

Software package

•

EATP model development

The ETAP representation of the QGX-CLP electrical network is presented in electrical system studies report1 already submitted.

2.2

ETAP Software Package

Fault level and relay co-ordination studies are carried out using version 5.0.3 of ETAP PowerStation, developed by Operation Technology, Incorporated. This package uses standard models of the main components in the power system in combination with numerical techniques to solve the various electrical and mechanical equations describing the system. The system model and parameters are entered into the model using the ETAP network schematic capture facility. The main components represented in the ETAP model are as follows: Synchronous machines: A standard two-axis equivalent circuit model is used to represent synchronous machines. This model includes sub-transient, transient and synchronous reactances and their associated time constants and allows full dynamic modelling of transient events. Stator and rotor saturation are accounted for, as are the alternator and prime mover inertia. Asynchronous (induction) machines: These elements are modelled based on their per-phase equivalent circuit parameters. The equivalent circuit data is manipulated to create a two axis transient model that also includes the motor and driven load inertia and the load torque-slip curve. The dynamic simulation therefore takes account of the motor and load dynamics. The model also accounts for the momentary and decaying current contribution that asynchronous machines will make into a system short circuit. Transformers: These are modelled as equivalent pi impedance network. The zero sequence impedance, and winding connections are included in the model. This is used to assemble the correct zero sequence network representation when calculating earth fault currents. Cables: Cables (and transmission lines) are modelled by a circuit of fixed positive sequence impedance and shunt susceptance. A pi impedance network is used to represent the circuit with half of the total circuit capacitance connected as a shunt element at each end of the circuit.

1

Electrical system studies for QGX-CLP development protect; Load flow, short circuit and motor starting studies – Rev A; Mar 2007, report submitted by Mott MacDonald Ltd.

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Mott MacDonald CTJV

Controllers: The prime mover turbines and voltage regulator/exciter system associated with synchronous machines are included as transfer function block diagrams and associated gains and time constants. Relays: Over current relay specific to manufacturer and model are available with all setting ranges and typical ANSI and IEC curves for inverse, very inverse and other characteristics. By selecting one particular setting of current and time delay the same can be projected on TCC (on loglog scale) to view the possible operation time for various currents.

2.3

System model Data

The ETAP single line representation of the QGX electrical system is based on CTJV General Single Line Diagram for the Electrical System2 . The system model3 used for system study is used for the relay co-ordination.

2.3.1

System Earthing

The QGX electrical system earth fault levels are generally limited by neutral earthing resistors that are organised as follows: •

132 kV

- Solidly earthed

•

33 kV

- limited to 400 A by each transformer NER

•

11 kV

- limited to 400 A by unit transformer NER (unit fed compressor motors)

•

6.6 kV

- limited to 400 A by each transformer NER;

•

0.415 kV

- limited to 10 A by each transformer NER.

2.3.2

System Operation

Various transformer configurations were considered in the studies for calculation of the minimum and the maximum fault current calculation. The following definitions are used throughout the report when referring to transformer connections: •

Dual transformers – each switchboard section is fed in isolation by its associated transformers. This is the normal operating configuration for the system.

•

Single transformers – two or more switchboard sections are fed via a single transformer. This is to consider a case where there is a single transformer outage and its load is taken up by another unit. For a switchboard fed by three or more transformers, it is not expected that one unit would be rated to supply the whole load.

2

CTJV, QATARGAS II DEVELOPMENT PROJECT General Single Line Diagram, Dwg. Nº: QGX/20/91/EL/DR/SD/001 Rev C2 3

Electrical system study for QGX-CLP development project Mar-2007 (Study report for load flow, short circuit, motor starting) submitted by Mott MacDonald Ltd.



3

Mott MacDonald CTJV

Relay Setting Results and Discussion

3.1

Introduction

Methodology used for relay setting and co-ordination of relays are presented in the various sub-section below. Based on that relay setting schedules and TCC of the over current relays are prepared.

3.2

Relay Setting and Co-ordination Studies

The relay setting and co-ordination studies are carried out for various relays and protection functions presented in the Table 1-1. Before carrying out the relay setting, a fault current matrix for various voltage levels is prepared. The current matrix gives important information for the minimum and maximum fault currents seen by each relay at various locations in the system, based on which proper discriminated, sensitive and coordinated protection can be achieved. In order to achieve the uniform relay setting for the feeders having similar rating of transformers and loads guidelines are prepared for setting of the various protection functions.

3.2.1

Fault current matrix for relay settings

Current matrix is calculated for faults at voltage levels. The following tables present the current matrices. The minimum and maximum three-phase fault levels at 132 kV main switchboard of the Kahramaa substation4 are presented below: S.No.

Fault level

Three-phase fault current (kA) at 132 kV main switchboard of the Kahramaa substation

X/R ratio

1

The minimum

10.2

12.05

2

The maximum

15.47

6.48

Table 3-1: Fault levels at 132 kV main switchboard of the Kahramaa substation

4

Email from Vincent Sauvergrain to Manoj Gupta, dated 31/08/2007, subject: QGX-CLP-MMD electrical studies-Company and KM comments



S.No

Transformer Tag Name

Primary Voltage

Secondary Voltage

Mott MacDonald CTJV

Transformer Rating Min Max MVA MVA

Full load current (FLC) (kA) I-Min I-Max I-Min I-Max Primary Primary Secondary Secondary

KV

kV

1

TR-27101 A/B

132

33

2

TR-27601

33

11

3

TR-27204 A/B

33

6.9

4

TR-27201 A/B

33

6.9

12

15

5

TR-27301 A/B

6.9

0.44

1.6

1.6

6

DTR-27302 A/B

6.9

0.44

1

1

0.084

80

0.437

1.4

1.75

Inrush Current (Multiple of FLC) 7

Type

100

0.35

Step down

25

25

0.437

0.437

1.312

1.312

7*

HV Distribution

20

25

0.350

0.437

1.674

2.092

4.75

MV Distribution

0.210

0.262

1.004

1.255

5.19

MV Distribution

0.134

0.134

2.100

2.100

7.31

LT Distribution

0.084

1.312

1.312

11.66

LT Distribution

Table 3-2: Current matrix for various ratings of transformer * Assumed data (Higher side value is considered for protection margins) Fault current matrix for fault currents at various voltage levels and associated fault current flow at higher voltage levels is presented in Table 3-2 below

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Mott MacDonald CTJV

Three-phase fault current when supplied from Kahramaa S/S Minimum (kA) Maximum (kA)

Fault location

Fault current observation

0.415 kV SB-27302A

SB-27302A

21.17

22.34

Bus section

21.17

22.34

6.6 kV incomer

1.38

1.45

SB-27301A

28.12

30.22

Bus section

28.12

30.22

6.6 kV incomer

1.83

1.98

SB-27201A

10.08

16

6.6 kV incomer

10.08

11

Bus section

10.08

11

33 kV TR-27201

2.06

2.34

33 kV incomer

2.06

1.51

132 kV CLP

0.52

0.4

6.6 kV

SB-27205A

11.81

17

SB-27205A

6.6 kV incomer

11.81

11.73

Bus section

11.81

11.73

33 kV TR-27204

2.41

2.89

33 kV incomer

2.41

1.68

132 kV CLP

0.62

0.45

33 kV

33 kV TR-27603

9.02

13.92

TR-27603

Bus section

9.02

13.92

33 kV incomer

9.02

9.46

132 kV CLP

2.31

2.52

132 kV CLP

9.5

13.92

132 kV CLP

10.05

15.17

0.415 kV SB-27301A

6.6 kV SB-27201 A

132 kV TR-27101A

(LG fault current)

Table 3-3: Fault current matrix for over current relay setting For the minimum three-phase fault current calculation, the minimum fault level at Kahramaa S/S and no motor contribution are considered. For the maximum fault current calculation, the maximum fault level at Kahramaa S/S and motor contributions are considered. All faults currents are as per IEC 60909 symmetrical breaking currents. Earth fault current is restricted to the value as indicated in the Section – 2.3.1 due to the resistance grounded system.



3.2.2

Mott MacDonald CTJV

Guidelines for relay settings for 51, 50, 51N and 51G protection function

The following guidelines are adopted for the relay settings •

Time discrimination between the relays

The Circuit protection Time Interval (CTI)5 for the over current relay settings is presented below S.No.

Components

CTI with field test (s) Static / Electronics relays

1

Circuit breaker opening time 5 cycles

2

Relay over travel

3

Relay tolerance and error

0.1 0 0.12

Total CTI

0.22

Table 3-4: Permissible time delay for over current relay co-ordination Hence it is practical to have CTI for the electronics relays as low as 0.22 s. CTI provides the necessary time delay between the operations of the two relays and ensure co-ordinated operation. •

Guideline for setting of the over current relays

A sample circuit is shown below with a transformer and load. Relay locations are presented by A, B and C. Fault is presented on the primary side and secondary side of the transformer by Fp and Fs respectively. C Fp

B

.

A Fs

Figure 3-1: Sample circuit diagram for relay setting guideline

5

IEEE Std. 242-2001: Chapter 15 Over current protection



Mott MacDonald CTJV

For the over current protection following guidelines are adopted •

The characteristic of the relays at A, B and C for over current protection is normal inverse. Exception can be made for the relay at A, if associated with a motor protection, then it may be definite time or extremely inverse.

•

Relay at B and C must not operate for the maximum full load current of the transformer. The pickup is set between 115-150% of the full load current depending on the coordination with the down-stream and up-stream relays.

•

Relay at C must not operate for inrush current of the transformer, to ensure this the pickup setting of the instantaneous element must be more than the inrush current as indicated in the Table 3-1

•

For the fault Fs, the instantaneous elements of the relay at A should give protection, backup by the over-current element of the B and C. The instantaneous element of the relay at B will not be co-ordinated as the same is used for blocking of ATS (Automatic transfer system)6 in event of fault at the secondary side of the transformer. Pickup values for the instantaneous element at B are considered as follows o

At 33 kV level set pickup = 2 kA

o

At 6.6 kV level set pickup = 4 kA

o

At 0.415 kV level set pickup = 10 kA

•

The instantaneous element of C should provide protection for the fault Fp

•

In no case the minimum CTI should be violated for the maximum fault current seen by the relays

•

Because earth fault current is limited by the NGR, definite time characteristics are adopted to co-ordinate all 51N and 51G protection functions.

•

Characterise of the fuse are as per the ABB fuse manual 7 . The fuse characteristics as given on page 13 of the manual are modelled in ETAP.

The TCCs for the over current protection is presented in the Appendix – B.

6

“Secondary selective systems”, document number QGX/20/19/EL/TS/NA/026

7

“PowerIT Motor Circuit Fuses, CMF/CEF” ABB catalogue 1 YMB631051-en



3.2.3

Mott MacDonald CTJV

Guidelines for relay setting for 27 protection function

For the under voltage protection the following settings are considered

S.No. 1 2

Under voltage element U< = 0.1 - 1.2 Un t< = 40 - 30,000 ms

For Motor 0.7 500 ms

For Transformer 0.7 70 ms

Table 3-5: Guideline for relay setting for under voltage protection •

Under voltage relay at transformer secondary is used for ATS operation as shown in figure below. During the operation of 50, 50N or 27 immediate transfers of the loads to the other main bus (S1-R) should not occur otherwise that bus (S1-R) will also see the fault. For this reason operation time of the 27 and ATS should be time delayed to allow the operation of 51, 51N at each outgoing feeder to disconnect the faulty feeders from the bus (S1-L), if the fault is at the outgoing feeders. Hence the additional time delay is used for this purpose. Time delay of 2s is provided by the 27X of the ATS.

The action can be summarised as follows: •

For faults at transformer secondary side the ATS operation is blocked by the instantaneous over-current relays 50 and 50N as well as 27

•

For the low voltage at the secondary of the transformer by opening the primary CB motor under voltage operates first followed by under voltage relay on the transformer secondary with the time delay of 70 ms that activates the transfer logic of ATS. The ATS operates after a delay of 2s by opening the primary CB of the affected transformer, then opening secondary CB of the transformer and closing the bus coupler. In this way the bus S1-L is transferred to the bus S1-R.



Mott MacDonald CTJV

P1-L

P1-R

C

Time delay of the 27X is taken care by the control logic. The following time delays are suggested for the 27X operation at different voltage levels

C

"#



27X at 33kV: Time delay = 2 s 27X at 6.6kV: Time delay = 3 s 27X at 415V: Time delay = 3.5 s

! "#

% '(

 

B

S1-L

  

A

B



S1-R

 

Fs "#& &



 

       

Figure 3-1A: ATS operation – Interaction with over-current and under voltage relays



3.2.4

Mott MacDonald CTJV


For the over voltage protection the following settings are considered

S.No. 1 2

Over voltage element U> = 0.1 - 3.0 Un t = 40 - 30,000 ms

For Motor 1.15 5000

Table 3-6: Guideline for relay setting for over-voltage protection

Motor starting results reveals that the maximum post transient over voltages after the motor start are as high as 1.1 pu for less than 100 ms. Considering the result of the motor starting the low set U> of the 59 function is set to 1.15 pu with a time delay of 5s.



3.2.5

Mott MacDonald CTJV

Guideline for relay setting for 49 protection function

For the thermal over load protection (49) of the MV motors, REM 543 (ABB) is used. For the LV motors the setting of the thermal protection is presented in Appendix – A1.

3.2.5.1 49 protection function for ABB REM 543 relay

S.No.

Setting Parameter

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21

Ist = 0.1-10.00 In Tst = 0.1 - 120.0 s NC-st = 1-3 Device Type = 0-6 Trip Temp. = 80-120 % Alarm Temp. = 40-100% Reset Temp. = 40-100% Am Temp.= -50-100 Deg C TC-cooling = 1.0-10.0 TC-Heating = 1-999 min ST-CS = 0.0-999.0 min LT-CSS = 0.0-999.0 min p = 0.0 - 1.0 S-TR =50-350 Deg C Tmax S = 0.0-350 Deg C ST-CR = 0.0-999.0 min LT-CR = 0.0-999.0 min p = 0.0 - 1.0 R-TR =50-350 Deg C Tmax R = 0.0-350 Deg C Trip Delay = 0-86400 s

Sample Data 3.5 12 3 3 120 90 60 50 3 45 14.00 69 0.5 90 155 4 69 0.25 100 200 3600

Remarks Starting current Starting time Number of starts allowed from cold Surface cooling Trip temperature Alarm temperature Reset temperature Ambient Temp. * TC-Heating Time constant Short TC - Stator Long TC - Stator Wt. factor Stator Temp. rise at FL Stator Max. Temp Short TC - Rotor Long TC - Rotor Wt. factor Rotor Temp. rise at FL Rotor Max. Temp 60 min

Table 3-7: Setting group for REM 543 relay for thermal over load protection Explanations of the above setting parameters are presented below •

Ist is set as per the individual motor starting current

•

Tst is set as per the individual motor starting time

•

NC-st is set as per the individual motor data

•

Device type8 is set for motor rating > 500 kW and surface cooling

8

Relay technical data sheet: ABB ProtectIT Machine Terminals REM 543 and REM 545, document number: 1MRS751173-MBG



Mott MacDonald CTJV

•

Trip Temp. is set to 120% with Trip Delay of 60 min (3600s). It means that from motor temperature in the range of 100-120%, warning alarm will be generated until time delay of 60 min, for temperature more than 120%, tripping will occur instantaneously.

•

Alarm Temp. is set at 90%

•

Reset Temp. is set at 60% of the thermal capacity

•

Am. Temp. is set at 50 Deg. C

•

TC-cooling is set at 3 times the heating time constant. For motors less than 1300 kW it is taken as 6.0

•

TC – heating is set according to individual motor data. Following values are used when the data is not available

S.No.

Motor rating

Time constant – Heating (Min)

1

Less than 1300 kW

30

2

1300 kW to 2000 kW

35

3

2100 kW to 3000 kW

40

4

More than 3000 kW

45

Table 3-8: Time constant – heating; Data assumed if not available •

Settings from ST-CS to TMAX R are taken as default setting for wide range of motor ratings, except for S-TR and R-TR. The value of S-TR and R-TR for motors above 2000 kW is 90 and 100 respectively and for motors between 1000 kW to 2000 kW is 70 and 80 respectively.



3.2.6

Mott MacDonald CTJV


For current unbalance protection (for ABB REM 543) the following settings are considered •

Operation mode = Inverse time (2)

•

Pick up Is = 0.05

•

K is calculated for individual motor in such a manner that the tripping time of the relay is below the thermal damage curve. For motors above 2500 kW the thermal damage limit is taken as 15s and below that it is 10s. 2

Thermal damage curve is plotted using I * t = 15 (10). 2

2

And the motor tripping time is plotted for (I – Is ) * t = K For successful tripping the tripping curve must lie below the thermal damage curve. •

Operation time = Not applicable as the operation mode is not definite time

•

Start delay = 1 s

•

Minimum operation time = 7 s

•

Maximum operation time = 3600 s

•

Cooling time = 1800 s

•

For ABB make REM 543 9 relay inverse time characteristic is used for this function.

9

“Negative Phase Sequence Protection” ABB document no. 1MRS752310-MUM, Issued 10/1998, Version E/24.11.2003 3-11 221661/02/B - OCT 2007 P:\Glasgow\PSB\EEG\3Jobs\221661 QGX\CLP Studies\Report\221661A - QGX-CLP - Relay Coordination-Rev1.doc/CLP


3.2.7

Mott MacDonald CTJV


For protection function 66 (for ABB make, REM 543) the following settings a re considered •

Operation mode = 2 (Both I2t and stall protection)

•

Starting current = From the motor data sheet

•

Start time = 1.1 * motor start time (10% margin)

•

Time limit = Number of hot starts * start time

•

Countdown rate = 3 * start time

•

Stall time = From the motor data sheet

The protection function is also used to derided the 51LR protection function using the NOC3High (I>>)10 of the over- current protection. Output of the 66 protection function (using MotStart) is applied as input to NOC3High to double the setting of the NOC3High during the motor start-up duration. Once the motor reaches to its normal speed the NOC3High is returned to the actual setting (which set at 0.75 * Motor starting current). In this way 51LR is achieved during the motor start-up and the motor normal running condition. During the motor start-up the 51LR function is provided by the MotStart (66 protection function) and during the motor normal running condition the 51LR function is provided using the NOC3High of the over-current protection.

3.2.8


For protection function 37 (for ABB make, REM 543) the following settings a re considered Minimal load = 5%, Minimal current = 5% Op. time = 300 s (5 min)

10

Email from Toshiaki Saito to Manoj Gupta; dated 28/09/2006; subject: QGX : 51LR protection of REM543 (SL19020); attachment: Motstart_ver_0.10.pdf 3-12 221661/02/B - OCT 2007 P:\Glasgow\PSB\EEG\3Jobs\221661 QGX\CLP Studies\Report\221661A - QGX-CLP - Relay Coordination-Rev1.doc/CLP


3.2.9

Mott MacDonald CTJV

Relay setting for 87 protection function / Interface with Kahramaa

The differential protection as indicated in Table 1-1 is used for cables, transformers and motors protections. The differential protection is a unit protection and setting of this function required detailed analysis. The following sections present the calculation of the differential protection for various equipments using different relays.

3.2.9.1 Setting of 87L protection for 33 kV outgoing feeders Relay type: Solkor-N Setting is based on the minimum fault current basis, in this case the earth fault current, hence the differential current setting is equal to earth fault current. For the bias current setting minimum through fault is considered to be equal to two times the full load plus the earth fault. Based on these criteria the setting points are presented in Table 3-8 and on the relay characteristic by black dots in Figure 3-2. In the Figure 3-2, operating point of the relays are shown to test the stability of the relay under EF condition with relatively higher value of the restraint current (2 * FLC + EF) / 2. If for the operating point falls inside the relay selected characteristic then the relay will operates for other higher value of the phase current as well. Hence in the figures below operating points of the relays are shown by black dots to present a case in which differential current is equal to the EF current and the bias current is (2*FLC + EF)/2. The operating point will assist to select the correct value of relay setting such as B2 and Is



33 kV feeder To

Mott MacDonald CTJV

TR-27204 A/B

TR-27601 to TR-27605

TR-27201 A/B

MaxLoad Current/ Cable Rating (A)

438

438

263

CT Ratio (to 1A)

600

600

400

Primary EF Current (A)

400

400

400

Relay Bias Current (x In)

1.06

1.06

1.16

Relay Differential Current (xIn)

0.67

0.67

1.00

Minimum Differential Allowed wrt to Ic (x In)

0.1

0.1

0.1

Diff Setting Chosen

0.2

0.2

0.2

1

1

1

Bias Break point Chosen

Table 3-9: Setting of 87L protection for 33 kV feeders from SB-27101 A/B Same setting is used for both sending end and receiving end of the 33 kV feeder cables Ic: Relay bias current



Mott MacDonald CTJV

Solkor N - Bias Characteristic Is = 20%,S1=20% , S2=150%, B2= 0.5, 1, 1.5, 2 2.500

x ( t 2.000 n e r r u C l 1.500 a i t n ) N e I r e f f 1.000 i D r o e t 0.500 a r e p O

B2 = 2.5

0.000 0.00000

0.50000

1.00000

1.50000

2.00000

2.50000

3.00000

Restraint or bias Current (x I N) Figure 3-2: Setting of 87L protection for 33 kV out going feeders from SB-27101 A/B on the relay characteristic 3-15 221661/02/B - OCT 2007 P:\Glasgow\PSB\EEG\3Jobs\221661 QGX\CLP Studies\Report\221661A - QGX-CLP - Relay Coordination-Rev1.doc/CLP


Mott MacDonald CTJV

3.2.9.2 Interface with 132 kV Kahramaa substation - Setting of 87L protection

Relay Type: 7SD53 (Siemens) and REL 561 (ABB)

132 kV Kahramaa S/S

800/1

REL 561

800/1

7SD53

3*1C 1000 Sqmm 2850 m XLPE

800/1

7SD53

800/1

REL 561

132 kV CLP- SS2702

Figure 3-3: Representation of 87L protection for 132 kV cable Cable charging current = 20 A (Approximately) Guidelines adopted for 87L relay settings are •

Pickup for differential current (I-Diff>) should be more than 2.5 time the charging current

•

5% CT error should be added for calculation of the differential current

•

Charging current compensation is not required as the charging current is only 20A

•

Harmonic current stabilisation feature should be set to On

•

No additional time delay is required either for I-Diff> or for I-Diff>>

•

For dual slope characteristic relay, set the first slope to 50%, second slope to 100%, and intersection of slope 1 and slope 2 to 350% of I-bias.

•

Same setting of the differential protection should be adopted for both the ends of cable if CT ratios at both the ends are same.



Mott MacDonald CTJV

Calculations of relay setting parameters for 7SD53 are presented below •

Setting of I-Diff> I-Diff> = (2.5 * Charging current + 5% CT ratio error) / CT ratio = (2.5 * 20 + 0.05 * 800) / 800 = 0.1125 Adopted setting for I-Diff> = 0.12

•

Setting of I-Diff> Switch On Setting of the I-Diff> is increased to the minimum 3 times during cable energization I-Diff> Switch On = 3 * I-Diff> = 3 * 0.12 = 0.36 Adopted setting for I-Diff> Switch On = 0.36

•

Time delay for I-Diff> = 0.0s

•

Time delay for I-Diff>> = 0.0s

•

Charging current compensation = OFF

•

I-Diff>> = Min ( 3* Full load current, Line-line fault current) / CT ratio = Min ( 3 * 300 A, 7.45 kA) / 800 = 1.125 Adopted setting for I-Diff>> = 1.25

•

I-Diff>> Switch On = 4 * I-Diff>> = 4 * 1.25 =5

•

Inrush Restraint = On

•

2 Harmonic restraint = 30%

•

Cross block = No

•

Maximum Inrush Peak = 9.0 (Based on 11 * Transformer full load RMS current)

nd



Mott MacDonald CTJV

Calculations of relay setting parameters for REL 561 are presented below •

Operation = On

•

CT factor = 1 (Because CT ratio of both sides of the cable are same)

•

IminSat (Minimum current for CT saturation detection) Adopted setting = 300%

•

Iminop (Pick for differential current) I-Diff> for 7SD52 is 12%, in REL 561 the minimum setting available is 20% Adopted setting = 20%

•

IDiffLVl1 (Slope 1 of the relay characteristics) IDiffLVl1 = 50%

•

IDiffLVl2 (Slope 2 of the relay characteristics) IDiffLVl2 = 100%

•

ILV1/2Cross (Intersection of the slope 1 a nd slope 2) ILV1/2Cross = 350%

•

Evaluate = 3 of 4 (Refer relay manual for this setting)

•

Asymdelay (Asymmetrical time delay in data communication between the two ends) Asymdelay = 0.0 (Refer relay manual for this setting)

•

Diff Sync (For synchronising the operation of relays at two ends) Set Diff Sync = Master (For the relay at Kahramaa Substation) Set Diff Sync = Slave (For the relay at CLP SS-2702 substation)

•

CCom (Charging current compensation) Set CCom to Off

Complete relay setting schedule for the 87L protection is listed in Appendix – A3, for the 132 kV feeders C30 and C40.



Mott MacDonald CTJV

3.2.9.3 Interface with 132 kV Kahramaa substation - Setting of 87T protection for TR-27101A/B Relay Type: 7UT612 This relay provides the differential protection for the 80 MVA, 132/33kV transformer connecting the Kahramaa substation to SS-2702 substation. 132 kV 600/1

TR-27101 A/B 80 MVA Z = 12.5%

87 T 87N

7UT612

2000/1 33 kV

Figure 3-4: Representation of 87T protection for TR-27101 A/B

Calculations of the relay setting parameters are presented below •

Setting of differential current (Id>)

The relay should have minimum restrain for magnetising current (assumed to be 2% of full load current) , CT errors (considered to be 5%) at full loads and should consider the effects of transformer tap operations

Using the formula shown below minimum restraint current = 0.07 Minimum restraint current (Is) = (5% of Isecondary / CT ratio) + (5% of Iprimary / CT ratio) Isecondary = X * FLC (FLC: Full load current) Iprimary = X * FLC X = 1.15 (15% allowable overload is considered) Adding the differential current at full load due to CT ratio mismatch, the minimum differential current = 0.07 + 0.11 = 0.18 Considering the safety margin, CT saturation and transformer tap operation set Id> to 0.25 In 3-19 221661/02/B - OCT 2007 P:\Glasgow\PSB\EEG\3Jobs\221661 QGX\CLP Studies\Report\221661A - QGX-CLP - Relay Coordination-Rev1.doc/CLP


•

Mott MacDonald CTJV

Add on Stabilization Setting of the Add on Stabilization is based on the inrush current magnitude. Inrush current for TR-27101A/B = 7 * Full load current = 7 * 350 = 2450 A The inrush current seen at CT secondary = 2450 / 600 = 4.08 Adopted setting for Add on Stabilization = 75% of 4.08In = 3.0 In

•

Set Action time = 250 cycles

•

High set differential current (Id>>)

Setting of Id>> is calculated based on the formula given in the manual of 7UT612 on page 37 Id>> = (Transformer Full load current / CT primary) / Z (pu) = (350/ 600) / 0.125 = 4.7 In Adopted setting for Id>> = 4.7 •

Pickup on switch on = 1 (No shifting of the characteristic during switching)

•

TD for Id> = 0.0, TD for Id>> = 0.0

•

I2N / IfN = 30% (2 harmonic restraint ratio)

•

InfN / IfN = 30% (5 harmonic restraint ratio) Cross block = 0 Time for cross bloc = Deactivated

• •

nd

th

Calculation of setting parameters for 87N protection (Setting group of Restricted Earth Fault (64) are use for 7UT612) Secondary side Neutral CT ratio = 400/1 Line CT ratio = 2000/1 •

Set I-REF> to 100 A I-REF> = 100 / 400 = 0.25

•

Set time delay = 0

•

Slope = 0

Because earth fault current is limited to 400A hence chances of CT saturation and error due to through fault current is remote. Complete relay setting schedule for the 87T protection for the transformer TR-27101 A/B is presented in the Appendix – A3.



Mott MacDonald CTJV

3.2.9.4 Setting of 87T protection for 33/6.6 kV and 132/33 kV transformers Relay type: REF 542+ Basic setting groups for the transform differential protection for the ABB make REF 542 plus relay are presented below for the 87T protection of TR-27101A/B S.No. 1 2 3 4 5 6 7 8 9 10 11 12 13

Setting Parameter VG = 0 - 11 Earthing P: Yes / No Earthing S: Yes / No Ip = 10 - 100000 A Is = 10 - 100000 A Ith = 0.1 - 0.5 Ir URL = 0.5 - 5.0 In SBRT = 0.2 - 2.0 SBRL = 1.00 - 2.00 Ir Slope = 0.4 - 1.0 Trip Id> = 5.00-40.00 I2 Block= 0.1 - 0.3 I5 Block = 0.1 - 0.3

Sample Data 0 Yes Yes 350 1400 0.2 0.5 0.25 1 1 5 0.3 0.3

Remarks Transformer vector group

Rated primary side current Rated secondary current Threshold current Unbiased region limit Slightly biased threshold Slightly biased region limit Third region slope Upper Id threshold for trip 2nd harmonic threshold 5th harmonic threshold

Table 3-10: Setting group for REF 542+ relay for 87T protection

Id =

Id>

I1 – I2

R3

R1: Unbiased region

Trip only without nd th 2 and 5 harmonics

R2: Slightly biased region R3: Heavily biased region



SBRT It

Slope

R2

R1

URL

SBRL

Ib = (I1 + I2) / 2

Figure 3-5: Characteristic for the differential protection of REF 542 + Area above the thick black line is the trip area and below is the no trip region 3-21 221661/02/B - OCT 2007 P:\Glasgow\PSB\EEG\3Jobs\221661 QGX\CLP Studies\Report\221661A - QGX-CLP - Relay Coordination-Rev1.doc/CLP


Mott MacDonald CTJV

Explanation of the individual setting parameter is presented below •

VG: Vector group is set to 11 as all MV transformer as Dyn11

•

Ip and Is are set according to the individual transformer rating

•

Ith: Threshold current for the unbiased region (R1) is set to 20%, considering the maximum CT error of +5% and -5% at both ends of the transformer for through fault condition For 33/6.9 kV transformers Ith is set to 10%

•

URL: Unbiased region limit is set to 0.5In corresponding to 50% of the full load

•

SBRT: Slightly biased region threshold (R2) is set to 25% For 33/6.9 kV transformers Ith is set to 20%

•

SBRL: Slightly biased region limit is set to 1.0, corresponding to full load Slope is set to 1 so that wider area is covered under tripping zone and at the same time higher than the minimum setting to provide the sufficient bias during through fault condition and CT situation conditions. For 33/6.9 kV transformers Ith is set to 0.5

•

Trip Id> is set at 5.0, which is higher than the inrush current

•

I2 Block and I5 Block for the harmonic current is taken as to be at the default set value



Mott MacDonald CTJV

3.2.9.5 Setting of 87M protection for motor Relay Type: REM 543 Differential protection of the motors using REM 543 is based on stabilized three-phase differential protection11. Basic relay characteristic is shown below

Figure 3-6: Three-phase stabilized differential protection for motors The setting groups are as follows •

Basic setting (Id>): Pickup for the differential element (5 – 50 %)

•

Turing point 1: Value of Ib/In from where the first slope starts (0.0 – 1.0 In)

•

Starting ratio: Slope of the line after the Turning point 1 (10 - 50%)

•

Turning point 2: Value of Ib/In from where second slope starts (1.0 – 3.0 In)

•

Inst. Setting (Id>>): Instantaneous differential element pickup (5.0 – 30.0 In)

11

“Diff6G-Stabilized Three-Phase Differential Protection for Generators” ABB document number 1MRS752302-MUM, version C/18.1.2002



Mott MacDonald CTJV

Settings adopted for BOG compressor motor relay are set as under

S. No.

Motor Rating (kW) Calculation parameters

9500

1

CT ratio

700/1

2

Basic setting (Id>) [5 – 50%]

10

3

Turing point 1 [0.0 – 1.0 In]

0.5

4

Starting ratio [10 – 50%]

50

5

Turning point 2 [1.0 – 3.0 In]

1.5

6

Inst. Setting (Id>>) [5.0 – 30 In]

5.0

Table 3-11: Setting of 87M protection for MV BOG compressors



Mott MacDonald CTJV

3.2.10 Setting of 25 function for ATS at 33 kV and 6.6 kV levels Relay type: REF 542+ The relay operates when the Delta Voltage and Delta Angle are within the set limits for a specified Time Delay, based on this Delta Voltage = 0.05 pu Delta Angle = 10 Degree Time Delay = 15s Explanations of the above setting are given below Settings are as per the operating criteria described in the relay manual 12 Delta V is set as per the allowable LF voltage limits for HV and MV (5%) switchboards Delta Angle is set to 10 (More than this value may be the indicator of the overloads / faults on the switchboards). This is also supported by the load flow result under normal condition, where the buses angle were found to be near to 5 degree while in the single transformer operation exceeding 10 degree at 6.6 kV switchboards, in all these cases of LF Delta Angle is within 10 degree. Time delay is set to 15s to give enough time before Delta V and Delta Angle remain within the set values.

12

Relay REF 542+ manual “Protection functions: configuration and settings” ABB document number 1VTA10002 Rev03, en 3-25 221661/02/B - OCT 2007 P:\Glasgow\PSB\EEG\3Jobs\221661 QGX\CLP Studies\Report\221661A - QGX-CLP - Relay Coordination-Rev1.doc/CLP


Mott MacDonald CTJV

3.2.11 Over current protection for the LV systems LV motors and static loads protections are provided by the ABB make INSUM-2 relay. INSUM13 has an inbuilt CT which can be used for loads up to 63A, for loads more than 63 A an external CT is used to scale down the current as per the requirement of the application. ABB make MCCB with static release type PR221 and PR111 are used for the loads more than 45kW. Tables 3-11 and 3-12, presents the different type of MCCB used for different rating of LT loads and related setting of the releases. Settings of the INSUM-2 for each type of load as shown in the Tables 3-11 and 3-12 are presented in Appendix –A. TCCs of MCCBs are already reported in company approved QGX relay setting studies report14 . For the five LNG circulating pumps (415V - 104.4 kW) supplied by the LDB Siemens panels, the protection relay in use is GE multilin MM2, setting of which is provided by CTJV 15 and presented in Appendix A-1.

13

“MCU parameter description” Ver. 3.0, ABB document on the INSUM relay

14

Electrical system study for QGX, Company approved report – Relay co-ordination studies – Rev G, July 07, report submitted by Mott MacDonald Ltd. To CTJV 15

Email from Vincent to Manoj Gupta; dated 28/09/2007; subject: RE: QGXE2A4042 / CLP - LDB Relays in Satellite SS2701A, SS-2702A/B/C – Settings; Attachment: MM2 Setpoint File Information.pdf



Cub

Motor

Mott MacDonald CTJV

MCCB

S.

No. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

Size 6E 6E 6E 6E 6E 6E 6E 6E 6E 6E 6E 6E 6E 6E 6E 6E 6E 12E 12E

kW 0.18 0.25 0.37 0.55 0.75 1.1 1.5 2.2 3 4 5.5 7.5 11 15 18.5 22 30 37 45

I (A) 0.72 0.83 1.1 1.5 2 2.8 3.5 5 6.6 8.6 11.5 15.2 22 28.5 36 42 56 68 83

Type T2H160 MF 1 T2H160 MF 1 T2H160 MF 1.6 T2H160 MF 1.6 T2H160 MF 2 T2H160 MF 3.2 T2H160 MF 4 T2H160 MF 5 T2H160 MF 8.5 T2H160 MF 11 T2H160 MF12.5 T2H160 MA 20 T2H160 MA 32 T2H160 MA 52 T2H160 MA 52 T2H160 MA 52 T2H160 MA 80 T2H160 MA 80 T2H160 MA 100

Magnetic Tripping current (A) 13 13 21 21 26 42 52 65 110 145 163 200 288 364 468 520 800 960 1200

MCCB Setting t1 I2 t2

I1

-

-

-

-

Contactor

INSUM

Interpose

QGX Type A9 A9 A9 A9 A9 A9 A16 A26 A26 A30 A50 A50 A50 A50 A50 A63 A75 A95 A110

TYPE MCU2 0.1-3.2 A MCU2 0.1-3.2 A MCU2 0.1-3.2 A MCU2 0.1-3.2 A MCU2 0.1-3.2 A MCU2 63 A MCU2 63 A MCU2 63 A MCU2 63 A MCU2 63 A MCU2 63 A MCU2 63 A MCU2 63 A MCU2 63 A MCU2 63 A MCU2 63 A MCU2 63 A MCU2 0.1-3.2 A MCU2 0.1-3.2 A

CT KORC 1A 105/1 S KORC 1A 105/1 S

I3

13 13 13 13 13 13 13 13 13 13 13 10 9 7 9 10 10 12 12

Table 3-12: Direct on line starters with MCCB and INSUM-2, load up to 45kW



Cub Size

Motor kW I (A)

I1

MCCB Setting t1 I2 t2

I3

Contactor QGX Type

INSUM TYPE

Interpose CT

T4H250 PR221-I In 160

Tripping current (A) 1360

20

12E

55

98

-

-

-

-

8.5

A145

MCU2 0.1-3.2 A

KORC 1A 105/1 S

21

12E

75

135

T4H250 PR221-I In 250

1875

-

-

-

-

7.5

A185

MCU2 0.1-3.2 A

KORC 1A 185/1 S

22

16E

90

158

T4H250 PR221-I In 250

2000

-

-

-

-

8

A210

MCU2 0.1-3.2 A

KORC 1A 185/1 S

23

16E

110

193

T4H320 PR221-I In 320

2080

-

-

-

-

6.5

A260

MCU2 0.1-3.2 A

KORC 1A 310/1 S

24

Cub600

132

232

E2N1250In400 PR121/LI

2400

0.8

12

-

-

6

N/A

MCU2 0.1-3.2 A

SUCCESS 400/1 A

25

Cub600

FDR

630

T5H630In630 PR221-LSI

2835

1

3

-

-

4.5

26

Cub600

FDR

800

S6H800In800 PR212-LSI

6400

1

A

2

A

8

S. No.

MCCB Type

Mott MacDonald CTJV

Table 3-13: Direct on line starters with MCCB and INSUM-2, load more than 45kW



Appendix - A: Relay setting schedules

The relay setting schedule is organised as follows A1: LT relays setting schedule A2: 33 kV feeders relay setting schedule A3: 33/6.6 kV and 6.6/0.415 kV transformer relay setting schedule A4: MV motor relay setting schedule

A1 221661/02/B - OCT 2007/1 of 1 P:\Glasgow\PSB\EEG\3Jobs\221661 QGX\CLP Studies\Report\221661A - QGX-CLP - Relay Coordination-Rev1.doc/CLP

Mott MacDonald CTJV


Mott MacDonald CTJV

A-1: LV relays setting schedule Setting Guideline for Auto-Restart Function

With referring to the Annexure-III (Motor Auto Restart Study) of the QGX relay setting report 13, autoRestart setting is provided for the LV motors required to be re-started as per the following guideline; Device Duty: Function 27 Setting Parameter:

•

Reset Voltage Level (RVL) Range: 50 - 100% Setting: 90%

•

Max Auto Re-closing Time (MAT) Range: 0.0 - 5.0sec Setting: 0.0sec16

•

Max. Power down Time (PDT) Range: 0 - 1200sec Setting: 5sec (Refer Note-1 below)

•

Staggered Start Time (SST) Range: 0 -1200sec Setting: Refer Note-2 below

Note-1: Referring to the Annexure-IV (Transformer Energization Study) of the QGX relay setting report13. Note-2: Setting value to be as per "Switch-In Time" for each priority group specified in Annexure-III (Motor Auto Restart Study) of the QGX relay setting report 13.

16

Email from Toshiaki Saito to Manoj Gupta dated 22/06/2007; Subject: Re: QGX : Wrap-up Comment on Relay Coordination Study (INSUM Setting)



S.N Cub. o. Size

Rated Rated I Protection kW A Type

INSUM CT ratio TYPE

Mott MacDonald CTJV

Device Setting range Duty

Schedule for LV (0.415 kV) feeders ST

Setting

NR-DOL/RCU Starter Type

MRD

As per Motor Data

In = 0.10 - 3.20 A Ist = 1.0 - 10 In Tst = 1 - 600s 49

Function TOL TOL Type t6 = 5 - 40s CDTF = 1 - 100 AL = 50 - 100%

51 LR Stall Protection Trip Level Trip Delay 1

6E

0.18

0.72

TYPE -C

MCU2

Remark

0.72 6 5

Nominal current Startup ratio

Enable Standard As per Motor Data 10 cool down time fact. 4 Alarm level 90 Trip Only 400% 5sec

0.1 - 3.2A 51 G Function EF Method RCT Ip = 1,5,50 A AL = 0.1(0.1)
27

Function 27 Un = 230 - 690 V AL = 50 - 100% U< = 50 -100% t< = 0.2 - 5 s RVL = 50 - 100 % MAT = 0.0 - 5.0 s PDT = 0 - 1200 s SST = 0 - 1200s

Alarm Only Measure 1 Alarm level 0.3

Enable 415 Alarm level 80 Trip level 70 0 Trip delay for DOL/RCU 90 Reset Voltage Level Auto reclosing time 0 Note-1 5 As per annexure-III Of the QGX – Rev G report



Mott MacDonald CTJV ST


MRD

As per Motor Data

In = 0.10 - 3.20 A Ist = 1.0 - 10 In Tst = 1 - 600s 49



6E

0.25

0.83

TYPE-C

MCU2

0.83 6 5

27


ST

Enable Standard As per Motor Data 10 cool down time fact. 4 90 Alarm level Trip Only 400% 5sec

Alarm Only Measure 1 0.3 Alarm level

Enable 415 Alarm level 80 70 Trip level Trip delay for DOL/RCU 0 Reset Voltage Level 90 Auto reclosing time 0 5 Note-1 As per annexure-III NR-DOL/RCU Starter Type

MRD

As per Motor Data

In = 0.10 - 3.20 A Ist = 1.0 - 10 In Tst = 1 - 600s 49


51 LR Stall Protection Trip Level Trip Delay 6E

0.37

1.1

TYPE-C

MCU2

Startup ratio

3

Nominal current

1.1 6 5



27



Enable 415 Alarm level 80 Trip level 70 Trip delay for DOL/RCU 0 Reset Voltage Level 90 Auto reclosing time 0 5 Note-1 As per annexure-III Of the QGX – Rev G report





MRD

As per Motor Data

In = 0.10 - 3.20 A Ist = 1.0 - 10 In Tst = 1 - 600s 49



6E

0.55

1.5

TYPE-C

MCU2

1.5 6 5

27


ST




MRD

As per Motor Data

In = 0.10 - 3.20 A Ist = 1.0 - 10 In Tst = 1 - 600s 49



0.75

2

TYPE-C

MCU2

Startup ratio

5

Nominal current

2 6 5



27








MRD

As per Motor Data

In = 2.0 - 63.0 A Ist = 1.0 - 10 In Tst = 1 - 600s 49



6E

1.1

2.8

TYPE-C

MCU2

2.8 6 5

27


ST



Enable 415 Alarm level 80 Trip level 70 Trip delay for DOL/RCU 0 90 Reset Voltage Level Auto reclosing time 0 Note-1 5 As per annexure-III NR-DOL/RCU Starter Type

MRD

As per Motor Data

In = 2.0 - 63.0 A Ist = 1.0 - 10 In Tst = 1 - 600s 49



1.5

3.5

TYPE-C

MCU2

Startup ratio

2.0-63.0 A 51 G Function EF Method RCT Ip = 1,5,50 A AL = 0.1(0.1)
7

Nominal current

3.5 6 5


Enable Standard 10 As per Motor Data 4 cool down time fact. Alarm level 90 Trip Only 400% 5sec

27



Enable 415 80 Alarm level 70 Trip level Trip delay for DOL/RCU 0 Reset Voltage Level 90 0 Auto reclosing time 5 Note-1 As per annexure-III Of the QGX – Rev G report





MRD

As per Motor Data

In = 2.0 - 63.0 A Ist = 1.0 - 10 In Tst = 1 - 600s 49

8

6E

2.2

5

TYPE-C

MCU2

2.0-63.0 A


51 LR Stall Protection Trip Level Trip Delay Trip Delay 51 G Function EF Method RCT Ip = 1,5,50 A AL = 0.1(0.1)
27


ST

5 6 5

Trip Only 400% 5sec 5sec Alarm Only Measure 1 Alarm level 0.3


As per Motor Data

In = 2.0 - 63.0 A Ist = 1.0 - 10 In Tst = 1 - 600s Function TOL TOL Type t6 = 5 - 40s CDTF = 1 - 100 AL = 50 - 100%


6E

3

6.6

TYPE-C

MCU2

Startup ratio

Enable Standard As per Motor Data 10 cool down time fact. 4 90 Alarm level

MRD

49

Nominal current

6.6 6 5



27








MRD

As per Motor Data

In = 2.0 - 63.0 A Ist = 1.0 - 10 In Tst = 1 - 600s 49



6E

4

8.6

TYPE-C

MCU2

8.6 6 5

27


ST




MRD

As per Motor Data

In = 2.0 - 63.0 A Ist = 1.0 - 10 In Tst = 1 - 600s 49



5.5

11.5

TYPE-C

MCU2

Startup ratio

11

Nominal current

11.5 6 5



27








MRD

As per Motor Data

In = 2.0 - 63.0 A Ist = 1.0 - 10 In Tst = 1 - 600s 49



6E

7.5

15.2

TYPE-C

MCU2

15.2 6 5

27


ST




MRD

As per Motor Data

In = 2.0 - 63.0 A Ist = 1.0 - 10 In Tst = 1 - 600s 49



11

22

TYPE -C

MCU2

Startup ratio

13

Nominal current

22.0 6 5



27








MRD

As per Motor Data

In = 2.0 - 63.0 A Ist = 1.0 - 10 In Tst = 1 - 600s 49



6E

15

28.5

TYPE-C

MCU2

28.5 6 5

27


ST




MRD

As per Motor Data

In = 2.0 - 63.0 A Ist = 1.0 - 10 In Tst = 1 - 600s 49



18.5

36

TYPE-C

MCU2

Startup ratio

15

Nominal current

36.0 6 5



27








MRD

As per Motor Data

In = 2.0 - 63.0 A Ist = 1.0 - 10 In Tst = 1 - 600s 49



6E

22

42

TYPE-C

MCU2

42.0 6 5

27


ST




MRD

As per Motor Data

In = 2.0 - 63.0 A Ist = 1.0 - 10 In Tst = 1 - 600s 49



30

56

TYPE-C

MCU2

Startup ratio

17

Nominal current

56.0 6 5



27





Electrical System Studies for QGX-CLP Development Project Relay Co-ordination Studies 0.1 - 3.2 A

Mott MacDonald CTJV

ST


Ext CT1 Ip = 10 - 6300A Ext CT Is = 0.01 - 3.20 A

105 1

MRD

As per Motor Data

In = 10.5 - 105A Ist = 1.0 - 10 In Tst = 1 - 600s 49

18

12E

37

73.5

TYPE-B

MCU2


51 LR Stall Protection Trip Level KORC 1A Trip Delay

51 G Function EF Method RCT Ip = 1,5,50 A AL = 0.1(0.1)
0.1 - 3.2 A


ST

73.5 5.6 6

Enable Standard 15 As per Motor Data 4 cool down time fact. 90 Alarm level Trip Only 400% 5sec

Alarm Only Measure 1 0.3 Alarm level Enable 415 Alarm level 80 Trip level 70 Trip delay for DOL/RCU 0 90 Reset Voltage Level 0 Auto reclosing time Note-1 5 As per annexure-III

105 1

MRD

As per Motor Data

In = 10.5 - 105A Ist = 1.0 - 10 In Tst = 1 - 600s

19

12E

45

84

TYPE-B

MCU2



Startup ratio



49

Nominal current


84.0 5.9 5



Alarm Only Measure 1 0.3 Alarm level Enable 415 80 Alarm level 70 Trip level Trip delay for DOL/RCU 0 90 Reset Voltage Level Auto reclosing time 0 Note-1 5 As per annexure-III Of the QGX – Rev G report



Mott MacDonald CTJV

ST



105 1

MRD

As per Motor Data

In = 10.5 - 105A Ist = 1.0 - 10 In Tst = 1 - 600s 49

20

12E

55

105

TYPE-B

MCU2



0.1 - 3.2 A


ST

105.0 5.3 6



185 1

MRD

As per Motor Data

In = 18.5 - 185A Ist = 1.0 - 10 In Tst = 1 - 600s

21

12E

75

129.5

TYPE-B

MCU2



Startup ratio



49

Nominal current


129.5 6.2 5



Alarm Only Measure 1 0.3 Alarm level Enable 415 80 Alarm level 70 Trip level Trip delay for DOL/RCU 0 90 Reset Voltage Level Auto reclosing time 0 Note-1 5 As per annexure-III Of the QGX – Rev G report



Mott MacDonald CTJV

ST



185 1

MRD

As per Motor Data

In = 18.5 - 185A Ist = 1.0 - 10 In Tst = 1 - 600s 49

22

16E

90

166.5

TYPE-B

MCU2

166.5 5.7 6


Trip Only 400% 5sec

0.1 - 3.2 A



ST



310 1

MRD

As per Motor Data

In = 31 - 310A Ist = 1.0 - 10 In Tst = 1 - 600s 49

23

16E

110

186

TYPE-B

MCU2

186.0 5.7 6


Startup ratio

Trip Only 400% 5sec

Nominal current

Enable Standard 12 As per Motor Data 4 cool down time fact. 90 Alarm level


27

Startup ratio

Enable Standard 15 As per Motor Data 4 cool down time fact. 90 Alarm level


27

Nominal current


Enable 415 80 Alarm level 70 Trip level Trip delay for DOL/RCU 0 90 Reset Voltage Level Auto reclosing time 0 Note-1 5 As per annexure-III Of the QGX – Rev G report




0.1 - 3.2 A



400 1

MRD

As per Motor Data

In = 40 - 400A Ist = 1.0 - 10 In Tst = 1 - 600s 49

24 Cub600

132

240

TYPE-A

MCU2

Success


51 LR Stall Protection Trip Level Trip Delay


240.0 5.8 6


Enable Standard 18 As per Motor Data cool down time fact. 4 Alarm level 90 Trip Only 400% 5sec

Alarm Only Measure 1 0.3 Alarm level Enable 415 80 70 Trip delay for DOL/RCU 0 90 Reset Voltage Level Auto reclosing time 0 Note-1 5 As per annexure-III Of the QGX – Rev G report

For the five LNG circulating Siemens panels are presented below:

pumps

(415V

-

104.4

kW)

supplied

by

the

LDB

27-MP 7111and 27-MP 7112 at the switchboard LDB 27302 27-MP 7113 at the switchboard LDB 27305 27-MP 7114 and 27-MP 7115 at the switchboard LDB 27306 The protection relay in use is GE multilin MM2, setting of which is provided by CTJV 17 and presented below:

17

Email from Vincent to Manoj Gupta; dated 28/09/2007; subject: RE: QGXE2A4042 / CLP - LDB Relays in Satellite SS2701A, SS-2702A/B/C – Settings; Attachment: MM2 Setpoint File Information.pdf




Mott MacDonald CTJV



Mott MacDonald CTJV



Mott MacDonald CTJV



Mott MacDonald CTJV


Mott MacDonald CTJV

A-2: HV feeders relay setting schedule

S.No.

Switch Board ID

Voltage (kV)

Panel Number

Feeder Name

Device Type / Manufacturer

CT ratio

Device Duty

Setting range

Setting

Remark

Schedule for 33 kV feeders

2000/1

1

SB27101A

33

A1 B1

Incoming A/B TR27101 A/B

51

I> = 0.05-40 Curve = NI, EI, VI, DT k = 0.05 - 1.5

50

I>> = 0.05-40

50N

t>> = 0.02 to 300s I0>> = 0.05 - 40 k = 0.05 - 1.5

0.95 Curve = NI 0.12

1

Output to ATS

0.02 0.05 0.05 (NI)

Output to ATS

REF 542 + 51N

51G 400/1


I0>> = 0.05-40 Curve = NI, EI, VI, DT k = 0.05 - 1.5 t0>>DT = 0.04 to 300s

0.05 Curve = DT

I0> = 0.05-40 Curve = NI, EI, VI, DT k = 0.05 - 1.5

I0>0.25 Curve = DT

t0>DT = 0.04 to 300s

t0>DT = 0.72

0.42


S.No.

Switch Board ID

Voltage (kV)

Panel Number

Feeder Name

Mott MacDonald CTJV


CT ratio

Device Duty 51

2

3

SB27101A

SB27101A

33

33

A2 B2

A4 B4

TR-27204 A/B

TR-27604 TR-27605

REF 542 +

REF 542 +

Setting Setting range I> = 0.05-40 Curve = NI, EI, VI, DT k = 0.05 - 1.5

Remark 0.75

Curve = NI 0.15

50

I>>> = 0.05-40 t>>> = 0.015 to 300s

9.85 0.015

27

U< pickup (relay logic) Time delay

51N

I0> = 0.05-40 Curve = NI, EI, VI, DT t0>DT = 0.04 to 300s

I0>0.15 Curve = DT t0>DT = 0.12

51


Curve = EI

600/1 50% 4s

CB Open (Not to trip)

1.25 0.2

50

I>>> = 0.05-40 t>>> = 0.015 to 300s

10.35 0.015

27


51N

I0> = 0.05-40 Curve = NI, EI, VI, DT

I0>0.15 Curve = DT

t0>DT = 0.04 to 300s

t0>DT = 0.12

600/1


50% 4s

CB Open (Not to trip)


S.No.

Switch Board ID

Voltage (kV)

Panel Number

Feeder Name

Mott MacDonald CTJV


CT ratio

Device Duty

51

4

SB27101A

33

A5 B5

TR-27603 TR-27606

REF 542 +

SB27101A

33

A6 B7

SB-27104 SB-27105

REF 542 +

Setting

Remark


Curve = EI

1.25 0.2

50

I>>> = 0.05-40 t>>> = 0.015 to 300s

10.35 0.015

27


51N

I0> = 0.05-40 Curve = NI, EI, VI, DT

I0>0.15 Curve = DT

t0>DT = 0.04 to 300s

t0>DT = 0.12


Curve = EI

600/1

51

5

Setting range

50% 4s

1.65 0.05

50

I>>> = 0.05-40 t>>> = 0.015 to 300s

6.85 0.015

27


51N

I0> = 0.05-40 Curve = NI, EI, VI, DT

I0>0.15 Curve = DT

t0>DT = 0.04 to 300s

t0>DT = 0.12

600/1


50% 4s


S.No.

6

Switch Board ID

SB27101A

Voltage (kV)

33

Panel Number

A7 B6

Feeder Name

SB-27102 SB-27103

Mott MacDonald CTJV


REF 542 +

CT ratio

Device Duty

Setting range

Setting

51


0.75 Curve = NI 0.29

50

I>>> = 0.05-40 t>>> = 0.015 to 300s

6.85 0.15

27


50% 4s

51N

I0> = 0.05-40 Curve = NI, EI, VI, DT

I0>0.25 Curve = DT

t0>DT = 0.04 to 300s

t0>DT = 0.12


Curve = NI

400/1

51

7

SB27102 SB27103

33

RMU outgoing feeder to SB27201

RMU outgoing feeder

7SJ600

Remark

0.7 0.2

50

I>>> = 0.1-25 t>>> = 0.0 to 60s

6.9 0.01

27


50% 4s

51N

I0> = 0.05-25 Curve = NI, EI, VI, DT

I0>0.25 Curve = DT

t0>DT = 0.0 to 60s

t0>DT = 0.12

400/1



S.No.

8

Switch Board ID

SB27104 SB27105

Voltage (kV)

33

Panel Number

RMU outgoing feeder BOG Compressor

Feeder Name

RMU outgoing feeder

Mott MacDonald CTJV


7SJ600

CT ratio

Device Duty

600/1


Setting range

Setting

Remark

51


1.6 Curve = EI 0.05

50

I>>> = 0.1-25 t>>> = 0.0 to 60s

6.9 0.01

27


50% 4s

51N

I0> = 0.05-25 Curve = NI, EI, VI, DT

I0>0.15 Curve = DT

t0>DT = 0.0 to 60s

t0>DT = 0.12


Mott MacDonald CTJV

A-3: Interface with Kahramaa - Schedule for 87L and 87T protection S.No.

Switch Board ID

Voltage (kV)

Panel Number

Feeder Name


CT ratio

Device Duty

Setting range

Setting

Remark

Schedule for line differential protection From up stream 400/1

A7

1A

SS-2702

33

All outgoing 33 kV feeders

SS-2702

87L

Down stream 400/1

A2-A6

From

1B

Solkor-N B6

33

All outgoing 33 kV feeders

up stream 600/1 Solkor-N B2-B5, B7

87L

Down stream 600/1


Id> = 0.1 - 2.5 In BS1 = 20 - 150 % BS2 = 30 - 150 % Ibreak = 0.5 - 20.0 In td> 0.0 - 10 s CT Ratio Cor = 0.50 - 1.0 CT Ratio Cor = 0.50 - 1.0 Internal Trip = ON, OFF External Trip = ON, OFF Delay Ex. Trip = 0.0 - 10s

0.1 20 150 1 0.05 1 1 OFF ON 0

Differential current 1st Bias slope 2nd Bias slope Bias break point Differential delay At up-stream relay At down stream relay

Id> = 0.1 - 2.5 In BS1 = 20 - 150 % BS2 = 30 - 150 % Ibreak = 0.5 - 20.0 In td> 0.0 - 10 s CT Ratio Cor = 0.50 - 1.0 CT Ratio Cor = 0.50 - 1.0 Internal Trip = ON, OFF External Trip = ON, OFF Delay Ex. Trip = 0.0 - 10s

0.1 20 150 1 0.05 1 1 OFF ON 0

Differential current 1st Bias slope 2nd Bias slope Bias break point Differential delay At up-stream relay At down stream relay

External trip delay

External trip delay


S.No.

2

Switch Board ID

Interface with KM 132 kV SSRLS2

Voltage (kV)

132

Panel Number

132 kV KM S/S Outgoing feeders to QGXCLP

Feeder Name

Mott MacDonald CTJV


CT ratio

Device Duty

800/1

C30

7SD53

87L

800/1

C40

C30

3

Interface with KM 132 kV SSRLS2

132

132 kV KM S/S Outgoing feeders to QGXCLP

800/1

REL 561

C40

87L

800/1

Setting range

A26

Remark

I-Diff> = 0.1 - 20.00 A

0.12

I-Diff> pickup value

I-Diff>Switch On TD I-Diff>= 0.0 - 60.0 s T310 Iphas = 0.0 to 0.5 s Ic-Com = ON, OFF IcSTAB/IcN = 2.0 - 4.0 I-Diff>> = 0.8 - 100.0 A I-Diff>>Switch On Inrush restraint = ON, OFF I2/In = 10 - 45% Cross block = NO, YES Imax-inrush = 1.1 - 25.0 A Cross B 2HM

0.36 0 0 OFF 1.25 5 ON 15 NO 9 0

I-Diff> under switch on Time delay for I-Diff

CTFactor = 0.4-1.0 IminSat = 100-1000% In IminOp = 20-150% In IdiffLvl1= 20-150% Ib IdiffLvl2= 30-150% Ib ILvl1/2Cross = 100-1000% Ib Evaluate = 2 of 4, 3 of 4 AsymDelay = 0.0 - 5.0 ms DiffSync = Mater, Slave CCComp = ON, OFF

221661/02/B - OCT 2007/26 of 2 P:\Glasgow\PSB\EEG\3Jobs\221661 QGX\CLP Studies\Report\221661A - QGX-CLP - Relay Coordination-Rev1.doc/CLP

Setting

1 300 20 50 100 350 3 of 4 0 Master Slave OFF

Charging current comp. Ic stabilization I-Diff>> pickup value

2nd Harmonic % of In Max. inrush peak value

CT matching factor Imin for saturation detection Idiff pickup Slope 1 Slope 2 Slope 2 intersection Tripping condition Asymmetrical delay At Kahramma substation At QGX-CLP SS-2702 Charging current comp.


S.N o.

4

SB ID

SB27101

Voltage (kV)

33

Panel Number

A1 B1

Feeder Name

TR-27101 A/B

Device / Manufactur er

7UT612

Mott MacDonald CTJV

CT ratio

Up stream 800/1

Device Duty

87T

Down stream 2000/1

Setting range

Diff. Prot. INC. CHAR.START INRUSH 2. HARM. REST.n.HAR. I-Diff>Mon I>Curr. GUARD DIFFw.IE1-MEAS DIFFw.IE2-MEAS I-DIFF> 0.05 - 2.00 (0.01) T I-DIFF> = 0.0 - 60.00s I-DIFF>> = 0.5-35.0 (0.1) T-IDIFF>> = 0.0 - 60.00s SLOPE 1= 0.1 - 0.5 BASE Point1 = 0.0 - 2.00 SLOPE 2 = 0.25 - 0.95 BASE Point2 = 0.0 - 10.0 I-REST. STARTUP = 0.0 - 2.0 START-FACTOR = 1.0 - 2.0 T START MAX = 0 - 180s I-ADD ON STAB = 2.0 - 15.0 T ADD ON STAB = 2- 250 2. HARMONIC = 10- 80% CROSSB.2.HARM = 2-1000 n. HARMONIC = 10 - 80% CROSSB.n.HARM = 2-1000 IDIFFmax.n.HM = 0.5 - 20 I-DIFF>MON T I-DIFF>MON = 1 - 10s


Setting

ON OFF ON 5. Harm ON 0 NO NO 0.25 0 4.7 0 0.25 0.5 0.5 1 0.1 1 0 3 250 15 20 30 0 1.5 0.25 2

Remark

Increase of trip char. Inrush 2nd Harm. Restraint nth Harmonic Restraint Diff. current monitoring I> for current guard

Id> pickup Time delay for Id> Id>> pickup Time delay for Id>>

Differential relay characteristic

I-RESTRAINT for start detc. Factor for increasing Char. Starting time Pickup for ADD on Stability Cycles for ADD on stability 2nd Harmonic Content in Id> Cycles for cross block 2nd harm. nth Harmonic in Id> Cylces for cross block nth harm. Limit Id> max for nth harm. Rest. Diff current for monitoring Monitoring time delay


S.No.

5

Switch Board ID

SB27101

Voltage (kV)

Panel Number

A1 33

Feeder Name

Mott MacDonald CTJV


TR-27101 A/B

7UT612

33 B1

87N 2000/1

Up stream 800/1

A1

SB27101

Device Duty

400/1

B1

6

CT ratio

TR-27101 A/B

REF 542 +

87T Down stream 2000/1

Setting range

REF Prot = ON, OFF, BLOCK I-REF> = 0.05 - 2.0 In TD-IREF = 0.0 - 60.0 s Slope = 0.00 - 0.95 VG = 0 - 11 Earthing P: Yes / No Earthing S: Yes / No Ip = 10 - 100000 A Is = 10 - 100000 A Ith = 0.1 - 0.5 Ir URL = 0.5 - 5.0 SBRT = 0.2 - 2.0 SBRL = 1.00 - 2.00 Ir Slope = 0.4 - 1.0 Trip Id> = 5.00-40.00 I2 Block= 0.1 - 0.3 I5 Block = 0.1 - 0.3


Setting

Remark

ON 0.25 0 0.5

I REF> pickup value Time delay Slope of characteristic 0

Transformer vector gp.

Yes Yes 437 1750 0.2 0.5 0.25 1 1 5 0.3 0.3

Threshold current Unbiased region limit Slightly biased threshold Slightly biased region limit Third region slope Upper Id threshold for trip 2nd harmonic threshold 5th harmonic threshold


Mott MacDonald CTJV

A-3: 33/6.6 kV and 6.6/0.415 kV transformer relay setting schedule S. Switch No Board ID .

Voltage Feeder Name (kV)

Device Type / Device CT ratio Setting range Manufacturer Duty

Setting

Remark

Schedule for 6.6 kV switch board SB-27204

51

50 2500

50N

51N

51G 400/1

REF 542 +

1 SB-27204

6.6

I> = 0.05-40 Curve = NI, EI, VI, DT k = 0.05 - 1.5 t>DT = 0.02 to 300s

0.85 NI 0.07

I>> = 0.05-40 t>> = 0.02 to 300s I0>> = 0.05 - 40 k = 0.05 - 1.5

1.6 0.015 0.05 0.05 (NI)

I0>> = 0.05-40 Curve = NI, EI, VI, DT k = 0.05 - 1.5 t0>>DT = 0.04 to 300s

0.05 DT 0.72

I0> = 0.05-40 Curve = NI, EI, VI, DT k = 0.05 - 1.5 t0>DT = 0.04 to 300s

27

U< = 0.1 - 1.2 Un t< = 40 - 30,000 ms

87

VG = 0 - 11 Earthing P: Yes / No Earthing S: Yes / No Ip = 10 - 100000 A Is = 10 - 100000 A Ith = 0.1 - 0.5 Ir URL = 0.5 - 5.0 SBRT = 0.2 - 2.0 SBRL = 1.00 - 2.00 Ir Slope = 0.4 - 1.0 Trip Id> = 5.00-40.00 I2 Block= 0.1 - 0.3 I5 Block = 0.1 - 0.3

0.25 DT 1.02 0.7 70

PT 6.6/0.11

Incoming A/B TR-27204 A/B 20000 kVA

87L

Solkor-N (33 kV side)

600/1

11 Transformer vector gp. No Yes 437

Id> = 0.1 - 2.5 In BS1 = 20 - 150 % BS2 = 30 - 150 % Ibreak = 0.5 - 20.0 In td> 0.0 - 10 s CT Ratio Cor = 0.50 - 1.0 Internal Trip = ON, OFF OFF External Trip = ON, OFF ON Delay Ex. Trip = 0.0 - 10s


2092

0.1 Threshold current 0.5 Unbiased region limit 0.2 Slightly biased threshold 1 Slightly biased region limit 0.5 Third region slope 9 Upper Id threshold for trip 0.3 2nd harmonic threshold 0.3 5th harmonic threshold 0.2 Differential current 20 1st Bias slope 150 2nd Bias slope 1 Bias break point 0.05 Differential delay 1 CT raio correction

0 External trip delay


S. Switch No Board ID .



2500 2 SB-27204

6.6

Bus Coupler

Mott MacDonald CTJV

REF 542 +

PT 6.6/ 3 /

51

25

0.110/ 3

6.6

DTR27305A/B 1000 kVA

REF 542 +

150/1


51

6.6

TR-27303A/B 1600 kVA

REF 542 +

200/1

6.6

SB-27205A/B

REF 542 +

500/1

15 Time delay 0.65 NI 0.2

200A

I0> = 0.05-40 Curve = NI, EI, VI, DT t0>DT = 0.04 to 300s I> = 0.05-40

0.35 DT 0.12

0.85 NI

0.19

50

I>>> = 0.05-40 t>>> = 0.015 to 300s

51N


DT


NI

51

5 SB-27204

0.07

0.05 Delta voltage 10 Delta phase


Curve = NI, EI, VI, DT k = 0.05 - 1.5 4 SB-27204

NI

V = 0.02 - 0.4 Un Phase = 5 - 50 Deg.

Fuse ABB-CEF

51N

50

I>>> = 0.05-40 t>>> = 0.015 to 300s

51N


Remark 0.85

TD = 0.2 - 1000s 51

3 SB-27204

Setting

20 0.015 0.25 0.12 2.35 0.05 11.75 0.015 0.25 DT


0.42




Mott MacDonald CTJV


Schedule for 11 kV switch b oard SB-27603 51 I> = 0.05-40 Curve = NI, EI, VI, DT k = 0.05 - 1.5 t>DT = 0.02 to 300s 50 REM 543

700/1

51N

51G REF542+

REM 543 SB-27603 1 To SB27606

11

Incoming TR-27603 to TR-27606 25000 kVA

400/1

I0>> = 0.05-40 Curve = NI, EI, VI, DT k = 0.05 - 1.5 t0>>DT = 0.04 to 300s I0> = 0.05-40 Curve = NI, EI, VI, DT k = 0.05 - 1.5 t0>DT = 0.04 to 300s

27

U< = 0.1 - 1.2 Un t< = 40 - 30,000 ms

87

VG = 0 - 11 Earthing P: Yes / No Earthing S: Yes / No Ip = 10 - 100000 A Is = 10 - 100000 A Ith = 0.1 - 0.5 Ir URL = 0.5 - 5.0 SBRT = 0.2 - 2.0 SBRL = 1.00 - 2.00 Ir Slope = 0.4 - 1.0 Trip Id> = 5.00-40.00 I2 Block= 0.1 - 0.3 I5 Block = 0.1 - 0.3

Remark

1.55 From 11 kV, 9500 kW Motor relay 0.78

EI

Used for 51LR 4.75 2 0.15 DT 0.12 0.25 DT 0.72 0.7 From 11 kV, 9500 kW 70 Motor relay

PT 6.6/0.11

REF542+

87L

Solkor-N (33 kV side)

I>> = 0.05-40 t>> = 0.02 to 300s I>>> = 0.05-40 Op. mode I>>>

Setting

600/1

11 Transformer vector gp. No Yes 437 1312 0.1 Threshold current 0.5 Unbiased region limit 0.2 Slightly biased threshold 1 Slightly biased region limit 0.5 Third region slope 9 Upper Id threshold for trip 0.3 2nd harmonic threshold 0.3 5th harmonic threshold

Id> = 0.1 - 2.5 In BS1 = 20 - 150 % BS2 = 30 - 150 % Ibreak = 0.5 - 20.0 In td> 0.0 - 10 s

0.2 Differential current 20 1st Bias slope 150 2nd Bias slope 1 Bias break point 0.05 Differential delay

CT Ratio Cor = 0.50 - 1.0 Internal Trip = ON, OFF External Trip = ON, OFF

1 CT raio correction OFF ON

Delay Ex. Trip = 0.0 - 10s


0 External trip delay




Mott MacDonald CTJV


Setting

Remark

Schedule for 0.415 kV switch boards

51

2500/1 1

TR-27303A/B SB-27303 0.415 TR-27301A/B SB-27301 1600 kVA

I> = 0.05-40 Curve = NI, EI, VI, DT

NI

k = 0.05 - 1.5

0.09

50

I>> = 0.05-40 t>> = 0.02 to 300s

4 For ATS 0.02 operation

27

U< = 0.1 - 1.2 Un t< = 40 - 30,000 ms

REF 542 +

51G 10/1

51


50

I>> = 0.05-40 t>> = 0.02 to 300s

27

U< = 0.1 - 1.2 Un t< = 40 - 30,000 ms

1600/1

0.7 70 0.25 DT 0.52


LDBDTR27302, 27302, 27305, 2 27305, 0.415 27306, 27306, 27307 A/B 27307 A/B 1000 kVA

1.05

0.95 NI 0.09 6.2 For ATS 0.02 operation

REF 542 +

51G 10/1


0.7 70

0.25 DT


0.52


Mott MacDonald CTJV

A-4: MV motor relay setting schedule Following functional blocks are used for the motor protection using REM 543

Relay REM 543

Protection Duty 51(I>) 50 (I>>>) 51N(I0>)

Non directinal over current low set Non directinal over current inst. Non directinal earth fault low set

Functional block name NOC3Low NOC3Inst NEF1Low

27(U<) 27 (U<<)

Undervoltage low set Undervoltage high set

UV3LOW UV3High

59 (U>)

Overvoltage low set

OV3Low

49

Thermal overload

TOL3Dev

46

Negative phase sequence

NPS3Low

66

Start-up supervision

MotStart

37 (I<)

Under current

NUC3St1

51LR

Lock rotor protection

NOC3High

47

Three-phase phase sequence

PSV3ST1

87M

Motor differential

Diff6G

Function name





Device Type

CT ratio

PT ratio

Mott MacDonald CTJV


Setting

Schedule for 6.6 kV switch board SB-27201

1

SB-27201 SB-27204

6.6

27-PM7102 LNG Loading REM 543 pump 589 kW

100/1

27

U< = 0.1 - 1.2 Un t< = 0.1 - 300 s Operation Mode = 0,1,2

59

U> = 0.10 - 1.60 Un t> = 0.05 - 300 s Operation Mode = 0,1,2,3

1.15 5 1

49

Ist = 0.1-10.00 In Tst = 0.1 - 120.0 s NC-st = 1-3 Device Type = 0-6 Trip Temp. = 80-120 % Alarm Temp. = 40-100% Reset Temp. = 40-100% Am Temp.= -50-100 Deg C TC-cooling = 1.0-10.0 TC-Heating = 1-999 min ST-CS = 0.0-999.0 min LT-CS = 0.0-999.0 min p = 0.0 - 1.0 S-TR =50-350 Deg C Tmax S = 0.0-350 Deg C ST-CR = 0.0-999.0 min LT-CR = 0.0-999.0 min p = 0.0 - 1.0 R-TR =50-350 Deg C Tmax R = 0.0-350 Deg C

3.6 1 3 3 120 90 60 50 6 30 14 69 0.5 70 155 4 69 0.25 80 200

46

Operation Mode = 0-2 I2> = 0.01 - 0.5 In K = 5.0 - 100.0 Start Delay = 0.1 - 60 s Tmin = 0.1 - 120 s Tmax =500 - 10000 s T cooling = 5 - 10000 s

66

Operation Mode = 0 - 2 Ist = 1.0 - 10.0 In Tst = 0.3 - 250 s Time limit = 1.0 - 500.0s Countdwn Rate = 2.0-250 s/h Stall time = 2.0 - 120.0s

1 3.6 1.1 2 3

37

Op. mode Op. criteria I< = 0.1 - 0.99 In t< = 0.1 - 600.0 s I< Block t< blocking

2 0 0.1 300

6.6/0.1 1

51

I> = 0.10 - 5.0 Op. mode I> k = 0.05 - 1.0

Fuse ABB - CEF 7.2 kV 51N I0> = 1 - 100% Curve = NI, EI, VI, DT t0>DT = 0.05 to 300s 51LR I>> = 0.05-40 t>> = 0.05 to 300s


0.7 0.5 1

2 0.05 5 1 7 3600 1800

Disable 0 1.35 EI 0.74 160 A

65 DT 0.12 2.7 0.5

Electrical System Studies for QGX-CLP Development Project Relay Co-ordination Studies S. Switch No Board ID .


Device Type

CT ratio

PT ratio

Mott MacDonald CTJV


Setting

Schedule for 6.6 kV switch board SB-27603 27 U< = 0.1 - 1.2 Un t< = 0.1 - 300 s Operation Mode = 0,1,2

1

SB-27603 SB-27606

11

27-KM7101 Motor 9500 kW

REM 543

0.7 0.5 1

59

U> = 0.10 - 1.60 Un t> = 0.05 - 300 s Operation Mode = 0,1,2,3

1.15 5 1

49

Ist = 0.1-10.00 In Tst = 0.1 - 120.0 s NC-st = 1-3 Device Type = 0-6 Trip Temp. = 80-120 % Alarm Temp. = 40-100% Reset Temp. = 40-100% Am Temp.= -50-100 Deg C TC-cooling = 1.0-10.0 TC-Heating = 1-999 min ST-CS = 0.0-999.0 min LT-CS = 0.0-999.0 min p = 0.0 - 1.0 S-TR =50-350 Deg C Tmax S = 0.0-350 Deg C ST-CR = 0.0-999.0 min LT-CR = 0.0-999.0 min p = 0.0 - 1.0 R-TR =50-350 Deg C Tmax R = 0.0-350 Deg C

3.7 10 3 3 120 90 60 50 6 20 14 69 0.5 90 155 4 69 0.25 100 200

46

Operation Mode = 0-2 I2> = 0.01 - 0.5 In K = 5.0 - 100.0 Start Delay = 0.1 - 60 s Tmin = 0.1 - 120 s Tmax =500 - 10000 s T cooling = 5 - 10000 s

66

Operation Mode = 0 - 2 Ist = 1.0 - 10.0 In Tst = 0.3 - 250 s Time limit = 1.0 - 500.0s Countdwn Rate = 2.0-250 s/h Stall time = 2.0 - 120.0s

47

Operation Mode = 0 - 7 U2> = 0.01 - 1.00 t2> = 0.04 - 60.00 s

5 0.05 1

87

Id> = 5 - 50% TP1 = 0.0 - 1.0 In Starting ratio = 10 - 50% TP2 = 1.0 - 3.0 In Id>> = 5 - 30 In

10.0 0.5 50 1.5 5

51

I> = 0.10 - 5.0 Op. mode I> k = 0.05 - 1.0

700/1 11/0.11

2 0.05 8 1 7 3600 1800 1 3.7 11 40 30

1.55 2 (EI) 0.78

51LR I>> = 0.05-40 t>> = 0.05 to 300s Op. mode I>> 50 I>>> = 0.05-40 Op. mode I>>> 51N I0> = 1 - 100% Curve = NI, EI, VI, DT t0>DT = 0.05 to 300s


2.8 0.5 1 4.75 2 15 1 (DT) 0.12


Mott MacDonald CTJV

Appendix - B: TCC for relay co-ordination The TCC of the over current (O/C) and motor protections are arranges as follows

S.No.

Relay location

CT ratio

Reference location voltage

Switch Board number

1

DTR-27305

150/1

6.6 kV

SB-27204

2

TR-27303

200/1

6.6 kV

SB-27204

3

MR-27PM7104A

100/1

6.6 kV

SB-27205

4

MR-27KM7101C

700/1

11 kV

SB-27603

5

TR-27204

600/1

33 kV

SB-27101

6

TR-27201

400/1

33 kV

SB-27101

B1 221661/02/B - OCT 2007/1 of 1 P:\Glasgow\PSB\EEG\3Jobs\221661 QGX\CLP Studies\Report\221661A - QGX-CLP - Relay Coordination-Rev1.doc/CLP

Electrical System Studies for QGX-CLP Development Project Mott MacDonald Relay Co-ordination Studies

CTJV

S.No.

Relay location

CT ratio


Switch Board number

1

DTR-27305

150/1

6.6 kV

SB-27204



CTJV

S.No.

Relay location

CT ratio


Switch Board number

2

TR-27303

200/1

6.6 kV

SB-27204



CTJV

S.No.

Relay location

CT ratio


Switch Board number

3

MR-27PM7104A

100/1

6.6 kV

SB-27205



CTJV

S.No.

Relay location

CT ratio


Switch Board number

4

MR-27KM7101C

700/1

11 kV

SB-27603

Settings of relay at the outgoing RMU feeders from switchboard SB-27104/5, is set equal to the relay settings of the 33kV feeder TR-27601 from the switchboard SB-29103 of the QGX system. The time margin with the upstream relay will not be available when the SB-27601 and SB-27602 are supplied either from the QGX system or CLP system; due to the tight relay co-ordination at the 33kV and upstream relays.



CTJV

S.No.

Relay location

CT ratio


Switch Board number

5

TR-27204

600/1

33 kV

SB-27101


221661A - QGX-CLP - Relay Coordination-Rev1

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