NARI PCS-985G Generator Relay

PCS-985G Generator Relay Instruction Manual

NR Electric Co., Ltd.

Preface

Preface Introduction This guide and the relevant operating or service manual documentation for the equipment provide full information on safe handling, commissioning and testing of this equipment. Documentation for equipment ordered from NR is dispatched separately from manufactured goods and may not be received at the same time. Therefore, this guide is provided to ensure that printed information normally present on equipment is fully understood by the recipient. Before carrying out any work on the equipment, the user should be familiar with the contents of this manual, and read relevant chapter carefully. This chapter describes the safety precautions recommended when using the equipment. Before installing and using the equipment, this chapter must be thoroughly read and understood.

Health and Safety The information in this chapter of the equipment documentation is intended to ensure that equipment is properly installed and handled in order to maintain it in a safe condition. When electrical equipment is in operation, dangerous voltages will be present in certain parts of the equipment. Failure to observe warning notices, incorrect use, or improper use may endanger personnel and equipment and cause personal injury or physical damage. Before working in the terminal strip area, the equipment must be isolated. Proper and safe operation of the equipment depends on appropriate shipping and handling, proper storage, installation and commissioning, and on careful operation, maintenance and servicing. For this reason, only qualified personnel may work on or operate the equipment. Qualified personnel are individuals who: 

Are familiar with the installation, commissioning, and operation of the equipment and of the system to which it is being connected;



Are able to safely perform switching operations in accordance with accepted safety engineering practices and are authorized to energize and de-energize equipment and to isolate, ground, and label it;



Are trained in the care and use of safety apparatus in accordance with safety engineering practices;



Are trained in emergency procedures (first aid).

Instructions and Warnings The following indicators and standard definitions are used: i

PCS-985G Generator Relay Date: 2013-6-23

Preface

DANGER! It means that death, severe personal injury, or considerable equipment damage will occur if safety precautions are disregarded. WARNING! It means that death, severe personal, or considerable equipment damage could occur if safety precautions are disregarded. CAUTION! It means that light personal injury or equipment damage may occur if safety precautions are disregarded. This particularly applies to damage to the device and to resulting damage of the protected equipment. WARNING! The firmware may be upgraded to add new features or enhance/modify existing features, please make sure that the version of this manual is compatible with the product in your hand. WARNING! During operation of electrical equipment, certain parts of these devices are under high voltage. Severe personal injury or significant equipment damage could result from improper behavior. Only qualified personnel should work on this equipment or in the vicinity of this equipment. These personnel must be familiar with all warnings and service procedures described in this manual, as well as safety regulations. In particular, the general facility and safety regulations for work with high-voltage equipment must be observed. Noncompliance may result in death, injury, or significant equipment damage. DANGER! Never allow the current transformer (CT) secondary circuit connected to this equipment to be opened while the primary system is live. Opening the CT circuit will produce a dangerously high voltage. WARNING! 

Exposed terminals

Do not touch the exposed terminals of this equipment while the power is on, as the high voltage generated is dangerous.

ii


Preface



Residual voltage

Hazardous voltage can be present in the DC circuit just after switching off the DC power supply. It takes a few seconds for the voltage to discharge. CAUTION! 

Earth

The earthing terminal of the equipment must be securely earthed. 

Operating environment

The equipment must only be used within the range of ambient environment detailed in the specification and in an environment free of abnormal vibration. 

Ratings

Before applying AC voltage and current or the DC power supply to the equipment, check that they conform to the equipment ratings. 

Printed circuit board

Do not attach and remove printed circuit boards when DC power to the equipment is on, as this may cause the equipment to malfunction. 

External circuit

When connecting the output contacts of the equipment to an external circuit, carefully check the supply voltage used in order to prevent the connected circuit from overheating. 

Connection cable

Carefully handle the connection cable without applying excessive force.

Copyright Version: R1.00

NR ELECTRIC CO., LTD. 69 Suyuan Avenue. Jiangning, Nanjing 211102, China

P/N: EN_YJBH2641.0086.0001

Tel: +86-25-87178185,

Fax: +86-25-87178208

Website: www.nrelect.com, www.nari-relays.com Copyright © NR 2013. All rights reserved

Email: [email protected]

We reserve all rights to this document and to the information contained herein. Improper use in particular reproduction and dissemination to third parties is strictly forbidden except where expressly authorized. The information in this manual is carefully checked periodically, and necessary corrections will be included in future editions. If nevertheless any errors are detected, suggestions for correction or improvement are greatly appreciated. We reserve the rights to make technical improvements without notice.

iii


Preface

Documentation Structure The manual provides a functional and technical description of this relay and a comprehensive set of instructions for the relay’s use and application. All contents provided by this manual are summarized as below:

1 Introduction Briefly introduce the application, functions and features about this relay.

2 Technical Data Introduce the technical data about this relay, such as electrical specifications, mechanical specifications, ambient temperature and humidity range, communication port parameters, type tests, setting ranges and accuracy limits and the certifications that our products have passed.

3 Operation Theory Introduce a comprehensive and detailed functional description of all protective elements.

4 Supervision Introduce the automatic self-supervision function of this relay.

5 Management Introduce the displayed measurement and recording in the relay.

6 Hardware Introduce the main function carried out by each plug-in module of this relay and providing the definition of pins of each plug-in module.

7 Settings List all the settings and some notes about the setting application.

8 Human Machine Interface Introduce the hardware of the human machine interface (HMI) module and a detailed guide for the user how to use this relay through HMI. It also lists all the information which can be view through HMI, such as settings, measurements, all kinds of reports etc.

9 Communication Introduce the communication port and protocol which this relay can support, IEC60970-5-103, IEC61850 and DNP3.0 protocols are introduced in details.

10 Installation Introduce the recommendations on unpacking, handling, inspection and storage of this relay. A guide to the mechanical and electrical installation of this relay is also provided, incorporating earthing recommendations. A typical wiring connection to this relay is indicated. iv


Preface

11 Commissioning Introduce how to commission this relay, comprising checks on the calibration and functionality of this relay.

12 Maintenance A general maintenance policy for this relay is outlined.

13 Decommissioning and Disposal A general decommissioning and disposal policy for this relay is outlined.

14 Manual Version History List the instruction manual version and the modification history records.

Typographic and Graphical Conventions Deviations may be permitted in drawings and tables when the type of designator can be obviously derived from the illustration. The following symbols are used in drawings:

& AND gate

≥1

OR gate

Comparator

Binary signal via opto-coupler

BI

SET

I>

Input signal from comparator with setting

EN

Input signal of logic setting for function enabling

SIG

Input of binary signal except those signals via opto-coupler

OTH

Input of other signal

XXX

Output signal

v


Preface Timer t

Timer (optional definite-time or inverse-time characteristic)

t

10ms

0ms

[t1]

Timer [delay pickup (10ms), delay dropoff (0ms), non-settable]

0ms

Timer (t1: delay pickup, settable)

0ms

[t2]

Timer (t2: delay dropoff, settable)

[t1]

[t2]

Timer (t1: delay pickup, t2: delay dropoff, settable)

IDMT

Timer (inverse-time characteristic)

* *

Instrument current transformer

Instrument voltage transformer

Symbol Corresponding Relationship Basic

Example

A, B, C

L1, L2, L3

Ia, Ib, Ic, I0

IL1, IL2, IL3, IN

AN, BN, CN

L1N, L2N, L3N

Ua, Ub, Uc

VL1, VL2, VL3

ABC

L123

Uab, Ubc, Uca

VL12, VL23, VL31

U (voltage)

V

U0, U1, U2

VN, V1, V2

vi


1 Introduction

1 Introduction Table of Contents 1 Introduction..................................................................................... 1-a 1.1 Application....................................................................................................... 1-1 1.2 Function ........................................................................................................... 1-1 1.3 Features ........................................................................................................... 1-3 1.4 Order Information............................................................................................ 1-7

List of Tables Table 1.2-1 Function configuration of generator ..................................................................... 1-1 Table 1.2-2 Function configuration of excitation transformer/exciter ................................... 1-2 Table 1.2-3 Mechanical function configuration ........................................................................ 1-2

PCS-985G Generator Relay

1-a Date: 2013-06-23

1 Introduction

1.1 Application PCS-985G can be applied for large-scale turbo-dynamo, gas-turbine generator and nuclear power generator with different connection modes. PCS-985G provides complete electric quantity protection of a generator and an exciter or excitation transformer. It also supports ECT/EVT and meets the requirements of power plant automation. For a large-scale generator, two sets of PCS-985G can be used and then main protection, abnormal operation condition protection and backup protection can be duplicated. Control circuit and mechanical protection are installed on a separate panel. Two sets of PCS-985G use different CT groups and main and backup protection in one PCS-985G share one CT group. The outputs correspond to various trip coils.

1.2 Function PCS-985G takes fully into account maximum configuration of large-scale generator, and suits the generator with capacity of 100MW or above.

1.2.1 Protection Function PCS-985G can select to configure the following protection functions, and “＊” means that it is an abnormality alarm function. Table 1.2-1 Function configuration of generator No.

Function

Stage

Delay

ANSI

1

Differential protection

－

－

87G

2

DPFC differential protection

－

－

87G

3

Transverse differential protection

2

－

87G

4

Longitudinal residual overvoltage protection for inter-turn fault

1

1

59N/60

5

DPFC directional protection for inter-turn fault

1

1

67

1

1

6

Calculated longitudinal residual overvoltage protection for inter-turn fault

7

Voltage controlled overcurrent protection

2

1

50

8

Phase-to-phase impedance protection

2

1

21G

9

Fundamental residual voltage protection for stator earth fault

2

1

64S

10

Third harmonic overvoltage ratio protection for stator earth fault

1

1

64S

11

Third harmonic overvoltage differential protection for stator earth fault

1

1

64S

12

stator earth-fault protection with voltage injection

2

1

64R

13

Rotor one-point earth-fault protection

2

1

64R1

14

Rotor two-point earth-fault protection

1

1

64R2

15

Definite-time stator overload protection

2

1

50S

16

Inverse-time stator overload protection

－

－

51S

17

Definite-time negative-sequence overload protection

2

1

50Q

18

Inverse-time negative-sequence overload protection

－

－

51Q


1-1 Date: 2013-06-23

1 Introduction 19

Loss-of-excitation protection

3

1

40

20

Out-of-step protection

2

1

78

21

Overvoltage protection

2

1

59

22

Undervoltage protection

1

1

23

Definite-time over-excitation protection

2

1

24

24

Inverse-time over-excitation protection

－

－

24

25

Reverse-power protection

2

1

32R

26

Low-power protection

1

1

37G

27

Sequential tripping reverse-power protection

1

1

32R

28

Underfrequency protection

3

1

81U

29

Overfrequency protection

2

1

81O

30

Startup/shutdown protection of differential current

1

1

31

Startup/shutdown protection of residual voltage

1

1

32

Low-frequency overcurrent protection

1

1

50

33

Inadvertent energization protection

1

1

50/27

34

Breaker failure protection

1

2

50BF

35

＊Voltage balance function

－

－

60

36

＊VT circuit supervision

－

－

VTS

37

＊CT circuit supervision

－

－

CTS

Note! Rotor earth-fault protection can select voltage switchover principle or external voltage injection principle. Table 1.2-2 Function configuration of excitation transformer/exciter No.

Function

Stage

Delay

ANSI

1

Differential protection

－

－

87ET

2

Overcurrent protection

2

1

50

3

Definite-time overload protection

1

1

50

4

Inverse-time overload protection

－

－

51

Stage

Delay

ANSI

Table 1.2-3 Mechanical function configuration No.

Function

1

Mechanical protection 1

1

1

2


1

1

3


1

1

4


1

1

5


1

1

6


1

1

7


1

1

8


1

1


1-2 Date: 2013-06-23

1 Introduction

Note! The name of mechanical protection 1~8 can be modified.

1.2.2 Configuration Explanation 1.2.2.1 Differential Protection 1.

For generator with the capacity of 300MW or above, panel A and B are both equipped with generator differential protection.

2.

For generator differential protection, there are two kinds of percentage differential protection: variable slope percentage differential protection and DPFC percentage differential protection.

1.2.2.2 Backup Protection 1.

Panel A and B are equipped with complete set of backup protection of generator and excitation transformer/exciter. Different CTs are used for them.

2.

As to rotor earth-fault protection, two sets of such protection cannot work simultaneously otherwise influence between them will appear. Only one set of rotor earth-fault protection can be enabled during operation. If other set will be put into operation sometimes, this set shall be quitted firstly.

1.2.2.3 Current Transformer 1.

Panels A and B adopt different CT.

2.

Main protection and backup protection share one group of CT.

3.

Generator reverse power protection can share one group of generator terminal CT with generator differential protection, or adopt independent measurement CT.

1.2.2.4 Voltage Transformer 1.

Panel A and B shall adopt different VT or its different windings if possible.

2.

For generator inter-turn protection, in order to prevent undesired operation due to VT circuit failure at HV side used dedicatedly for this protection, one set of protection shall adopt two groups of VT. However, if it is considered to adopt only independent VT windings, too much VT will be installed at generator terminal and it is not reasonable. So it is recommended to equip three windings of VT there, namely VT1, VT2 and VT3. Panel A adopts voltage from VT1 and VT3 while panel B VT2 and VT3. During normal operation, panel A adopts VT1 and panel B adopts VT2 while VT3 is backup to both of them. If circuit of VT1 or VT2 fails, VT3 will be switched on automatically by software.

3.

For residual voltage, there are two windings adopted by two sets of protection equipments simultaneously in general.

1.3 Features 

High-performance general-purpose hardware and real-time calculations


1-3 Date: 2013-06-23

1 Introduction

Hardware structure of 32-bit microprocessors＋dual DSP is adopted. A number of processors operate in parallel. 32-bit microprocessors provide functions of HMI, communication, and printing, etc. The two DSPs provide protection operations and output logic. High performance hardware ensures real-time calculation for all relays in each sampling interval of this relay. This relay adopts 32-bit high performance CPUs and DSPs, internal high-speed bus, and intelligent I/O. Both hardware and software adopt modular design, which can be flexibly configured. Features include versatility, easy expansion, and easy maintenance. 

Independent fault detector elements

The output mode of fault detector “AND” protection operation eliminates the possibility of malfunction and misjudgment caused by hardware fault of the device. 

Strong EM compatibility

Integral panel and fully enclosed chassis are adopted. Strong electricity and weak electricity are strictly separated. Traditional rear board wiring mode is not used. At the same time, measures against interference are taken in software design, greatly improving the immunity to disturbances. EM radiation to outside satisfies relevant standards. 

Modular programs

Modular programs allow flexible protection configuration and easy functional adjustment. 

Variable slope percentage differential protection

Variable slope percentage characteristic is adopted for differential protection. Pickup slope and maximum slope should be reasonably set, so that high sensitivity can be gained during internal fault and transient unbalance current can be avoided during external fault. In order to prevent undesired operation of differential protection due to CT saturation, measures to discriminate CT saturation are provided for phase current at each side. 

DPFC percentage differential protection

DPFC percentage differential protection reflects only deviation components of differential current and restraint current and is not effected by load current. It can detect light fault within generator. Besides, it is insensitive to CT saturation since its restraint coefficient is set comparatively high. 

Detect CT Saturation by asynchronous method

According to relation between DPFC restraint current and DPFC differential current of differential protection, external or internal fault can be discriminated correctly. For external fault, waveform discrimination of phase current and differential current is adopted. Undesired operation will not occur if CT correct transfer time from primary to secondary side is not less than 5ms. As to internal fault, the device will operate quickly. 

High-sensitive transverse differential protection

By adopting frequency tracking, digital filter and Fourier transformation, the filtration ratio of third harmonic component can reach more than 100. These entire countermeasure guarantees the reliability of the protection in all occasions as mentioned as below:


1-4 Date: 2013-06-23

1 Introduction

The transverse differential protection can get reliable restraint effect because the faulty phase current increases greatly while transverse differential current increases less in external fault situation. The protection has very high operation sensitivity because transverse differential current increases comparatively large whereas phase current change not too observably in slightly inter-turn fault situation. The high-setting stage of transverse differential protection will operate quickly and reliably when severe inter-turn fault occurs in stator winding. In case of phase-to-phase fault of stator winding, not only transverse differential current but also phase current increase greatly, therefore just low percentage restraint by phase current guarantees the reliable operation of transverse differential protection against the fault. As for unbalanced transverse differential current increasing during normal operation condition, transverse differential protection uses float threshold to avoid undesired operation. 

Percentage restraint inter-turn protection

By adopting frequency tracking, digital filter and Fourier transformation, the filtration ratio of third harmonic component can reach more than 100. Calculated longitudinal residual overvoltage protection is adopted in PCS-985G, which is the new criteria of generator inter-turn protection and does not need the special VT for the protection. 

Stator earth-fault protection

By adopting frequency tracking, digital filter and Fourier transformation, the filtration ratio of third harmonic component can reach more than 100. The sensitive stage of fundamental residual voltage protection operates and issues trip command only if the dual criterias of residual voltages of generator terminal and neutral point are met at the same time. The ratio settings of third harmonic of generator terminal to that of neutral point used in third harmonic ratio criteria will automatically suit to the change of ratio fore-and-aft incorporating in power network third harmonic voltage of the plant unit. This automation adjustment function ensures the correctness of signals generated and issued by the third harmonic voltage criteria even during incorporation or isolation course of generator. The ratio and phase-angle difference of third harmonic voltage of generator terminal to that of neutral point keeps almost stable when the generator is in normal operation condition; also it is a slow developing course. Through real time adjustment of coefficient of amplitude value and phase, PCS-985 makes differential voltage between generator terminal and neutral point as zero in normal operation condition. When stator earth fault occurs, the criteria tend to operate reliably and sensitively. 

Stator earth-fault protection with external voltage injection principle

The protection adopts digital technology to calculate earth fault resistance accurately.


1-5 Date: 2013-06-23

1 Introduction

Settings configured two stage are provided. One stage operates to alarm, and the other stage operates to trip. The residual current protection is free from impact of 20Hz power, which provides mainly protection for comparatively severe stator earth fault. The protection is adaptive for various operation conditions, such as stillness, no-load, shutdown, startup and connected to power grid. 

Sampling-switch type rotor earth-fault protection

DC current is input by high-performance isolated amplifier. Via switching two different electronic switches, PCS-985 solves four different ground-loop equations to compute rotor winding voltage, rotor ground resistance and earthing position on real time and display these information on LCD. 

Rotor earth-fault with external voltage injection principle

Injecting a low-frequency square wave between positive terminal and negative terminal of rotor windings or between one terminal of rotor windings and axis, the device acquires leakage current of rotor, and calculates insulation resistance between rotor windings and ground in real-time. The injected square wave voltage is generated by the device. The protection reflects the insulation reduction between rotor windings and axis. The calculation to rotor earth resistance is unrelated to fault location, and no dead zone. The calculation accuracy of rotor earth resistance is high and is not affected by the capacitance between rotor windings and ground. The calculation to rotor earth resistance is unrelated to excitation voltage. It can still supervise insulation situation of rotor windings when no excitation voltage is supplied. It can be adaptive to various lead-out modes of rotor windings, and both single-end injection and double-ends injection can be selected. The fault location can be measured if selecting double-ends injection. 

Loss-of-excitation protection

Loss-of-excitation protection adopts optimizing protection scheme in which stator impedance criteria, reactive power criteria, rotor voltage criteria and busbar voltage criteria, could be optionally combined to meet various demands of different generator units. 

Out-of-step protection

Out-of-step protection adopts three-impedance element (gains from positive-sequence current and positive sequence voltage of generator) to distinguish out-of-step from steady oscillation. More than that, the protection can accurately locate the position of oscillation center and record oscillation slid numbers of external and internal oscillation respectively in real-time. 

VT circuit failure supervision

Two groups of VT inputs are equipped at generator terminal. If one group fails, the device will issue alarm and switch over to the healthy one automatically. It doesn’t need to block protection


1-6 Date: 2013-06-23

1 Introduction

element relevant to voltage. Based on percentage restraint characteristic, it can discriminate that neutral point of VT circuit fails. 

CT circuit failure supervision

Reliable blocking function when CT circuit failure can prevent the device from undesired operation due to CT circuit failure or AC sampled circuit failure. 

Powerful communication function

Flexible communication mode is provided. 2 independent Ethernet interfaces and 2 independent RS-485 communication interfaces are provided. Power industry communication standard IEC60870-5-103, Modbus protocol and new generation substation communication standard IEC61850 are supported. 

Complete event recording function

64 faults and operation sequence, 64 fault waveforms, results of 256 self-supervision reports, and 1024 binary signal change reports can be recorded. 

Auxiliary PC software

PC software allows easy application of this device.

1.4 Order Information 

CT secondary rated value: 1A or 5A



DC power supply for device: 110/125V, 220/250V



DC power supply for binary input: 110/125V, 220V


1-7 Date: 2013-06-23

1 Introduction


1-8 Date: 2013-06-23

2 Technical Data

2 Technical Data Table of Contents 2 Technical Data................................................................................. 2-a 2.1 Electrical Specifications ................................................................................. 2-1 2.1.1 AC Current Input .................................................................................................................. 2-1 2.1.2 AC Voltage Input .................................................................................................................. 2-1 2.1.3 Power Supply....................................................................................................................... 2-1 2.1.4 Binary Input .......................................................................................................................... 2-1 2.1.5 Binary Output ....................................................................................................................... 2-2

2.2 Mechanical Specifications ............................................................................. 2-2 2.3 Ambient Temperature and Humidity Range .................................................. 2-2 2.4 Communication Port ....................................................................................... 2-3 2.4.1 EIA-485 Port ........................................................................................................................ 2-3 2.4.2 Ethernet Port........................................................................................................................ 2-3 2.4.3 Optical Fibre Port ................................................................................................................. 2-3 2.4.4 Print Port .............................................................................................................................. 2-4 2.4.5 Clock Synchronization Port ................................................................................................. 2-4

2.5 Type Tests ........................................................................................................ 2-4 2.5.1 Environmental Tests ............................................................................................................ 2-4 2.5.2 Mechanical Tests ................................................................................................................. 2-4 2.5.3 Electrical Tests ..................................................................................................................... 2-5 2.5.4 Electromagnetic Compatibility ............................................................................................. 2-5

2.6 Certifications ................................................................................................... 2-6 2.7 Protective Functions....................................................................................... 2-6 2.7.1 Generator/ Excitor Differential Protection ............................................................................ 2-6 2.7.2 Excitation Transformer Differential Protection ..................................................................... 2-7 2.7.3 Generator Transverse Differential Protection ...................................................................... 2-7


2-a Date: 2013-06-24

2 Technical Data

2.7.4 Generator Longitudinal Residual Overvoltage Protection ................................................... 2-7 2.7.5 Generator Stator Earth-fault Protection ............................................................................... 2-7 2.7.6 Stator Earth-fault Protection with External Inject Principle .................................................. 2-8 2.7.7 Generator Rotor Earth-fault Protection ............................................................................... 2-8 2.7.8 Generator Stator Overload Protection ................................................................................. 2-8 2.7.9 Generator Negative-sequence Overload Protection ........................................................... 2-8 2.7.10 Excitation Windings Overload Protection .......................................................................... 2-9 2.7.11 Generator Loss-of-excitation Protection ............................................................................ 2-9 2.7.12 Generator Out-of-step Protection ...................................................................................... 2-9 2.7.13 Generator Voltage Abnormality Protection ........................................................................ 2-9 2.7.14 Generator Over-excitation Protection .............................................................................. 2-10 2.7.15 Generator Power Protection ............................................................................................ 2-10 2.7.16 Generator Frequency Protection ..................................................................................... 2-10 2.7.17 Generator Inadvertent Energization Protection ............................................................... 2-10 2.7.18 Generator Startup/shutdown Protection ...........................................................................2-11 2.7.19 Low-impedance Protection ...............................................................................................2-11 2.7.20 Voltage Controlled Overcurrent Protection.......................................................................2-11 2.7.21 Mechanical Protection ......................................................................................................2-11 2.7.22 Breaker Failure Protection at Generator Terminal............................................................2-11

2.8 Metering Scope and Accuracy ..................................................................... 2-12 2.9 Management Functions ................................................................................ 2-12 2.9.1 Clock Performance ............................................................................................................ 2-12 2.9.2 Fault and Disturbance Recording ...................................................................................... 2-12 2.9.3 Binary Input Signal............................................................................................................. 2-12

2-b


2 Technical Data

2.1 Electrical Specifications 2.1.1 AC Current Input Standard

IEC 60255-27:2005

Phase rotation

ABC

Nominal frequency (fn)

50±5Hz, 60±5Hz

Rated Current (In)

1A

Linear to

0.05In~40In

5A

Thermal withstand -continuously

4In

-for 10s

30In

-for 1s

100In

-for half a cycle

250In

Burden

< 0.15VA/phase @In

Accuracy

±0.5%In

< 0.25VA/phase @In

2.1.2 AC Voltage Input Standard

IEC 60255-6, IEC60288

Phase rotation

ABC

Nominal frequency (fn)

50±5Hz, 60±5Hz

Rated Voltage (Un)

50~120V

100~220V（broken-delta voltage）

Linear to

1~170V

2V~233V

-continuously

200V

220V

-10s

260V

380V

-1s

300V

420V

Burden at rated

< 0.20VA/phase @Un

< 0.80VA/phase @Un

Accuracy

±0.5%Un

Thermal withstand

2.1.3 Power Supply Standard

IEC 60255-11:2008

Rated Voltage

110Vdc/125Vdc, 220Vdc/250Vdc

Operating Range

80%~120% of rated voltage

Permissible AC ripple voltage

≤15% of the nominal auxiliary voltage

Burden Quiescent condition

<25W

Operating condition

<30W

2.1.4 Binary Input Rated Voltage

24V

48V

110V

125V

220V

250V

Rated current drain

1.2mA

2.4mA

1.1mA

1.25mA

2.2mA

2.5mA

Pickup voltage

55%~70% of rated voltage


2-1 Date: 2013-06-24

2 Technical Data Dropoff voltage

<55% of rated voltage

Maximum permissible voltage

120% of rated voltage

Withstand voltage -continuously Response time for logic input

2000Vac, 2800Vdc <1ms

2.1.5 Binary Output Contact Type

Trip output

Signal output

Output mode

Potential free contact 5A@380Vac

8A@380Vac

5A@250Vdc

8A@250Vdc

Pickup time

<8ms (typical 3ms)

<10ms

Dropoff time

<5ms

<8ms

0.65A@48Vdc

1.20A@48Vdc

0.30A@110Vdc

0.50A@110Vdc

0.15A@220Vdc

0.25A@220Vdc

Electrical life

10000 times

10000 times

Maximal system voltage

380Vac, 250Vdc

Test voltage across open contact

1000V RMS for 1min

1200V RMS for 1min

6A@3s

10A@3s

[email protected]

[email protected]

[email protected]

[email protected]

Continuous carry

Breaking capacity (L/R=40ms)

Short duration current

2.2 Mechanical Specifications Mounting Way

Flush mounted

Housing color

Silver grey

Weight per device

Approx. 40kg

Housing material

Aluminum

Location of terminal

Rear panel of the device

Device structure

Plug-in modular type @ rear side, integrated front plate

Protection class Standard

IEC 60225-1:2009

Front side

IP40

Other sides

IP50 (chassis without cooling holes), IP30 (chassis with cooling holes)

Rear side, connection terminals

IP30

2.3 Ambient Temperature and Humidity Range Standard

IEC 60225-1:2009

Operating temperature

-20°C to +55°C

Transport and storage temperature range Permissible humidity

-40°C to +70°C 5%-95%, without condensation

2-2


2 Technical Data Pollution degree

2

Altitude

<3000m

2.4 Communication Port 2.4.1 EIA-485 Port Baud rate

4.8kbit/s, 9.6kbit/s, 19.2kbit/s, 38.4kbit/s, 57.6kbit/s, 115.2kbit/s

Protocol

IEC 60870-5-103:1997

Maximal capacity

32

Transmission distance

<500m

Safety level

Isolation to ELV level

Twisted pair

Screened twisted pair cable

2.4.2 Ethernet Port Connector type

RJ-45

Transmission rate

100Mbits/s

Transmission standard

100Base-TX


<100m

Protocol

IEC 60870-5-103:1997 or IEC 61850

Safety level


2.4.3 Optical Fibre Port 2.4.3.1 For Station Level Characteristic

Glass optical fiber

Connector type

ST, SC

Fibre type

Multi mode


<2km

Wave length

1310nm

Transmission power

Min. -20.0dBm

Minimum receiving power

Min. -30.0dBm

Margin

Min +3.0dB

2.4.3.2 For Process Level Characteristic

Glass optical fiber

Connector type

LC

Fibre type

Multi mode


<2km

Wave length

1310nm

Transmission power

Min. -20.0dBm


Min. -30.0dBm

Margin

Min +3.0dB


2-3 Date: 2013-06-24

2 Technical Data

2.4.3.3 For Pilot Channel Characteristic

Glass optical fiber

Connector type

FC

Fibre type

Single mode


<40km (1310nm), <100km (1550nm)

Wave length

1310nm, 1550nm

Transmission power

Min. -18.0dBm


Min. -38.0dBm

Margin

Min +3.0dB

2.4.3.4 For Synchronization Port Characteristic

Glass optical fiber

Connector type

ST

Fibre type

Multi mode

Wave length

820nm


Min. -25.0dBm

Margin

Min +3.0dB

2.4.4 Print Port Type

RS-232

Baud Rate

4.8kbit/s, 9.6kbit/s, 19.2kbit/s, 38.4kbit/s, 57.6kbit/s, 115.2kbit/s

Printer type

EPSON 300K printer

Safety level


®

2.4.5 Clock Synchronization Port Type

RS-485


<500m

Maximal capacity

32

Timing standard

PPS, IRIG-B

Safety level


2.5 Type Tests 2.5.1 Environmental Tests Dry cold test

IEC60068-2-1:2007

Dry heat test

IEC60068-2-2:2007

Damp heat test, cyclic

IEC60068-2-30:2005

2.5.2 Mechanical Tests Vibration

IEC 60255-21-1:1988 Class I

Shock and bump

IEC 60255-21-2:1988 Class I

2-4


2 Technical Data

2.5.3 Electrical Tests Standard

IEC 60255-27:2005

Dielectric tests

Test voltage 2kV, 50Hz, 1min

Standard

IEC 60255-5:2000

Impulse voltage tests Overvoltage category

Test voltage 5kV Ⅲ

Insulation

resistance

measurements

Isolation resistance >100MΩ@500VDC

2.5.4 Electromagnetic Compatibility IEC 60255-22-1:2007 1MHz burst disturbance test

Common mode: class III 2.5kV Differential mode: class III 1.0kV IEC60255-22-2:2008 class IV

Electrostatic discharge test

For contact discharge: 8kV For air discharge: 15kV IEC 60255-22-3:2007 class III Frequency sweep Radiated amplitude-modulated 10V/m (rms), f=80~1000MHz

Radio frequency interference tests

Spot frequency Radiated amplitude-modulated 10V/m (rms), f=80MHz/160MHz/450MHz/900MHz Radiated pulse-modulated 10V/m (rms), f=900MHz IEC 60255-22-4:2008

Fast transient disturbance tests

Power supply, I/O, Earth: class IV, 4kV, 2.5kHz, 5/50ns Communication terminals: class IV, 2kV, 5kHz, 5/50ns IEC 60255-22-5:2008

Surge immunity test

Power supply, AC input, I/O port: class IV, 1.2/50us Common mode: 4kV Differential mode: 2kV

Conducted

RF

Electromagnetic

Disturbance

IEC 60255-22-6:2001 Power supply, AC, I/O, Comm. Terminal: Class III, 10Vrms, 150 kHz~80MHz

Power Frequency Magnetic Field

IEC 61000-4-8:2001

Immunity

class V, 100A/m for 1min, 1000A/m for 3s

Pulse Magnetic Field Immunity

IEC 61000-4-9:2001 class V, 6.4/16μs, 1000A/m for 3s

Damped oscillatory magnetic field

IEC 61000-4-10:2001

immunity

class V, 100kHz & 1MHz–100A/m


2-5 Date: 2013-06-24

2 Technical Data

Auxiliary power supply performance

IEC60255-11: 2008

- Voltage dips

Up to 500ms for dips to 40% of rated voltage without reset

-Voltage short interruptions

100ms for interruption without rebooting

2.6 Certifications 

ISO9001:2008



ISO14001:2004



OHSAS18001:2007



ISO10012:2003



CMMI L4



EMC: 2004/108/EC, EN50263:1999



Products safety(PS): 2006/95/EC, EN61010-1:2001

2.7 Protective Functions Note!

Ie is secondary rated current of generator In is secondary rated current of CT Un is secondary rated voltage of VT Pn is rated active power of generator

2.7.1 Generator/ Exciter Differential Protection Pickup setting range of percentage differential element

≤5% or 0.01In whichever is greater

Setting accuracy Setting

range

of

unrestrained

instantaneous

differential element

Setting range of first slope of percentage differential element Setting range of maximum slope of percentage differential element

of

differential protection

unrestrained

0~0.50

0.30~0.80 ≤25ms (2 times pickup current settings)

Operation time of percentage differential protection time

2Ie~14Ie ≤2.5%

Setting accuracy

Operation

0.1Ie~1.5Ie

instantaneous

≤20ms (1.5 times pickup current settings)

2-6


2 Technical Data

2.7.2 Excitation Transformer Differential Protection Pickup setting range of percentage differential element


Setting accuracy Setting

range

0.1Ie~1.5Ie

of

unrestrained

instantaneous

differential element

2Ie~14Ie ≤2.5%

Setting accuracy Setting range of first slope of percentage differential element Setting range of maximum slope of percentage differential element

0~0.50

0.50~0.80

Secondary harmonic restraint coefficient

0.10~0.35

Operation time of percentage differential protection

≤35ms(2 times pickup current settings)

Operation

time

of

unrestrained

instantaneous

differential protection

≤25ms(1.5 times pickup current settings)

2.7.3 Generator Transverse Differential Protection Setting range of transverse differential element

0.1ln~10ln

High setting range of transverse differential element

0.1ln~10ln

Setting accuracy

≤2.5% or 0.01In whichever is greater

Time

delay

of

transverse

differential

element

(one-point earth)

0.1~10s ≤35ms (1.5 times pickup current settings)

Operating time

2.7.4 Generator Longitudinal Residual Overvoltage Protection Setting range of longitudinal residual voltage element

1~10V

Setting accuracy

≤2.5% or 0.05V whichever is greater

Setting accuracy of calculated longitudinal residual voltage element


Time delay of longitudinal residual voltage element

0.1~10s

Setting accuracy

≤1%Setting + 40ms

2.7.5 Generator Stator Earth-fault Protection Setting range of residual voltage blocking element

1~100V

Setting range of residual voltage element

0.1~50V

High setting range of residual voltage element

0.1~50V

Setting accuracy


Setting range of third harmonic voltage ratio element

0.5~10

Setting range of third harmonic voltage differential element

0.05~2.0

Setting accuracy

≤5%

Time delay

0.1~10s


2-7 Date: 2013-06-24

2 Technical Data ≤1%Setting + 40ms

Setting accuracy

2.7.6 Stator Earth-fault Protection with External Inject Principle Resistance setting range

0.1~30kΩ

Setting accuracy

≤5%

Residual current setting range

0.02~1.50A

Setting accuracy

≤5% or 0.001A whichever is greater

Time delay

0.1~10s

Setting accuracy

≤1%Setting + 40ms

2.7.7 Generator Rotor Earth-fault Protection Resistance setting range of one-point earth

0.1~100kΩ

Setting accuracy

≤10% or 0.5kΩ whichever is greater

negative-sequence voltage setting range of 2nd harmonic

0.1~10V

Setting range of switchover cycle

0.5~10s

Time delay

0.1~10s

Setting accuracy

≤1%Setting + 1s

2.7.8 Generator Stator Overload Protection Definite-time current setting range

0.1In~10In

Setting accuracy


Inverse-time pickup current setting range

0.1In~20In

Setting accuracy


Time delay

0.1 ~10s

Setting accuracy

≤1%Seting + 40ms

Setting range of thermal capacity of stator windings

1~100

Setting range of heat emission factor

1.02~2.0

2.7.9 Generator Negative-sequence Overload Protection Definite-time negative-sequence current setting range

0.1In~4In

Setting accuracy


Time delay

0.1~10s

Setting accuracy

≤1%Setting + 40ms

Inverse-time

negative-sequence

pickup

current

setting range

0.05In~1In

Setting accuracy


Setting range of rotor heat constant

1~100

Setting

range

of

negative-sequence current

continuous

tolerable

0.05ln~1ln

2-8


2 Technical Data

2.7.10 Excitation Windings Overload Protection Definite-time current setting range

0.1ln~20ln

Inverse-time pickup current setting range

0.05ln~10ln

Setting accuracy


Time delay

0.1~25s

Setting accuracy

≤1%Setting + 40ms

Setting range of thermal capacity factor

1~100

Setting range of reference current

0.1ln~10ln

2.7.11 Generator Loss-of-excitation Protection Impedance setting range (Z1)

0.1 ~ 200Ω

Impedance setting range (Z2)

0.1 ~ 200Ω

Setting accuracy

≤2.5% or 0.1Ω whichever is greater

Reverse reactive power setting range

0 ~ 50.00%Pn

Setting accuracy

≤1% or 0.002Pn whichever is greater

Low-voltage setting range of rotor

1 ~ 500V

No-load voltage setting range of rotor

1 ~ 500V

Low-voltage setting range of bus or generator terminal

0.1 ~ 100V

Setting accuracy


Setting range of rotor low-voltage factor

0 ~ 10

Time delay of stage 1 and stage 2

0.1 ~ 10s

Time delay of stage 3

0.1 ~ 3000s

Setting accuracy

≤1%Setting + 40ms

2.7.12 Generator Out-of-step Protection Impedance setting A range

0 ~ 100Ω

Impedance setting B range

0 ~ 100Ω

Impedance setting C range

0 ~ 100Ω

Setting accuracy

≤2.5% or 0.1Ωwhichever is greater

Setting range of sensitive angle

0 ~ 90°

Setting range of len′s inner angle lens

0 ~ 150°

Setting accuracy

≤3°

Setting range of pole slipping number

1 ~ 1000

Setting range of permitted tripping current

0.1ln ~ 20ln

Setting accuracy


2.7.13 Generator Voltage Abnormality Protection Vero-voltage setting range

0.1 ~ 200V

Under-voltage setting range

0.1 ~ 100V

Setting accuracy


Time delay

0 ~ 10s

Setting accuracy

≤1%Setting + 40ms


2-9 Date: 2013-06-24

2 Technical Data

2.7.14 Generator Over-excitation Protection Definite time V/F setting range

1.0 ~ 2.0 pu

Setting accuracy

≤2.5% or 0.01 whichever is greater

Definite time delay for tripping

0.1 ~ 3000.0s

Definite time delay for alarm

0.1 ~ 25s

Setting accuracy

≤1%Setting + 40ms

Inverse time V/F setting range

1.0 ~ 2.0 pu

Inverse time delay for tripping

0.1 ~ 3000.0s

2.7.15 Generator Power Protection Setting range of reverse power element

0.5 ~ 50%Pn

Setting range of reverse power sequential tripping element

0.5 ~ 10%Pn

Setting range of under-power element

0.5 ~ 10%Pn

Setting accuracy

≤10% or 0.002Pn whichever is greater

Time delay of reverse power element

0.1 ~ 3000s

Time delay of reverse power sequential tripping element

0.01~10s

Time delay of under-power element

0.01~10s

Setting accuracy

≤1%Setting + 40ms

2.7.16 Generator Frequency Protection Setting range of underfrequency protection (stage 1~3)

0.90~1.02fn

Setting range of overfrequency protection (stage 1-2)

1.00~1.20fn

Setting accuracy

≤0.02Hz

Time delay of underfrequency protection (stage 1~2)

0.1 ~ 300min

Time delay of underfrequency protection (stage 3)

0.1 ~ 100s

Time delay of overfrequency protection (stage 1)

0.1 ~ 100min

Time delay of overfrequency protection (stage 2)

0.1 ~ 100s

Setting accuracy

≤1%Setting + 40ms

2.7.17 Generator Inadvertent Energization Protection Current setting range of inadvertent energization protection


Setting accuracy Undervoltage

0.1ln ~ 10ln

setting

range

of

inadvertent

energization protection

6~80V

Setting accuracy


Blocking frequency setting range

0.80~1.00fn

Time delay of inadvertent energization protection

0.01 ~ 1.0s

Setting accuracy

≤1%Setting + 40ms

2-10


2 Technical Data

2.7.18 Generator Startup/shutdown Protection Blocking frequency setting range

0.80~1.00fn

Differential current setting range

0.2le~10Ie

Setting accuracy


Overcurrent

setting

range

under

low-frequency

condition

0.1ln ~ 20ln

Setting accuracy


Residual voltage setting range

5 ~ 25V

Setting accuracy

≤5% or 0.02Un whichever is greater

Time delay

0 ~ 10s

Setting accuracy

≤1%Setting + 40ms

setting range

2.7.19 Low-impedance Protection Forward impedance setting range

0.1 ~ 100Ω

Reverse impedance setting range

0.1 ~ 100Ω

Setting accuracy

≤2.5% or 0.1Ω whichever is greater

Time delay

0.1 ~ 10s

Setting accuracy

≤1%Setting + 40ms

2.7.20 Voltage Controlled Overcurrent Protection Negative-sequence voltage setting range

1 ~ 20V

Low voltage setting range

10 ~ 100V

Setting accuracy


Current setting range

0.1ln ~ 20ln

Setting accuracy


Time delay

0 ~ 10s

Setting accuracy

≤1%Setting + 40ms

2.7.21 Mechanical Protection Time delay

0.1 ~ 10s

Setting accuracy

≤1%Setting + 40ms

2.7.22 Breaker Failure Protection at Generator Terminal Phase current setting range

0.1ln ~ 4ln

Negative-sequence current setting range

0.1ln ~ 4ln

Setting accuracy


Time delay

0.1~ 10s

Setting accuracy

≤1% + 40ms


2-11 Date: 2013-06-24

2 Technical Data

2.8 Metering Scope and Accuracy Metering Item

Range

Accuracy

Phase range

0°~ 360°

≤ 0.5% or ±1°

Frequency

35.00Hz ~ 70.00Hz

±0.02Hz

Currents from dedicated metering current transformers Current

0.05 ~ 1.40×In

≤ 0.2% of rating

Active power (W)

0.05 ~ 1.20×Un, 0.05 ~ 1.40×In

≤ 1.0% of rating at unity power factor

Currents from protection measurement current transformers Current

0.05 ~ 1.40×In

≤ 2.0% of rating

Voltage

0.05 ~ 1.20×Un

≤ 1.0% of rating

Active power (W)

0.05 ~ 1.20×Un, 0.05 ~ 1.40×In

≤ 3.0% of rating at unity power factor

2.9 Management Functions 2.9.1 Clock Performance Real time clock accuracy

≤ 3s/day

Accuracy of GPS synchronization

≤ 1ms

External time synchronization

IRIG-B (200-98), PPS, IEEE1588 or SNTP protocol

2.9.2 Fault and Disturbance Recording Magnitude and relative phases

≤ 2.5% of applied quantities

Maximum duration

2048 sampled points (24 sampled points per cycle)

Recording position

3 cycles before pickup of trigger element

2.9.3 Binary Input Signal Resolution of binary input signal

≤ 1ms

Binary input mode

Potential-free contact

Resolution of SOE

≤ 2ms

2-12


3 Operation Theory

3 Operation Theory Table of Contents 3 Operation Theory ............................................................................ 3-a 3.1 Overview .......................................................................................................... 3-1 3.2 Fault Detector (FD) .......................................................................................... 3-1 3.2.1 Differential Protection of Generator ..................................................................................... 3-2 3.2.2 Inter-turn Protection of Generator ....................................................................................... 3-2 3.2.3 Stator Earth-fault Protection of Generator ........................................................................... 3-2 3.2.4 Stator Earth-fault Protection with Voltage Injection of Generator........................................ 3-2 3.2.5 Rotor Earth-fault Protection of Generator ........................................................................... 3-2 3.2.6 Stator Overload Protection of Generator ............................................................................. 3-3 3.2.7 Negative-sequence Overload Protection of Generator ....................................................... 3-3 3.2.8 Loss-of-excitation Protection of Generator .......................................................................... 3-3 3.2.9 Out-of-step Protection of Generator .................................................................................... 3-3 3.2.10 Voltage Protection of Generator ........................................................................................ 3-3 3.2.11 Over-excitation Protection of Generator ............................................................................ 3-3 3.2.12 Power Protection of Generator .......................................................................................... 3-4 3.2.13 Frequency Protection of Generator ................................................................................... 3-4 3.2.14 Inadvertent Energization Protection of Generator ............................................................. 3-4 3.2.15 Startup/shutdown Protection of Generator ........................................................................ 3-4 3.2.16 Differential Protection of Excitation Transformer/Exciter ................................................... 3-4 3.2.17 Overcurrent Protection/Overload Protection of Excitation Transformer/Exciter................ 3-5 3.2.18 Breaker Failure Protection at Generator Terminal............................................................. 3-5 3.2.19 Mechanical Protection ....................................................................................................... 3-5

3.3 Differential Protection of Excitation Transformer/Exciter............................ 3-5 3.3.1 Operation Characteristic ...................................................................................................... 3-5 3.3.2 Inrush Current Detection Element ....................................................................................... 3-7


3-a Date: 2013-06-28

3 Operation Theory

3.3.3 CT Saturation Detection Element ........................................................................................ 3-8 3.3.4 High-setting Percentage Differential Protection Element (HSDP) ...................................... 3-8 3.3.5 Unrestrained Instantaneous Differential Protection Element (UIDP) .................................. 3-9 3.3.6 Differential Current Abnormality Alarm and CT Circuit Failure Blocking ............................. 3-9 3.3.7 Overexcitation Detection Element ..................................................................................... 3-10 3.3.8 Logic Scheme .....................................................................................................................3-11

3.4 Differential Protection of Generator ............................................................ 3-12 3.4.1 Percentage Differential Protection (SPDP) ....................................................................... 3-12 3.4.2 High Performance Blocking Technique in Case of CT Saturation .................................... 3-13 3.4.3 High-setting Percentage Differential Protection (HSDP) ................................................... 3-14 3.4.4 Unrestrained Instantaneous Differential Protection (UIDP) .............................................. 3-14 3.4.5 Differential Current Abnormality Alarm and CT Circuit Failure Blocking ........................... 3-14 3.4.6 Logic Scheme .................................................................................................................... 3-15

3.5 DPFC Differential Protection ........................................................................ 3-15 3.5.1 Operation Characteristic .................................................................................................... 3-16 3.5.2 Differential Current Abnormality Alarm and CT Circuit Failure Blocking ........................... 3-17 3.5.3 Logic Scheme .................................................................................................................... 3-17

3.6 Generator Inter-turn Protection ................................................................... 3-18 3.6.1 High-sensitive Transverse Differential Protection ............................................................. 3-18 3.6.2 Longitudinal Residual Voltage Protection .......................................................................... 3-20 3.6.3 VT2 Circuit Failure Alarm and Blocking ............................................................................. 3-20 3.6.4 DPFC Inter-turn Protection ................................................................................................ 3-21 3.6.5 Calculated Longitudinal Residual Voltage Protection ....................................................... 3-21 3.6.6 VT1 Circuit Failure Alarm and Blocking ............................................................................. 3-23

3.7 Phase-to-phase Backup Protection of Generator ...................................... 3-23 3.7.1 Voltage Controlled Overcurrent Protection ........................................................................ 3-23 3.7.2 Impedance Protection........................................................................................................ 3-25

3.8 Stator Earth-fault Protection ........................................................................ 3-27 3.8.1 Fundamental Residual Overvoltage Protection ................................................................. 3-27 3.8.2 Third Harmonic Voltage Ratio Protection .......................................................................... 3-28 3-b


3 Operation Theory

3.8.3 Third Harmonic Voltage Differential Protection ................................................................. 3-29 3.8.4 VT Circuit Failure Blocking ................................................................................................ 3-29 3.8.5 Logic Scheme .................................................................................................................... 3-30

3.9 Stator Earth-fault Protection with Voltage Injection ................................... 3-32 3.9.1 Earthing Resistance Criterion ............................................................................................ 3-32 3.9.2 Earthing Current Criterion.................................................................................................. 3-33 3.9.3 External Voltage Circuit Monitoring ................................................................................... 3-33 3.9.4 Logic Scheme .................................................................................................................... 3-34

3.10 Rotor Earth-fault Protection with Ping-pang Type ................................... 3-34 3.10.1 One-point Earth-fault Protection ...................................................................................... 3-34 3.10.2 Two-points Earth fault Protection .................................................................................... 3-35

3.11 Rotor Earth-fault Protection with Voltage Injection .................................. 3-36 3.11.1 One-point Earth-fault Protection ...................................................................................... 3-36 3.11.2 Two-point Earth-fault Protection ...................................................................................... 3-37

3.12 Stator Overload Protection......................................................................... 3-38 3.12.1 Definite-time Stator Overload Protection ......................................................................... 3-38 3.12.2 Inverse-time Stator Overload Protection ......................................................................... 3-39

3.13 Negative-sequence Overload Protection .................................................. 3-40 3.13.1 Definite-time Negative-sequence Overload Protection ................................................... 3-40 3.13.2 Inverse-time Negative-sequence Overload Protection ................................................... 3-41

3.14 Loss-of-excitation Protection..................................................................... 3-42 3.14.1 Undervoltage Criterion ..................................................................................................... 3-42 3.14.2 Stator-side Impedance Criterion ...................................................................................... 3-43 3.14.3 Rotor-side Criterion ......................................................................................................... 3-44 3.14.4 Logic Scheme .................................................................................................................. 3-45

3.15 Out-of-step Protection ................................................................................ 3-46 3.16 Generator Voltage Protection ..................................................................... 3-48 3.16.1 Overvoltage Protection .................................................................................................... 3-48 3.16.2 Undervoltage Protection .................................................................................................. 3-49

3.17 Over-excitation Protection ......................................................................... 3-50 PCS-985G Generator Relay

3-c Date: 2013-06-28

3 Operation Theory

3.17.1 Definite-time Over-excitation Protection .......................................................................... 3-50 3.17.2 Inverse-time Over-excitation Protection .......................................................................... 3-50

3.18 Power Protection......................................................................................... 3-51 3.18.1 Reverse Power Protection ............................................................................................... 3-51 3.18.2 Sequence Tripping Reverse Power Protection ............................................................... 3-52 3.18.3 Low Power Protection...................................................................................................... 3-53

3.19 Frequency Protection ................................................................................. 3-53 3.19.1 Underfrequency Protection .............................................................................................. 3-53 3.19.2 Overfrequency Protection ................................................................................................ 3-53 3.19.3 Logic Scheme .................................................................................................................. 3-54

3.20 Inadvertent Energization Protection.......................................................... 3-54 3.21 Startup and Shutdown Protection ............................................................. 3-56 3.22 Overload Protection of Excitation Windings ............................................ 3-57 3.22.1 Definite-time Excitation Winding Overload Protection .................................................... 3-57 3.22.2 Inverse-time Excitation Winding Overload Protection ..................................................... 3-58

3.23 Excitation Transformer /Exciter Overcurrent Protection ......................... 3-59 3.24 Breaker Failure Protection at Generator Terminal ................................... 3-59 3.25 CT Circuit Supervision ............................................................................... 3-60 3.25.1 Three-phase Current Circuit Failure Alarm ..................................................................... 3-60 3.25.2 Differential Current Alarm in Differential Protection Circuit ............................................. 3-60 3.25.3 Alarm or Blocking to Differential Protection by CT Circuit Failure ................................... 3-61

3.26 VT Circuit Supervision ................................................................................ 3-61 3.26.1 VT Circuit of Any Side Failure Alarm ............................................................................... 3-61 3.26.2 Voltage Valance on Generator Terminals ........................................................................ 3-62 3.26.3 Three-phase Voltage Circuit Failure Supervision ............................................................ 3-62

3.27 Mechanical protection ................................................................................ 3-62

List of Figures Figure 3.1-1 Hardware structure ................................................................................................ 3-1 Figure 3.3-1 Operation characteristic of differential protection............................................. 3-6

3-d


3 Operation Theory

Figure 3.3-2 Operation characteristic of HSDP ........................................................................ 3-9 Figure 3.3-3 Logic diagram of differential protection............................................................ 3-11 Figure 3.4-1 Operation characteristic of percentage differential protection ...................... 3-12 Figure 3.4-2 Logic diagram of differential protection............................................................ 3-15 Figure 3.5-1 Operating characteristic of DPFC percentage differential protection ........... 3-17 Figure 3.5-2 Logic diagram of DPFC percentage differential protection ............................ 3-17 Figure 3.6-1 Logic diagram of high-setting stage transverse differential protection ........ 3-19 Figure 3.6-2 Logic diagram of sensitive stage transverse differential protection ............. 3-19 Figure 3.6-3 Logic diagram of longitudinal residual voltage protection ............................. 3-20 Figure 3.6-4 Logic diagram of calculated longitudinal residual voltage protection .......... 3-22 Figure 3.7-1 Logic diagram of overcurrent protection .......................................................... 3-25 Figure 3.7-2 Operation characteristic of impedance protection .......................................... 3-26 Figure 3.7-3 Logic diagram of impedance protection ........................................................... 3-27 Figure 3.8-1 Logic diagram of stator earth-fault protection ................................................. 3-31 Figure 3.9-1 Circuit design of stator earth-fault protection with voltage injection ............ 3-32 Figure 3.9-2 Logic diagram of stator earth-fault protection with voltage injection ........... 3-34 Figure 3.10-1 Schematic diagram of measurement principle............................................... 3-35 Figure 3.10-2 Logic diagram of one-point earth fault protection ......................................... 3-35 Figure 3.10-3 Logic diagram of two-points earth fault protection ....................................... 3-36 Figure 3.11-1 Measuring scheme of voltage injection into the rotor winding at single-end .............................................................................................................................................. 3-36 Figure 3.11-2 Measuring scheme of voltage injection into the rotor winding at double-ends .............................................................................................................................................. 3-37 Figure 3.11-3 Logic diagram of one-point earth-fault protection ......................................... 3-37 Figure 3.11-4 Logic diagram of two-points earth-fault protection ....................................... 3-38 Figure 3.12-1 Logic diagram of definite-time stator overload protection ........................... 3-39 Figure 3.12-2 Operation curve of inverse-time stator overload protection ........................ 3-39 Figure 3.12-3 Logic diagram of inverse-time stator overload protection ........................... 3-40 Figure 3.13-1 Logic diagram of definite-time negative-sequence overload protection .... 3-41 Figure 3.13-2 Operation curve of inverse-time negative-sequence overload protection.. 3-41


3-e Date: 2013-06-28

3 Operation Theory

Figure 3.13-3 Logic diagram of inverse-time negative-sequence overload protection..... 3-42 Figure 3.14-1 Operation characteristic of steady-state stabilization impedance circle .... 3-43 Figure 3.14-2 Operation characteristic of asynchronous impedance circle ...................... 3-44 Figure 3.14-3 Logic diagram of loss-of-excitation protection (stage 1) .............................. 3-45 Figure 3.14-4 Logic diagram of loss-of-excitation protection (stage 2) .............................. 3-46 Figure 3.14-5 Logic diagram of loss-of-excitation protection (stage 3) .............................. 3-46 Figure 3.15-1 Operation characteristic of out-of-step protection ........................................ 3-47 Figure 3.15-2 Logic diagram of out-of-step protection ......................................................... 3-48 Figure 3.16-1 Logic diagram of overvoltage protection ........................................................ 3-49 Figure 3.16-2 Logic diagram of undervoltage protection ..................................................... 3-49 Figure 3.17-1 Logic diagram of definite-time over-excitation protection............................ 3-50 Figure 3.17-2 Inverse-time characteristics ............................................................................. 3-51 Figure 3.17-3 Logic diagram of inverse-time over-excitation protection ............................ 3-51 Figure 3.18-1 Logic diagram of reverse power protection ................................................... 3-52 Figure 3.18-2 Logic diagram of sequence tripping reverse power protection ................... 3-52 Figure 3.18-3 Logic diagram of low power protection .......................................................... 3-53 Figure 3.19-1 Logic diagram of underfrequency protection................................................. 3-54 Figure 3.19-2 Logic diagram of overfrequency protection ................................................... 3-54 Figure 3.20-1 Logic diagram of inadvertent energization protection (standard version) . 3-55 Figure 3.20-2 Logic diagram of inadvertent energization protection (special version) .... 3-56 Figure 3.21-1 Logic diagram of generator startup and shutdown protection .................... 3-57 Figure 3.22-1 Logic diagram of definite time excitation winding overload protection ...... 3-57 Figure 3.22-2 Operation characteristic of inverse-time excitation winding overload protection ............................................................................................................................ 3-58 Figure 3.22-3 Logic diagram of inverse-time excitation winding overload protection ...... 3-59 Figure 3.23-1 Logic diagram of excitation transformer or exciter overcurrent protection 3-59 Figure 3.24-1 Logic diagram of breaker failure protection ................................................... 3-60

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3 Operation Theory

3.1 Overview The device has 2 plug-in modules (i.e. protection DSP module and fault detector DSP module), and the logic relation between them is “AND”. They have independent sample circuit and output circuit. AC current and voltage is converted into small voltage signal and sent to protection calculation module (also called DSP module 1) and fault detector calculation module (also called DSP module 2) respectively. Protection DSP module is responsible for protection calculation and fault detector DSP module is responsible for fault detector. Fault detectors on fault detector DSP module picks up to connect positive pole of power supply of output relays. Real-time data exchange between protection DSP module and fault detector DSP module is performed. Based on strict mutual check and self-check, any of them fails will lead to block the device and issue alarm signal. The device will not mal-operate due to hardware error. Serial port

Ethernet

CPU Print

AC Signal

LPF

Clock Synchronization

A/D

DSP

Optocoupler

External BI

Output Relay

Protection DSP module

QDJ

LPF

A/D

DSP

+E

Fault detector DSP module

Figure 3.1-1 Hardware structure

3.2 Fault Detector (FD) Each fault detector element will be enabled when the corresponding protection element is enabled. After the fault detector element operates, the positive power supply will be provided to output relay and pickup signal will keep 500ms even the fault detector element drops off. Tripping output is only enabled if both corresponding fault detector element on fault detector DSP module and corresponding protection element on protection DSP module operate, otherwise the device will issue alarm signal. The fault detector element with the prefix of “FD_” will delay drop-off with a time delay of 500ms, and the fault detector element with the prefix of “St_” will drop–off with no time delay. The principle of each fault detector element is given below:


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3 Operation Theory

3.2.1 Differential Protection of Generator When the differential current of generator is greater than the setting [I_Pkp_PcntDiff_Gen], the fault detector element of generator differential protection [FD_Diff_Gen] and [St1_DiffProt_Gen] will operate. When the fundamental variation of differential current is greater than the threshold value, the fault detector element of generator differential protection [FD_Diff_Gen] and [St2_DiffProt_Gen] will operate.

3.2.2 Inter-turn Protection of Generator When the transverse differential current of generator is greater than the setting [I_SensTrvDiff_Gen], the fault detector element of generator transverse differential protection [FD_IntTurn_Gen] and [St_TrvDiffProt_Gen] will operate. When the longitudinal residual voltage is greater than the setting [V_SensROV_Longl_Gen], the fault detector element of longitudinal residual voltage protection [FD_IntTurn_Gen] and [St_ROV_Longl_Gen] will operate. When the fundamental variation of negative-sequence voltage, current and power are greater than their threshold values, the fault detector element of DPFC inter-turn protection [FD_IntTurn_Gen] and [St_DPFC_IntTurn_Gen] will operate. When the calculated longitudinal residual voltage is greater than the setting [V_SensROV_Longl_Gen], the fault detector element of longitudinal residual voltage protection [FD_IntTurn_Gen] and [St_ROV_Longl2_Gen] will operate.

3.2.3 Stator Earth-fault Protection of Generator When residual voltage of generator terminal and neutral point are greater than the setting [V_SensROV_Sta], the fault detector element of residual voltage protection [FD_StaEF_Gen] and [St_ROVProt_Sta] will operate. When third harmonic voltage ratio is greater than the setting [k_V3rdHRatio_PreSync_Sta] or [k_V3rdHRatio_PostSync_Sta], the fault detector element of third harmonic voltage ratio protection [FD_StaEF_Gen] and [St_V3rdHRatio_Sta] will operate.

3.2.4 Stator Earth-fault Protection with Voltage Injection of Generator When the calculated earth resistance is lower than the resistance setting [R_Trp_Inj_EF_Sta], the fault detector element [FD_InjStaEF_Gen] and [St_InjR_Sta] will operate. When earthing current of stator without being subjected to digital filter is greater than the current setting [I_ROC_Inj_EF_Sta], the fault detector element [FD_InjStaEF_Gen] and [St_InjI0_Sta] will operate.

3.2.5 Rotor Earth-fault Protection of Generator When grounded resistance of rotor windings is smaller than its setting [R_1PEF_RotWdg], the fault detector element of rotor one-point earth-fault protection [FD_EF_RotWdg] and 3-2


3 Operation Theory

[St_1PEF_RotWdg] will operate. When the change of rotor grounding location is greater than its internally fixed setting, the fault detector element of rotor two-points earth-fault protection will [FD_EF_RotWdg] and [St_2PEF_RotWdg] operate.

3.2.6 Stator Overload Protection of Generator When maximum value of three phase currents is greater than the setting [I_OvLd_Sta], the fault detector element of definite-time overload protection [FD_StaOvLd_Gen] and [St_OvLd_Sta] will operate. When the inverse time accumulated value is greater than the setting [I_InvOvLd_Sta], the fault detector element of inverse-time overload protection [FD_StaOvLd_Gen] and [St_InvOvLd_Sta] will operate.

3.2.7 Negative-sequence Overload Protection of Generator When maximum value of negative sequence current is greater than the setting [I_NegOC_Gen], the fault detector element of definite-time negative-sequence overload protection [FD_NegOC_Gen] and [St_NegOC_Sta] will operate. When the inverse time accumulated value is greater than the setting [I_InvNegOC_Gen], the fault detector element of inverse-time negative-sequence overload protection [FD_NegOC_Gen] and [St_InvNegOC_Sta] will operate.

3.2.8 Loss-of-excitation Protection of Generator When the locus of calculated impedance enters into impedance circle, the fault detector of loss-of-excitation protection [FD_LossExc_Gen] and [St_LossExcn_Gen] (n can be 1, 2 or 3) will operate.

3.2.9 Out-of-step Protection of Generator When the locus of calculated impedance leaves boundary of impedance operation zone, the fault detector of out-of-step protection [FD_OOS_Gen] and [St_x_OOS_Gen] (x can be Ext or Int) will operate.

3.2.10 Voltage Protection of Generator When maximum value of three phase-to-phase voltage is greater than the setting [V_OVn_Gen], the fault detector element of overvoltage protection [FD_VoltProt_Gen] and [St_OVn_Gen] will operate (n can be 1 or 2). When maximum value of three phase-to-phase voltage is greater than the setting [V_UV_Gen], the fault detector element of overvoltage protection [FD_VoltProt_Gen] and [St_UV_Gen] will operate.

3.2.11 Over-excitation Protection of Generator When the measured U/F is greater than the setting [k_OvExc1_Gen], the fault detector element of


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3 Operation Theory

definite-time over-excitation protection [FD_OvExc_Gen] and [St_OvExc1_Gen] will operate. When the accumulated value is greater than the setting [k0_InvOvExc_Gen], the fault detector element of inverse-time over-excitation protection [FD_OvExc_Gen] and [St_OvExc2_Gen] will operate.

3.2.12 Power Protection of Generator When reverse power is greater than setting [P_RevP_Gen], the fault detector of reverse power protection [FD_PwrProt_Gen] and [St_RevP_Gen] will operate. When reverse power is greater than setting [P_SeqTrpRevP_Gen], the fault detector of reverse power protection [FD_PwrProt_Gen] and [St_SeqTrpRevP_Gen] will operate. When power is lower than setting [P_UP_Gen] and the binary input [BI_NotUrgBrake] is energized, the fault detector of low power protection [FD_PwrProt_Gen] and [St_UP_Gen] will operate.

3.2.13 Frequency Protection of Generator When the frequency is smaller than the setting value for a specified time interval, the fault detector element of low-frequency protection [FD_Freq_Gen] and [St_UFn_Gen] (n can be 1, 2 or 3) will operate. When the frequency is greater than the setting value for a specified time interval, the fault detector element of over-frequency protection [FD_Freq_Gen] and [St_OFx_Gen] (x can be 1 or 2) will operate.

3.2.14 Inadvertent Energization Protection of Generator When the maximum value of three phase currents of generator is greater than the setting [I_OC_AccEnerg_Gen], the fault detector element of generator inadvertent energization protection [FD_AccEnerg_Gen] and [St_AccEnerg_Gen] will operate.

3.2.15 Startup/shutdown Protection of Generator When the differential current of generator is greater than the setting [I_GenDiff_StShut_Gen], the fault detector element of generator startup/shutdown protection [FD_StShut_Gen] and [St_GenDiff_StShut_Gen] will operate. When the residual voltage of generator is greater than the setting [V_StaROV_StShut_Gen], the fault detector element of generator startup/shutdown protection [FD_StShut_Gen] and [St_StaROV_StShut_Gen] will operate. When the low-frequency current of generator neutral point is greater than the setting [I_OC_StShut_Gen], the fault detector element of generator startup/shutdown protection [FD_StShut_Gen] and [St_OC_StShut_Gen] will operate.

3.2.16 Differential Protection of Excitation Transformer/Exciter When the maximum value of three phase differential currents is greater than the setting [I_Pkp_PcntDiff_Exc], the fault detector element of differential protection [FD_Diff_Exc] and [St_DiffProt_Exc] will operate. 3-4


3 Operation Theory

3.2.17 Overcurrent Protection/Overload Protection of Excitation Transformer/Exciter When the maximum value of three phase currents is greater than the setting [I_OCn_Exc] (n can be 1 or 2), the fault detector element of overcurrent protection [FD_Bak_Exc] and [St_OCn_Exc] will operate.

3.2.18 Breaker Failure Protection at Generator Terminal When the binary input [BI_ExtTrpCtrl] is energized, and phase current or negative-sequence current is greater than the setting value, the fault detector element of breaker failure protection [FD_BFPGCBProt] and [St_BFPGCBProt] will operate.

3.2.19 Mechanical Protection When the operation duration of mechanical protection is greater than its time delay, the fault detector element of mechanical protection [FD_MechRly] and [St_MechRlyn] (n can be 1, 2, 3, 4, 5, 6, 7 or 8) will operate. Note! These setting values of above fault detector elements are formed automatically by the device, it needs not to set manually.

3.3 Differential Protection of Excitation Transformer/Exciter 3.3.1 Operation Characteristic Operation criterion of percentage differential protection is

 I d  K bl  I r  I cdqd   K bl  K bl1  K blr  ( I r / I e )   I d  K bl 2  ( I r  nI e )  b  I cdqd   K blr  ( K bl 2  K bl1 ) /(2  n) b  ( K bl1  K blr  n)  nIe

( I r  nIe ) ( I r  nI e )

Equation 3.3-1

 I1  I 2  I r  2    I  I 1  I 2  d n is the multiple of restraint current at the second slope and is fixed at 6. Figure 3.3-1 shows operation characteristic of differential protection.


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3 Operation Theory

Id Operation area of unrestrained instantaneous differential protection

Icdsd

K st O =1 ea p .0 di d er ffe y s at re ta ion nt te a ia p re l p er a ro ce of te nt ct ag io e n

Operation area of highsetting percentage differential protection

Kbl2

1.2Ie Kbl1 Icdqd 0

Ir Ie

nIe

Figure 3.3-1 Operation characteristic of differential protection

Where: Icdqd is pickup value of differential current fault detector. Id is differential current. Ir is restraint current. Ie is rated current. Icdsd is the setting of unrestrained instantaneous differential protection. Kbl is percentage differential restraint factor and Kb1r is its increment. Kbl1 is the first slope of percentage differential with setting range 0.05~0.15. 0.10 is applicable usually. Kbl2 is the second slope of percentage differential with setting range 0.50~0.80. 0.70 is applicable usually. I1 represents current of HV side of excitation transformer/exciter. I2 represents current of LV side of excitation transformer/exciter. Steady-state percentage differential protection element will not send tripping signal in case of CT saturation, CT circuit failure (optional), inrush current and overexcitation condition. It can ensure sensitivity of protection and avoid unwanted operation when CT is saturated during external fault. Its operation area is tint shadow area. High-setting percentage differential protection element (described in section 3.3.4) will not send 3-6


3 Operation Theory

tripping signal only due to CT circuit failure (optional) and inrush current. It eliminates influence of transient and steady saturation of CT during external fault and ensures reliable operation even if CT is in saturation condition during internal fault by means of its percentage restraint characteristic. Its operation area is deep shadow area. Unrestrained instantaneous differential protection element (described in section 3.3.5) will send tripping signal without any blocking if differential current of any phase reaches its setting. Its operation area is over the above two areas with no shadow.

3.3.2 Inrush Current Detection Element 1.

Second harmonic restraint principle

In the device, the second harmonic of differential current can be used to distinguish inrush current. Its operation criterion is:

I 2 nd  K 2 xb  I1st Where:

I 2 nd is the second harmonic of each phase differential current. I1st is the differential fundamental current of corresponding phase. k 2 xb is the setting of restraint coefficient of second harmonic. (0.15 is recommended value) 2.

Waveform distortion discrimination principle

During internal fault, differential currents of various sides transferred by CT are basically fundamental sinusoidal wave. But when the transformer is energized, lots of harmonics occur. The waveform is intermittent and unsymmetrical. A special algorithm can be used for discrimination of the inrush current. During internal fault, following relation exists:

S  kb*S  S  St Where: S is the full cycle integral of differential current S+ is full cycle integral of the sum of instantaneous value of differential current and that of half cycle before. Kb is a fixed constant. St is a threshold value which can be represented as follows: PCS-985G Generator Relay

3-7 Date: 2013-06-28

3 Operation Theory

St   * I d  0.1* I e Where: Id is the full cycle integral of differential current. α is a proportional constant. Ie is the secondary rated current of excitation transformer/exciter. If any of three phases can not meet above equation, the differential current can be considered as inrush current and percentage differential protection will be blocked. In this device, logic setting is provided for user to select the restraint blocking principle. If the logic setting is set as “0”, discrimination by harmonics is enabled. Otherwise, discrimination by waveform distortion is enabled.

3.3.3 CT Saturation Detection Element In order to prevent undesired operation of steady-state percentage differential protection caused by transient or steady-state CT saturation during external fault, composite harmonics of secondary differential current is used for the device to discriminate CT saturation. The expression is as following:

I cop  K nxb  I1 Where:

I cop is the composite harmonics of phase differential current. I1 is the fundamental component of corresponding phase differential current. k nxb is proportional coefficient. For an internal fault, DPFC restraint current and DPFC differential current appear simultaneously. If DPFC restraint current appears before DPFC differential current, it maybe an external fault. CT saturation detection element shall be adopted in this case. It can prevent percentage differential protection from undesired operation due to CT saturation.

3.3.4 High-setting Percentage Differential Protection Element (HSDP) A percentage differential protection with high percentage and high setting is equipped with the device to prevent delayed operation of percentage differential protection caused by CT saturation and other factors during serious internal fault. This protection is blocked only by inrush current criterion i.e. second harmonic of differential current or waveform discrimination. It can prevent influence of steady state and transient CT saturation during external fault and can operate correctly and quickly during internal fault even if CT is in saturation condition. Operation criterion of 3-8


3 Operation Theory

this high setting percentage differential protection is:

I d  1.2  I e  I d  1.0  I r Where: Id is differential current as mentioned above. Ir is restraint current as mentioned above. Id Instantaneous operation area Icdsd

Operation area K=1.0

1.2Ie Ir

0 Figure 3.3-2 Operation characteristic of HSDP

When fault occurs, the operation criterion will be discriminated phase by phase and percentage differential protection will operate if the criterion is met. Note! Parameters of this protection have been fixed in program and do not need to be configured by user.

3.3.5 Unrestrained Instantaneous Differential Protection Element (UIDP) The aim of unrestrained instantaneous differential protection for excitation transformer/exciter is to accelerate the trip speed for excitation transformer/exciter’s inner fault. So the element does not need any block element, but the setting should be greater than maximum inrush current. Its operation criterion is: Differential current of any phase is greater than the setting [I_InstDiff_Exc].

3.3.6 Differential Current Abnormality Alarm and CT Circuit Failure Blocking Differential current abnormality alarm with percentage restraint and instant CT circuit failure blocking function are equipped with the device.


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3 Operation Theory

CT circuit failure blocking function can be configured by logic setting [Opt_CTS_Blk_PcntDiff_Exc]. When such failure occurs and is discriminated, issuing alarm signal only or blocking percentage differential protection is optional. If the logic setting is set as “1”, percentage differential protection will be blocked immediately.

3.3.7 Overexcitation Detection Element When an excitation transformer/exciter is overexcited, the exciting current will increase sharply which may result in unwanted operation of differential protection. Therefore the overexcitation shall be discriminated to block the current differential protection. The fifth harmonic of differential current is used as criterion of overexcitation discrimination.

I 5th  k5 xb * I1st Where:

I1st is fundamental component of differential current. I 5th is fifth harmonic of differential current.

k5 xb is the fifth harmonic restraint coefficient, it is fixed at 0.25. Note! High-setting percentage differential protection is not blocked by fifth harmonic of differential current.

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3 Operation Theory

3.3.8 Logic Scheme SIG

BI

EN

Flg_UIDP_EXC

&

[En_Diff_Exc]

EN

[En_InstDiff_Exc]

SIG

[FD_Diff_Exc]

SET

[TrpLog_Diff_Exc].Bit0

SIG

Flg_Inrush_Exc

SIG

Flg_HSDP_Exc

BI

&

[EBI_Diff_Exc]

Op_InstDiff_Exc

&

[EBI_Diff_Exc]

EN

[En_Diff_Exc]

EN

[En_PcntDiff_Exc]

SIG

[Alm_CTS_Diff_Exc]

SET

[Opt_CTS_Blk_PcntDiff_Exc]

SIG

[FD_Diff_Exc]

SET

[TrpLog_Diff_Exc].Bit0

SIG

Flg_CTsat

SIG

Flg_Inrush

&

≥1

&

& ≥1

SIG

Flg_SPDP_Exc

BI

[EBI_Diff_Exc]

Op_PcntDiff_Exc

&

EN

[En_Diff_Exc]

EN

[En_PcntDiff_Exc]

SIG

[Alm_CTS_Diff_Exc]

SET

[Opt_CTS_Blk_PcntDiff_Exc]

SIG

Flg_OvExc_Exc

SIG

[FD_Diff_Exc]

≥1

&

&

Figure 3.3-3 Logic diagram of differential protection

Where: FD_Diff_Exc: fault detector of differential protection of excitation transformer/exciter. Flg_UIDP_Exc is the flag indicating whether or not the criterion of UIDP element is met.


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3 Operation Theory

Flg_HSDP_Exc is the flag indicating whether or not the criterion of HSDP element is met. Flg_SPDP_Exc is the flag indicating whether or not the criterion of SPDP element is met. Flg_CTsat is the flag indicating whether or not the CT is in saturation state. Flg_Inrush is the flag indicating whether or not the criterion of inrush current detection is met. Flg_OvExc_Exc is the flag indicating whether or not the excitation transformer/exciter is in overexcitation state.

3.4 Differential Protection of Generator 3.4.1 Percentage Differential Protection (SPDP) Operation characteristic of percentage differential protection is as shown as following figure. Id

Unrestraint operation area Icdsd

Kbl2

Operation area

Restraint area

Kbl1 Icdqd 0

Ir Ie

nIe

Figure 3.4-1 Operation characteristic of percentage differential protection

Operation equation of this percentage differential protection is

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3 Operation Theory

 I d  K bl  I r  I cdqd   K bl  K bl1  K blr  ( I r / I e )   I d  K bl 2  ( I r  nI e )  b  I cdqd   K blr  ( K bl 2  K bl1 ) /(2  n) b  ( K bl1  K blr  n)  nI e

( I r  nI e ) ( I r  nI e )

Equation 3.4-1    I 1 I2   Ir  2     I d  I 1  I 2 

Where:

I d is differential current.

I r is restraint current.

I cdqd is pickup value of differential current. I e is rated current of generator. K bl is percentage differential restraint coefficient and K blr is its increment. K bl1 is the first slope of percentage differential with setting range 0.05~0.15. 0.05 is recommended usually.

K bl 2 is the second slope of percentage differential with setting range 0.30~0.70. 0.50 is recommended usually. n is the multiple of restraint current at second percentage restraint coefficient and is fixed at 4. For differential protection of generator and exciter, I1 and I 2 are currents of terminal and neutral point respectively.

3.4.2 High Performance Blocking Technique in Case of CT Saturation In order to prevent unwanted operation of steady-state percentage differential protection due to CT transient or steady state saturation during external fault, discrimination of waveform of differential current principle is adopted as criterion of CT saturation. PCS-985G Generator Relay

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3 Operation Theory

When fault occurs, the equipment decides firstly whether it is internal or external fault. If it is external fault, criterion of CT saturation is enabled. If any phase differential current of differential protection meets the criterion, it is decided that this differential current comes from CT saturation and the percentage differential protection will be blocked.

3.4.3 High-setting Percentage Differential Protection (HSDP) A percentage differential protection with high percentage coefficient and high pick-up setting is equipped with the equipment to prevent operation of percentage differential protection delayed by CT saturation and other factors during serious internal fault. It can prevent influence of steady state and transient CT saturation during external fault due to its percentage restraint characteristic and can operate correctly and quickly during internal fault and CT being saturated. Operation criterion of this high setting percentage differential protection is

I d  1.2  I e  I d  1.0  I r Where: Differential current I d and restraint current I r are the same as mentioned above. When fault occurs, the operation criterion will be discriminated phase by phase and percentage differential protection will operate if the criterion is met. Parameters of this protection are configured during manufacturing and not need to be configured in site.

3.4.4 Unrestrained Instantaneous Differential Protection (UIDP) This protection will operate and trip immediately if differential current of any phase is higher than its setting.

3.4.5 Differential Current Abnormality Alarm and CT Circuit Failure Blocking Differential current abnormality alarm with percentage restraint and instant CT circuit failure blocking function are equipped with the device. CT circuit failure blocking function can be configured by logic setting [Opt_CTS_Blk_PcntDiff_Gen]. When such failure occurs and is discriminated, issuing alarm signal only or blocking percentage differential protection is optional. If the logic setting is set as “1”, percentage differential protection will be blocked immediately.

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3 Operation Theory


Flg_UIDP_Gen

BI

[EBI_Diff_Gen]

EN

[En_Diff_Gen]

EN

[En_InstDiff_Gen]

SIG

[FD_Diff_Gen]

SET

[TrpLog_Diff_Gen].Bit0

SIG

Flg_HSDP_Gen

BI

& & Op_InstDiff_Gen

&

[EBI_Diff_Gen]

&

EN

[En_Diff_Gen]

EN

[En_PcntDiff_Gen]

SIG

[Alm_CTS_Diff_Gen]

SET

[Opt_CTS_Blk_PcntDiff__Gen]

SIG

[FD_Diff_Gen]

SET


SIG

Flg_CTsat

SIG

Flg_SPDP_Gen

BI

[EBI_Diff_Gen]

≥1

&

≥1 Op_PcntDiff_Gen

&

EN

[En_Diff_Gen]

EN

[En_PcntDiff_Gen]

SIG

[Alm_CTS_Diff_Gen]

SET

[Opt_CTS_Blk_PcntDiff__Gen]

SIG

[FD_Diff_Gen]

&

&

≥1

Figure 3.4-2 Logic diagram of differential protection

Where: Flg_UIDP_Gen is the flag indicating whether or not the criterion of UIDP element is met. Flg_HSDP _Gen is the flag indicating whether or not the criterion of HSDP element is met. Flg_SPDP_Gen is the flag indicating whether or not the criterion of SPDP element is met. FD_Diff_Gen: fault detector of differential protection of generator. Flg_CTsat is the flag indicating whether or not the CT is in saturation state.

3.5 DPFC Differential Protection If slight fault occurs in generator, steady-state differential protection may not response sensitively PCS-985G Generator Relay

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3 Operation Theory

due to influence of load current. DPFC percentage differential protection of generator is equipped with the device for that and it can significantly improve sensitivity of the protection during small current internal fault of generator.

3.5.1 Operation Characteristic The operation criteria of DPFC percentage differential are as follows:

 I d I d  I d I  r I  d

 1.25I dt  I dth  0.6I r

I r  2 I e

 0.75I r  0.3I e

I r  2 I e

Equation 3.5-1

 I1  I 2  I1  I2

Where:

I dt is floating threshold which increases progressively along with DPFC increasing. Take its multiple as 1.25 can ensure threshold voltage always a bit higher than imbalance current. So that unwanted operation of the equipment can be avoided during power swing and frequency deviation conditions.

I1 and I 2 are currents at the generator terminal and the neutral point of generator respectively.

I d is DPFC differential current.

I r is DPFC restraint current whose maximum value is taken for actual restraint. I dth is fixed threshold. Note! Calculation of restraint current of DPFC percentage differential protection is different from steady-state percentage differential protection, it is difficult to test this function on site, so we recommend only qualitative function test on site. DPFC differential protection is equipped to each phase of generator, but the user should know that DPFC restraint quantity for each phase is the same maximum value among the three phases. The following figure shows operating characteristic of DPFC percentage differential protection.

3-16


3 Operation Theory

Differential current

ΔId

Icdqd

0.75

0.6 ΔIr

2Ie

Restraint current

Figure 3.5-1 Operating characteristic of DPFC percentage differential protection

When fault occurs, the operation criterion will be discriminated phase by phase and percentage differential protection will operate if the criterion is met. This protection element has high ability to eliminate the effect of transient and steady-state CT saturation during the external fault because the restraint coefficient is set at a higher value.

3.5.2 Differential Current Abnormality Alarm and CT Circuit Failure Blocking Differential current abnormality alarm with percentage restraint and instant CT circuit failure blocking function are equipped with the device.


Flg_CTsat

SIG

Flg_DPFC_Diff_Gen

BI

&

&

[EBI_Diff_Gen]

0ms EN

[En_Diff_Gen]

EN

[En_DPFC_Diff_Gen]

SET


SIG

[Alm_CTS_Diff_Gen]

SET

[Opt_CTS_Blk_PcntDiff_Gen]

SIG

[FD_Diff_Gen]

20ms

& Op_DPFC_Diff_Gen ≥1

Figure 3.5-2 Logic diagram of DPFC percentage differential protection

Where: PCS-985G Generator Relay

3-17 Date: 2013-06-28

3 Operation Theory

Flg_DPFC_Diff_Gen is the flag indicating whether or not the criterion of DPFC differential element is met. FD_Diff_Gen: fault detector of generator differential protection. Flg_CTsat is the flag indicating whether or not the CT is in saturation state. The corresponding parameters of DPFC differential protection is are fixed and need not to be set on site.

3.6 Generator Inter-turn Protection 3.6.1 High-sensitive Transverse Differential Protection Transverse differential protection installed on connection between two neutral points of generator is used as main protection of inter-turn fault of generator’s stator winding, open circuit fault of branches and short circuit fault between phases. Since this protection adopts frequency tracing, digital filtering and full cycle Fourier algorithm, the third harmonic can be reduced to 1/100 within the frequency tracing range and the protection can response the fundamental component only. This protection comprises two stages: high-setting stage (insensitive stage) and sensitive stage. 3.6.1.1 High-setting Stage This stage is equivalent to traditional transverse differential protection. When the transverse differential current is in excess of the setting [I_InsensTrvDiff_Gen], high-setting stage of transverse differential protection operates. 3.6.1.2 Sensitive Stage Phase current percentage restraint principle is used for this stage. The operation criterion is

I d  I hcZD  I MAX  I e I  (1  K )  I hcZD d hcZD   I e 

when I MAX  I e when I MAX  I e

Where:

I d is the transverse differential current. I hcZD is the transverse differential current setting [I_SensTrvDiff_Gen].

I MAX is the maximum value of three phase current of generator. I d is the rated current of generator.

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3 Operation Theory

K hcZD is the restraint coefficient. Phase current percentage restraint transverse differential principle can ensure no unwanted operation during external fault and sensitive operation during internal fault. As this principle is adopted, current setting of the transverse differential protection shall be only higher than unbalance current during normal operation and much less than that of traditional transverse differential current protection. Sensitivity for inter-turn fault of generator can be enhanced then. This protection has also a floating threshold for high transverse differential unbalance current during other normal operation conditions. Operation of the high sensitive transverse differential protection will lead a tripping immediately. When rotor of generator is grounded at one point, a configurable time delay [t_TrvDiff_Gen] will be inserted in the tripping course. Figure 3.6-1 shows logic diagram of this protection. 3.6.1.3 Logic Scheme SIG

Flg_InsensTrvDiff_Gen

EN

[En_InsensTrvDiff_Gen]

EN

[En_IntTurn_Gen]

BI

[EBI_IntTurn_Gen]

SIG

[FD_IntTurn_Gen]

SET

[TrpLog_IntTurn_Gen].Bit0

& & Op_InsensTrvDiff_Gen

Figure 3.6-1 Logic diagram of high-setting stage transverse differential protection SIG

Alm_1PEF_RotWdg

BI

[BI_1PEF_RotWdg]

≥1

& [t_TrvDiff_Gen] 0s

SIG

Flg_SensTrvDiff_Gen

EN

[En_SensTrvDiff_Gen]

EN

[En_IntTurn_Gen]

BI

[EBI_IntTurn_Gen]

SIG

[FD_IntTurn_Gen]

SET


&

&

≥1

& Op_SensTrvDiff_Gen

Figure 3.6-2 Logic diagram of sensitive stage transverse differential protection

Where: [BI_1PEF_RotWdg]: rotor one-point earth binary input. Flg_SensTrvDiff_Gen is flag indicating the criterion of sensitive stage transverse differential protection of generator is met. Flg_InsensTrvDiff_Gen is flag indicating the criterion of high-setting stage transverse differential protection of generator is met. PCS-985G Generator Relay

3-19 Date: 2013-06-28

3 Operation Theory

FD_IntTurn_Gen: fault detector of inter-turn protection of generator.

3.6.2 Longitudinal Residual Voltage Protection Longitudinal residual voltage protection is configured for inter-turn fault of stator winding of generator. It uses open-delta voltage of dedicated VT at the generator terminal as the criterion. Since this protection adopts frequency tracing, digital filtering and full cycle Fourier algorithm, the third harmonic can be reduced to 1/100 within the frequency tracing range and the protection can response the basic wave component only. Setting of this protection shall be higher than maximum unbalance voltage during external fault, whilst directional flag indicating internal fault must be satisfied. When measured longitudinal residual voltage is in excess of the setting [V_SensROV_Longl_Gen] and lasts for longer than the delay setting [t_ROV_Longl_Gen], this protective element will trip breakers according to the configuration of [TrpLog_IntTurn_Gen]. Operation of this element is usually configured to be delayed shortly by 0.1s~0.2s. 3.6.2.1 Logic Scheme SIG

Flg_Dir_NegP

SIG

Flg_LonglROV_Gen

SIG

Flag_VTS2

EN

[En_SensROV_Longl_Gen]

&

EN

[En_IntTurn_Gen]

BI

[EBI_IntTurn_Gen]

SIG

[FD_IntTurn_Gen]

SET


&

& [t_ROV_Longl_Gen]

Op_SensIntTurn_Gen

Figure 3.6-3 Logic diagram of longitudinal residual voltage protection

Where: Flg_Dir_NegP is internally generated flag indicating whether or not the direction element calculated from negative-sequence voltage and current is met the faulty condition. Flg_LonglROV_Gen is internally generated flag indicating whether or not the longitudinal residual overvoltage protection operates.

3.6.3 VT2 Circuit Failure Alarm and Blocking Longitudinal residual voltage protection for inter-turn fault of stator shall be blocked when the dedicated VT2 circuit at the generator terminal fails. There are two criteria to decide to whether or not block the protection. Criterion 1: 1.

Negative-sequence voltage of VT1: 3U2Uozd

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3 Operation Theory

(residual voltage setting) 2.

Negative-sequence voltage of VT2: 3U2′Uozd (residual voltage setting)

Criterion 2:

U AB  U ab  5V or U BC  U bc  5V or U CA  U ca  5V , and broken-delta voltage of VT2: 3U0′>Uozd (residual voltage setting) Where:

U AB , U BC , U CA are phase-to-phase voltages of VT1 U ab , U bc , U ca are phase-to-phase voltages of VT2 That any one of these three sub-criteria is met means criterion 2 picks up. When any of criterion 1 and criterion 2 operates, alarm of VT2 circuit failure will be issued with a time delay of 40ms and longitudinal residual voltage protection will be blocked. After VT2 circuit failure reverting to normal condition, blocking can be released by pressing the reset button.

3.6.4 DPFC Inter-turn Protection The operation criterion is:    ΔF＝Re ΔU 2  Δ I 2  e jΦ   ε  1.25 dF  

U 2  0.5V  1.25du I 2  0.02In  1.25di If the three criterions are met simultaneity, the directional flag of protection is set. Under negative-sequence voltage and negative-sequence current controlling, the protection operates after 0.2~0.5s time delay. AC current and voltage input of DPFC inter-turn protection are from the generator terminal directly. When the VT1 at the generator terminal fails, DPFC inter-turn protection is blocked. The setting is default setting. The sensitivity is about 3V of longitudinal residual voltage. DPFC inter-turn protection cannot response to inter-turn fault before the generator is connected into the power system.

3.6.5 Calculated Longitudinal Residual Voltage Protection Dedicated VT is not needed in this protection, calculated longitudinal residual voltage used by the PCS-985G Generator Relay

3-21 Date: 2013-06-28

3 Operation Theory

protection is composed of residual voltage of generator terminal VT1 and neutral point, the protection is configured for inter-turn fault of stator winding of generator. The operation criterion is:

U z0  U f 0  K tz U n 0  U z 0 zd Where:

U zozd is the residual voltage setting [V_SensROV_Longl_Gen].

U f 0 is residual voltage of generator terminal VT1.

U n 0 is residual voltage of neutral point. K tz is complex number adjustment coefficient. After the generator is connected into the power system, calculated longitudinal residual voltage protection will be controlled by DPFC negative-sequence power direction element, the voltage setting for this protection should be greater than the maximum unbalance voltage during normal operation. Calculated longitudinal residual voltage protection share the voltage setting and time delay setting with longitudinal residual voltage protection, it can operate to issue alarm signal or trip with a short time delay (0.1s~0.2s.) 3.6.5.1 Logic Scheme EN

[En_Alm_ROV2_Longl_Gen]

EN

[En_IntTurn_Gen]

& [t_ROV_Longl_Gen]

& SIG

Flg_ROV2_Longl_Gen

SIG

Flag_VTS1

SIG

Flg_Gen_UnConnect

SIG

Flg_Dir_NegP

EN

[En_Trp_ROV2_Longl_Gen]

BI

[EBI_IntTurn_Gen]

SIG

[FD_IntTurn_Gen]

SET


Alm_IntTurn2_Gen

>=1

&

& [t_ROV_Longl_Gen]

Op_SensIntTurn2_Gen

Figure 3.6-4 Logic diagram of calculated longitudinal residual voltage protection

Where: Flg_Dir_NegP is internally generated flag indicating whether or not the direction element 3-22


3 Operation Theory

calculated from negative-sequence voltage and current is met the faulty condition. Flg_ROV2_Longl_Gen is internally generated flag indicating whether or not the calculated longitudinal residual overvoltage protection operates. Flg_Gen_UnConnect is the internal generated flag indicating the generator is not connected into the power system.

3.6.6 VT1 Circuit Failure Alarm and Blocking If VT1 circuit fails, calculated longitudinal residual voltage protection will be blocked. Criterion 1: 1.

Negative-sequence voltage of VT1: 3U2Uozd (residual voltage setting)

2.

Negative-sequence voltage of VT2: 3U2′Uozd (residual voltage setting)

Criterion 2:

U ab  U AB  5V

or U bc  U BC  5V

or U ca  U CA  5V , and calculated longitudinal

residual voltage : 3U 0 ′>Uozd (residual voltage setting) Where:

U AB , U BC , U CA are phase-to-phase voltages of VT1. U ab , U bc , U ca are phase-to-phase voltages of VT2. When any of criterion 1 and criterion 2 operates, alarm of VT1 circuit failure will be issued with a time delay of 40ms and calculated longitudinal residual voltage protection will be blocked. After VT1 circuit failure reverting to normal condition, blocking can be released by pressing the reset button.

3.7 Phase-to-phase Backup Protection of Generator 3.7.1 Voltage Controlled Overcurrent Protection This protection is used as a backup protection of generator, main transformer, HV busbar and adjacent lines. There are two stages with their own delay settings respectively. Stage 1 is used to trip bus coupler breaker or other circuit breaker and stage 2 to shut down the generator. Figure 3.7-1 shows its logic diagram. 3.7.1.1 Composite Voltage Element Composite voltage element consists of phase-to-phase undervoltage element and negative-sequence overvoltage element. These two elements are jointed together by OR gate. By PCS-985G Generator Relay

3-23 Date: 2013-06-28

3 Operation Theory

relevant logic setting, stage 1 and stage 2 of overcurrent protection can be configured to be controlled by composite voltage element respectively. 3.7.1.2 Current Memory For generators with self shunt excitation, current will decrease so quickly during fault that it may be lower than overcurrent setting before tripping. So memorized function for remember fault current is equipped with this protection. Logic setting [En_Mem_Curr_Gen] is used for configuration of this function. Note! When logic setting [En_Mem_Curr_Gen] is enabled, overcurrent protection must be controlled by voltage element. 3.7.1.3 Blocking by HV-side Composite Voltage Overcurrent protection can be blocked not only by composite voltage at generator terminal but also by composite voltage at HV side of main transformer. This function can be configured by setting logic setting [En_HVS.VCE_Ctrl_OC_Gen] as “1”. 3.7.1.4 Influence on Protection Performance during VT Circuit Failure A logic setting [Opt_VTS_Ctrl_OC_Gen] is used to configure composite voltage element during VT circuit failure. When this logic setting is set as “1”, if VT circuit failure at this side is detected, the composite voltage element will not meet conditions to operate. When this logic setting is set as “0”, if VT circuit failure at this side is detected, composite voltage element is disabled, overcurrent protection will not be blocked and becomes a pure overcurrent protection.

3-24


3 Operation Theory

3.7.1.5 Logic Scheme SET

Upp< [Vpp_UV_VCE_Gen]

SET

U2>[V_NegOV_VCE_ Gen]

SIG

Flg_VTS

≥1

& ≥1 Flg_VCE_Gen

& SET

[Opt_VTS_Ctrl_OC_Gen]

& ≥1 EN

[En_Mem_Curr_Gen]

SIG

Flg_OCn_Gen

SIG

Flg_VCE_Gen

EN

[En_VCE_Ctrl_OCn_Gen]

EN

[En_PPF_Gen]

&

≥1

& SET

& [t_OCn_Gen] 0s

[TrpLog_OCn_Gen].Bint0

BI

[EBI_PPF_Gen]

SIG

[FD_PPF_Gen]

Op_OCn_Gen

Figure 3.7-1 Logic diagram of overcurrent protection

Where: Upp represents any one of the three phase-to-phase voltage of generator. U2 is negative sequence voltage of generator calculated by protection. Flg_OCn_Gen is internally generated flag indicating stage n of overcurrent operates, which means the measured current is in excess of its setting [I_OCn_Gen].. FD_PPF_Gen: fault detector of phase-to-phase backup protection of generator. n can be 1 or 2. As for principle of discrimination of VT circuit failure, see section 3.26.

3.7.2 Impedance Protection Two stages impedance protection is equipped at the generator terminal as its phase-to-phase backup protection. Phase-to-phase current used in impedance protection is derived from CT at the neutral point of generator. Full impedance, directional impedance or shifted impedance characteristic can be selected to operate for these two stages. Full impedance characteristic suits case of forward setting of a zone being equal to its reverse setting. Directional impedance characteristic suits case of reverse setting of a zone being set as 0. Shifted impedance characteristic suits for case that forward setting of a zone is higher than its reverse setting. Reach angle of impedance protection is 78°. Forward of the impedance protection is configurable and PCS-985G Generator Relay

3-25 Date: 2013-06-28

3 Operation Theory

generally points to generator.

jX 

I Zp





U I Zp

m



U





 I Zn

R



U  I Zn

Figure 3.7-2 Operation characteristic of impedance protection

Figure 3.7-2 shows operation characteristic of impedance protection. In this figure, I is phase current, U is corresponding phase-to-phase voltage, Zn is reverse impedance setting, and Zp is forward impedance setting. Operation criterion:

90  Arg









(U  I Z P )

 270

(U  I Z n ) DPFC phase-to-phase current and negative-current current are adopted as fault detector of impedance protection. Pickup signal will be maintained 500ms and will be kept if impedance protection operates during this time interval. Operation criterion of the fault detector is:

I  1.25I t  I th Where:

I t is floating threshold which increases gradually along with DPFC increasing. Take its multiple as 1.25 can ensure threshold voltage always a bit higher than imbalance voltage. Unwanted operation of the device can be avoided during conditions of power swing and frequency deviation from nominal values.

I th is the fixed threshold. When DPFC phase-to-phase current is higher than 0.2Ie, the fault detector operates. The logic scheme of impedance protection is shown in Figure 3.7-3.

3-26


3 Operation Theory SIG

Flg_VTS

SIG

Flg_Zn_Gen

EN

[En_PPF_Gen]

BI

[EBI_PPF_Gen]

SIG

[FD_PPF_Gen]

SET

[TrpLog_Zn_Gen].Bit0

& &

& [t_Zn_Gen] 0s

Op_Zn_Gen

Figure 3.7-3 Logic diagram of impedance protection

Where: Flg_Zn_Gen is internally generated indicating stage n of distance protection of generator is met. n can be 1 or 2. Note! If VT circuit failure occurs, impedance protection of generator will be blocked. Note! When stage 1 of phase-to-phase backup protection of generator operates to trip bus coupler circuit breaker, this function can be selected whether or not be blocked by the logic setting [En_CB_Ctrl_OC1_Gen].

3.8 Stator Earth-fault Protection 3.8.1 Fundamental Residual Overvoltage Protection Single-phase earth fault within 85%~95% ranges from terminal of stator winding can be protected by fundamental residual overvoltage protection. Fundamental residual overvoltage protection reacts to magnitude of residual voltage of generator. Since it adopts frequency tracing, digital filtering and full cycle Fourier algorithm, the third harmonic can be reduced to 1/100 within the frequency tracing range and the protection can response the basic wave component only. This protection comprises two stages: sensitive stage and insensitive stage (high setting stage). 3.8.1.1 Sensitive Stage Operation criterion:

U n0  U 0zd Where:


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3 Operation Theory

U n 0 is residual voltage of neutral point of generator. U 0zd is operation threshold setting of fundamental residual voltage [V_SensROV_Sta]. When the sensitive stage operates to trip, in order to prevent sensitive stage of fundamental residual overvoltage protection from undesired trip due to external fault, it can be blocked by residual voltage at HV side of main transformer, and the blocking setting of residual voltage can settable. 3.8.1.2 High-setting Stage Operation criterion:

U n0  U 0hzd Where:

U n0 is residual voltage of neutral point of generator. U 0hzd is residual voltage high setting [V_InsensROV_Sta]. 20V~25V is recommended generally. The high-setting stage can be independently set to trip.

3.8.2 Third Harmonic Voltage Ratio Protection This protection is designed to cover only about 25% of earth fault of the stator winding away from generator terminal. Third harmonic voltage of generator terminal is got from its broken-delta residual voltage. Third harmonic voltage of neutral point side is got from neutral point VT of the generator. Operation criterion:

U 3T / U 3N  K 3wzd Where:

U 3T and U 3N are third harmonic voltage of generator terminal and neutral point respectively. K 3wzd is the third harmonic voltage percentage setting. During incorporation of generator to power system, the ratio U3T/U3N changes considerably owing to variation of equivalent capacitive reactance at generator terminal. So two different settings are designed for protection before and after connection of generator with system, and these two settings can be switched over with alternation of contacts’ position of the terminal breaker. In addition, settings are provided for deciding whether the ratio protection of third harmonics 3-28


3 Operation Theory

voltage is used for alarm or tripping or both. Third harmonic voltage ratio protection can operates for alarm purpose or trip purpose.

3.8.3 Third Harmonic Voltage Differential Protection Operation criterion: 





U 3T  K t  U 3 N  Kre  U 3 N Where: 



U 3T and U 3 N are third harmonic vector voltage of generator terminal and neutral point K t is automatic tracing regulation coefficient K re is third harmonic differential percentage setting This protection is enabled automatically when the generator has been connected with the system and load current is higher than 0.2 Ie (generator rated current) and only issues alarms if operates. Third harmonic voltage differential protection operates only for alarm purpose.

3.8.4 VT Circuit Failure Blocking 1.

Broken-delta VT circuit failure alarm of generator terminal and neutral point of generator

Since broken-delta voltages of VT at neutral point and generator terminal are taken for residual voltage protection of stator, failure of these VT circuits will make this protection fail to operation. So alarm shall be issued during this case. Third harmonic voltage ratio criterion and third harmonic voltage differential criterion shall be disabled during VT circuit failure at neutral point of generator. The operation criterion is: Positive-sequence voltage of secondary winding of generator terminal is higher than 0.9Un and third harmonic of residual voltage is lower than 0.1V. VT circuit failure alarm will be issued by delay 10s and reverted automatically by delay 10s when the failure vanishes. If residual voltage of generator terminal is from calculated residual voltage, broken-delta circuit failure of VT1 at generator terminal is not discriminated. The alarm function of broken-delta VT circuit failure of generator terminal and neutral point of generator can be enabled or disabled by logic setting [En_Alm_DeltVTS1_Gen]. 2.

Primary circuit failure of VT1 at generator terminal

Secondary circuit failure of VT1 of generator terminal will not influence ground protection of stator. PCS-985G Generator Relay

3-29 Date: 2013-06-28

3 Operation Theory

Primary circuit failure of VT1 of generator terminal will cause basic wave component of residual voltage of generator terminal increasing and third harmonic component decreasing, and will not cause unwanted operation of basic wave residual voltage protection and third harmonic voltage ratio protection. However, it will cause unwanted operation of third harmonic voltage differential protection, so this protection shall be blocked during this failure. The operation criterion is: 1.

Negative-sequence voltage of VT2: 3U2′<3V

2.

Negative-sequence voltage of VT1: 3U2 >8V

3.

Calculated residual voltage of VT1: 3U0>8V

4.

Open-delta residual voltage of VT1: 3U0>8V

When these criterions are met, VT1 primary circuit failure alarm will be sent by short delay and third harmonic voltage differential protection and third harmonic voltage ratio protection will be blocked. If residual voltage of generator terminal is from calculated residual voltage, primary circuit failure of VT1 is not discriminated.

3.8.5 Logic Scheme Figure 3.8-1 show logic diagrams of stator earth-fault protection.

3-30


3 Operation Theory EN

[En_EF_Sta]

EN

[En_Alm_ROV_Sta]

SIG

Flg_SensROV_Sta

SIG

Flg_SensROV_Sta

SIG

Flg_Blk_SensROV_Sta

EN

[En_Trp_ROV_Sta]

EN

[En_EF_Sta]

BI

[EBI_ROV_Sta]

& [t_ROV_Sta] 0s

&

&

& [t_ROV_Sta] 0s

SIG

[FD_StaEF_Gen]

SET

[TrpLog_EF_Sta].Bint0

SIG

Flg_InsensROV_Sta

EN

[En_Trp_InsensROV_Sta]

EN

[En_EF_Sta]

BI

[EBI_ROV_Sta]

SIG

[FD_StaEF_Gen]

SET

[TrpLog_EF_Sta].Bint0

Alm_ROV_Sta

Op_SensROV_Sta

& &

& [t_InsensROV_Sta] 0s

EN

[En_Alm_V3rdHRatio_Sta]

SIG

Flg_VTS

Op_InsensROV_Sta

& [t_V3rdH_Sta] 0s

Alm_V3rdHRatio_Sta

&

SIG

Flg_V3rdHRatio_Sta

EN

[En_EF_Sta]

EN

[En_Trp_V3rdHRatio_Sta]

BI

[EBI_V3rdH_Sta]

SIG

[FD_StaEF_Gen]

SET

[TrpLog_EF_Sta].Bit0

&

&

EN

[En_Alm_V3rdHDiff_Sta]

SIG

Flg_VTS

[t_V3rdH_Sta] 0s

& [t_V3rdH_Sta] 0s

BI

Flg_V3rdHDiff_Sta

EN

[En_EF_Sta]

Alm_V3rdHDiff_Sta

&

[EBI_V3rdH_Sta]

SIG

Op_V3rdHRatio_Sta

Figure 3.8-1 Logic diagram of stator earth-fault protection

Where: Flg_SensROV_Sta is internally generated flag indicating sensitive stage of fundamental residual overvoltage protection operates. Flg_Blk_SensROV_Sta is voltage blocking condition for sensitive stage fundamental residual overvoltage protection, i.e. residual voltage at HV side of main transformer is smaller than a PCS-985G Generator Relay

3-31 Date: 2013-06-28

3 Operation Theory

settable value and there have broken-delta residual voltage for generator terminal. Residual voltage at HV side of main transformer, and the blocking setting of residual voltage can settable. When the sensitive stage operates to trip, it will be blocked by broken-delta residual voltage of generator terminal, and the blocking setting need not be set. Flg_InsensROV_Sta is internally generated flag indicating insensitive stage of fundamental residual overvoltage protection operates. Flg_V3rdHRatio_Sta is internally generated flag indicating third harmonic voltage ratio protection operates. Flg_V3rdHDiff_Sta is internally generated flag indicating third harmonic voltage differential protection operates.

3.9 Stator Earth-fault Protection with Voltage Injection Earthing transformer

GND

Main transformer

Generator

Breaker

Busbar

G Band-Pass Filter B10 Load Resistor Voltage Divider

Rn

Square-wave power supply

A2 Inter-CT Panel B

ISEF USEF

RCS-985U auxiliary power supply for stator earth fault protection

PCS-985B Generator Relay

Figure 3.9-1 Circuit design of stator earth-fault protection with voltage injection

An external low-frequency alternating voltage source injects into neutral point of the generator via secondary side of earthing transformer, or injects into secondary side of broken-delta VT at the generator terminal.

3.9.1 Earthing Resistance Criterion Earthing resistance criterion is not related to the location of stator windings earth fault, and it can protect 100% range of stator windings for single-phase earth-fault. According to the earthing resistance of stator windings, PCS-985G provides two stages for alarm purpose with high setting and for trip purpose with low setting respectively. The operation

3-32


3 Operation Theory

criterions are:

RE  REsetL

(for trip purpose)

RE  REsetH

(for alarm purpose)

Where:

RE is calculated earth resistance. REsetL is resistance setting for trip purpose. REsetH is resistance setting for alarm purpose.

3.9.2 Earthing Current Criterion If an earth fault happens to stator windings near generator terminal during normal generator operation, fundamental components will increase obviously and the sensitivity of detecting low-frequency faulty components will be affected seriously. In order to improve the sensitivity, earthing current criterion is equipped with the device. It can detect single-phase fault with the range of 80%~90% stator windings away from generator terminal. The great advantage of this criterion is that more close to the generator terminal the fault point locates, more high sensitivity the criterion can get, which can realize 100% stator earth-fault protection cooperated with the earthing resistance criterion. The operation criterion is:

I G 0  I Eset Where:

I G 0 is earthing current of stator without being subjected to digital filter. I Eset is earthing current setting.

3.9.3 External Voltage Circuit Monitoring When U LF 0 ( U G 0 is low-frequency voltage after Un0 is digital filtered) is smaller than the setting value or I LF 0 ( I G 0 is low-frequency current after In0 is digital filtered) is smaller than the setting value, it means that external injection circuit for stator earth-fault protection is abnormal. The device will be blocked and issue an alarm signal.


3-33 Date: 2013-06-28

3 Operation Theory

The operation criterion is:

U LF 0  U LF 0 set  I LF 0  I LF 0 set Where:

U LF 0 set is alarm setting of low-frequency voltage I LF 0 set is alarm setting of low-frequency current

3.9.4 Logic Scheme SET

ULF0<[V_Supv_Inj_EF_Sta]

≥1

& 0s

SET

ILF0<[I_Supv_Inj_EF_Sta]

SET

RE<[R_Alm_Inj_EF_Sta]

EN

[En_Alm_R_Inj_EF_Sta]

EN

[En_Inj_EF_Sta]

SET

RE<[R_Trp_Inj_EF_Sta]

EN

[En_Trp_R_Inj_EF_Sta]

BI

[EBI_V3rdH_Sta]

0.1s

Alm_Inj_Circuit

& [t_Alm_Inj_EF_Sta] 0s

Alm_InjEF_Sta

& [t_Trp_Inj_EF_Sta] 0s

SIG

[FD_InjStaEF_Gen]

SET

[TrpLog_Inj_EF_Sta].Bit0

SET

IG0>[I_ROC_Inj_EF_Sta]

EN

[En_Trp_I0_Sta]

EN

[En_Inj_EF_Sta]

BI

[EBI_V3rdH_Sta]

SIG

[FD_InjStaEF_Gen]

SET

[TrpLog_Inj_EF_Sta].Bit0

Op_InjEF_Sta

&

&

& &

[t_Trp_Inj_EF_Sta] 0s

Op_InjI0_Sta

Figure 3.9-2 Logic diagram of stator earth-fault protection with voltage injection

3.10 Rotor Earth-fault Protection with Ping-pang Type 3.10.1 One-point Earth-fault Protection If one-point earth fault of rotor occurs, insulation resistance between rotor winding and the axis will drop down. Rotor earth-fault protection adopts switch-over sampling principle (ping-pang type) Rotor earth-fault protection measures earthing resistance Rg of the winding by an unbalance bridge as shown in Figure 3.10-1. Corresponding equations can be got by switching over S1 and S2 alternately, and earthing resistance Rg and location of the earthing point “α” can be found by 3-34


3 Operation Theory

calculation. There are two stages equipped for one-point earth protection: sensitive stage and regular stage. Sensitive stage is used for alarm and regular stage for tripping or alarm. U

aU

+

rotor

Rg

R

R

S2

S1

R

R

Figure 3.10-1 Schematic diagram of measurement principle

Figure 3.10-2 show logic scheme of one-point earth fault protection. SET

Rg<[R_Sens1PEF_RotWdg]

& [t_Alm_1PEF_RotWdg] 0s

EN

[En_EF_RotWdg]

EN

[En_Alm_Sens1PEF_RotWdg]

EN

[En_Alm_1PEF_RotWdg]

SET

Rg<[R_1PEF_RotWdg]

EN

[En_EF_RotWdg]

EN

[En_Trp_1PEF_RotWdg]

BI

[EBI_EF_RotWdg]

SIG

[FD_EF_RotWdg]

SET

[TrpLog_EF_RotWdg].Bit0

Alm_Sens1PEF_RotWdg


&

Alm_1PEF_RotWdg

&

& [t_Trp_1PEF_RotWdg] 0s

Op_1PEF_RotWdg

Figure 3.10-2 Logic diagram of one-point earth fault protection

3.10.2 Two-points Earth fault Protection If one-point earth protection is used for alarm only, when earth resistance Rg is less than setting of its regular stage [R_1PEF_RotWdg], it will switch into two-points earth fault protection with a time delay automatically. If the location of the earthing point varies and the variation reaches its setting value, two-point earth fault protection will operate and issue a tripping command. In order to improve the reliability, two-point earth fault protection can be blocked by second harmonic voltage by setting logic setting [En_VCE_2PEF_RotWdg] as “1”. Figure 3.10-3 show logic diagram of two-points earth fault protection.


3-35 Date: 2013-06-28

3 Operation Theory t 0s

SIG

Alm_1PEF_RotWdg

SIG

Flg_2PEF_RotWdg

EN

[En_EF_RotWdg]

SIG

Flg_V2ndH_VCE_2PEF_RotWdg

& &

≥1

& [t_2PEF_RotWdg] 0s

EN

[En_VCE_2PEF_RotWdg]

EN

[En_2PEF_RotWdg]

BI

[EBI_EF_RotWdg]

SIG

[FD_EF_RotWdg]

SET


Op_2PEF_RotWdg

&

Figure 3.10-3 Logic diagram of two-points earth fault protection

Where: Flg_2PEF_RotWdg is the flag indicating whether or not two-point earth-fault protection meet its criterion. Flg_V2ndH_VCE_2PEF_RotWdg is the flag indicating whether or not the second harmonics element used for control 2PEF operates.

3.11 Rotor Earth-fault Protection with Voltage Injection 3.11.1 One-point Earth-fault Protection Based on leading-out mode of rotor windings, rotor earth fault protection with injection principle of double-ends or single-end can be selected. The injected power supply is connected to rotor winding from between the positive/negative pole (or only negative pole) and shaft. The switching cycle of injected power supply can be adjusted depended on in accordance with the capacitor between rotor winding and ground. The rotor earth-fault protection with injection principle can reflect a decline in insulation resistance between generator rotor and shaft by real-time calculating one-point earth resistance of rotor. The work circuit of voltage injection into the rotor winding at double-ends and single-end is shown in Figure 3.11-1 and Figure 3.11-2 respectively. Ur+

Rg

Ig

Usq Rotor Axis Rx

Uα Ur-

Ry

Figure 3.11-1 Measuring scheme of voltage injection into the rotor winding at single-end

3-36


3 Operation Theory Ry

Ur+

Rg

Usq Rotor Axis Rx

Ig

Uα Ur-

Ry

Figure 3.11-2 Measuring scheme of voltage injection into the rotor winding at double-ends

Where: Ur: the rotor voltage α: the percentage of earthing location RX: the resistance of measure circuit Ry: the injected external resistance Usq: the injected square power supply Rg: the insulation resistance between rotor windings and shaft Rotor one-point earth fault protection provides two stages: one stage is sensitive stage used to issue alarm signal, and the other stage, regular stage, can operate to issue alarm signal or trip. Figure 3.11-3 show logic diagram of one-point earth fault protection.

SET

Rg<[R_Sens1PEF_RotWdg]


EN

[En_EF_RotWdg]

EN

[En_Alm_Sens1PEF_RotWdg]

EN

[En_Alm_1PEF_RotWdg ]

SET

Rg<[R_1PEF_RotWdg]

EN

[En_EF_RotWdg]

EN

[En_Trp_1PEF_RotWdg]

BI

[EBI_EF_RotWdg]

SIG

[FD_EF_RotWdg]

SET


Alm_Sens1PEF_RotWdg


&

Alm_1PEF_RotWdg

&

& [t_Trp_1PEF_RotWdg] 0s

Op_1PEF_RotWdg

Figure 3.11-3 Logic diagram of one-point earth-fault protection

3.11.2 Two-point Earth-fault Protection If both positive and negative terminal of rotor windings are leaded out, rotor earth-fault protection PCS-985G Generator Relay

3-37 Date: 2013-06-28

3 Operation Theory

with voltage injection can measure the one-point earthing location, and then implement two-point earth fault protection according to the variation of the earthing location. If rotor one-point earth fault protection is used to issue alarm signal only, it is optional whether rotor two-points earth fault protection is put into service or not. If it is selected to be in service, rotor two-point earth fault protection will be enabled automatically with a time delay after regular stage of rotor one-point earth fault protection operating to issue alarm signal. After that, if the location of earthing point varies and the variation reaches its internal threshold value, the protective device thinks it as two-point earth fault and rotor two-points earth fault protection will operate to trip. Figure 3.11-4 show logic diagram of two-point earth fault protection. SIG

Alm_1PEF_RotWdg

SIG

Flg_2PEF_RotWdg

EN

[En_EF_RotWdg]

EN

[En_2PEF_RotWdg]

BI

[EBI_EF_RotWdg]

SIG

[FD_EF_RotWdg]

t 0s

& & [t_2PEF_RotWdg] 0s

SET

Op_2PEF_RotWdg

&


Figure 3.11-4 Logic diagram of two-points earth-fault protection

Note!

The device only can enable any of rotor earth-fault protection with ping-pang type and rotor earth-fault protection with voltage injection, the other is reserved.

3.12 Stator Overload Protection Stator overload represents average heating of winding of the stator. This protection takes currents from generator terminal and neutral point as its criterion.

3.12.1 Definite-time Stator Overload Protection There are two stages equipped with definite-time stator overload protection: one for alarm and another for tripping. Figure 3.12-1 shows its logic diagram.

3-38


3 Operation Theory SET

I>[I_Alm_OvLd_Sta]

& [t_Alm_OvLd_Sta] 0s

EN

[En_OvLd_Sta]

SET

I>[I_OvLd_Sta]

EN

[En_OvLd_Sta]

BI

[EBI_OvLd_Sta]

Alm_OvLd_Sta

&

& [t_OvLd_Sta] 0s

SIG

[FD_StaOvLd_Gen]

SET

[TrpLog_OvLd_Sta].Bit0

Op_OvLd_Sta

Figure 3.12-1 Logic diagram of definite-time stator overload protection

3.12.2 Inverse-time Stator Overload Protection Inverse-time stator overload protection consists of three parts: low-setting initiator, inverse-time part and upper-limit definite-time part. The upper-limit definite-time part has minimum operating time. When stator current reaches its low setting (Iszd), inverse-time part initiates and the heat is accumulated. When the accumulated value is greater than the setting, inverse-time stator overload protection operates to trip. Inverse-time part can simulate generator-heating process including heat accumulation and dissipation. When the stator current is lower than rated value, the heat accumulation will decrease accordingly. Figure 3.12-2 shows the inverse-time curve. I Ih

Iszd

t min

t max

Figure 3.12-2 Operation curve of inverse-time stator overload protection

Where: tmin is time delay of upper limit tmax is time delay of lower limit Iszd is initiation setting of inverse-time part PCS-985G Generator Relay

3-39 Date: 2013-06-28

3 Operation Theory

Ih is upper-limit current value Operation criterion of inverse-time stator overload protection:

[( I I ezd）  K srzd  ]  t  KS zd 2

2

Where:

KS zd is time constant of generator heating K srzd is heat dissipation factor of generator I ezd is rated secondary current of generator Figure 3.12-3 shows logic diagram of inverse-time stator overload protection. SET

I > [I_InvOvLd_Sta]

EN

[En_OvLd_Sta]

BI

[EBI_OvLd_Sta]

SIG

[FD_StaOvLd_Gen]

SET

[TrpLog_InvOvLd_Sta].Bit0

&

IDMT

&

[tmin_InvOvLd_Sta] 0s

& Op_InvOvLd_Sta

Figure 3.12-3 Logic diagram of inverse-time stator overload protection

Note ! In order to prevent heat accumulation from not being dissipated, the dissipation coefficient (the setting [K_Disspt_Sta])should be set as 1.02~1.05.

3.13 Negative-sequence Overload Protection Negative-sequence overload reflects overheating on surface of the rotor and other abnormality due to negative-sequence current. This protection takes negative-sequence current at generator terminal and neutral point as its criterion.

3.13.1 Definite-time Negative-sequence Overload Protection There are two stages equipped with definite-time negative-sequence overload protection: one for alarm and the other for tripping. Figure 3.13-1 shows its logic diagram.

3-40



[En_NegOC_Gen]

& [t_Alm_NegOC_Gen] 0s

SET

I2>[I_Alm_NegOC_Gen]

SET

I2>[I_NegOC_Gen]

&

EN

[En_NegOC_Gen]

SET

[TrpLog_NegOC_Gen].Bit0

BI

[EBI_NegOC_Gen]

SIG

[FD_NegOC_Gen]

Alm_NegOC_Gen

& [t_NegOC_Gen] 0s

Op_NegOC_Gen

Figure 3.13-1 Logic diagram of definite-time negative-sequence overload protection

3.13.2 Inverse-time Negative-sequence Overload Protection Inverse time negative sequence protection consists of three parts: low-setting initiator, inverse-time part and upper-limit definite-time part. The upper-limit definite-time part has minimum operating time. When negative-sequence current reaches its low setting [I_InvNegOC_Gen], inverse-time part initiates and the heat is accumulated. When the accumulated value is greater than the setting, inverse-time negative-sequence overload protection operates to trip. Inverse-time part can simulate generator-heating process including heat accumulation and dissipation. When the stator current is lower than permissive continuous negative-sequence current [I_Neg_Perm_Gen], the heat accumulation will decrease accordingly. Figure 3.13-2 shows the inverse-time curve. I

I2zd

t min

t max

Figure 3.13-2 Operation curve of inverse-time negative-sequence overload protection

Operation criterion of inverse-time negative-sequence overload protection:

[( I 2 I ezd）  I 21  ]  t  A 2

2

Equation 3.13-1

Where:


3-41 Date: 2013-06-28

3 Operation Theory

I 2 is generator negative-sequence current I ezd is generator rated current I 2l is permissive continuous negative-sequence current (per unit value) A is negative-sequence heating constant of rotor. Inverse-time negative-sequence overload protection can be set to trip to separation and field suppression or alarm. Figure 3.13-3 shows its logic diagram.

SET

I2>[I_InvNegOC_Gen]

t>[tmax_InvNegOC_Gen]

&

≥1 IDMT

EN

&

[En_NegOC_Gen] [tmin_InvNegOC_Gen] 0s

SET

[TrpLog_InvNegOC_Gen].Bit0

&

& Op_InvNegOC_Gen

BI

[EBI_NegOC_Gen]

SIG

[FD_NegOC_Gen]

Figure 3.13-3 Logic diagram of inverse-time negative-sequence overload protection

Note! The long time delay of lower limit should be smaller than the calculated operating time using lower-limit pickup current according to Equation 3.13-1.

3.14 Loss-of-excitation Protection Loss of excitation represents abnormal operation of generator due to excitation failure. There are 3 criterion used for loss-of-excitation protection: undervoltage criterion, stator-side impedance criterion and rotor-side criterion.

3.14.1 Undervoltage Criterion Three-phase voltages on busbar side generally and those at generator terminal sometimes are taken as this criterion. Three-phase voltage should meet the criterion simultaneous.

U pp  U lezd Where: Upp is phase-to-phase voltage of busbar or of generator terminal. Ulezd is undervoltage setting [V_BusUV_LossExc_Gen]. When bus voltage is taken as the criterion, if bus VT circuit fails, the protection will be blocked. 3-42


3 Operation Theory

When generator terminal voltage is taken as the criterion, if one group of VT circuit fails, the other group of VT will be switched over automatically.

3.14.2 Stator-side Impedance Criterion This criterion is impedance circle including asynchronous impedance circle and steady-state stabilization limit circle. The operation criterion is

270  Arg

Z  jX B  90 Z  jX A

Where: XA: can be set as the system impedance Xs for steady-state stabilization limit circle and XA= 0.5 X'd for asynchronous impedance circle XB: is taken as Xd+0.5 X'd for non-salient pole generator and 0.5(Xd＋Xq)+0.5 X'd for salient pole generator The impedance criterion can be combined with reverse reactive power criterion, i.e., Q<[Q_RevQ_LossExc_Gen]. Using the same current and voltage to calculate inactive power and reverse power. Figure 3.14-1 and Figure 3.14-2 show operation characteristics of steady-state stabilization impedance circle and asynchronous impedance circle.

jx Z1

R -Qzd

Z2

Figure 3.14-1 Operation characteristic of steady-state stabilization impedance circle

The hatched area is operating area, and the dotted line is operation limit of reverse reactive power.


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3 Operation Theory

jx

-Qzd

R

Z1

Z2 Figure 3.14-2 Operation characteristic of asynchronous impedance circle

Besides operation criterion mentioned above, there are also auxiliary operation criterion, namely: 1.

Positive-sequence voltage is greater than or equal to 6V

2.

Negative-sequence voltage U2 is lower than 0.1Un (rated voltage of generator)

3.

Generator current is no less than 0.1Ie (rated current of generator)

3.14.3 Rotor-side Criterion Rotor-side criterion comprises: Rotor-side undervoltage criterion: Ur

3 Operation Theory

rotor under voltage criterion and the variable excitation voltage criterion will be met and withdrawn periodically in general. So the excitation voltage element will revert with delay during out-of-step condition while the impedance entering the steady state stability limit circle.

3.14.4 Logic Scheme Three stages are equipped with loss-of-excitation protection: stage 1 is used to trip adopting busbar-side undervoltage criterion, stage 2 is used to trip adopting generator terminal undervoltage criterion, stage 3 is used to trip or alarm with long time delay. Figure 3.14-3 shows logic diagram of stage 1 of loss-of-excitation protection. SET

Ur<[V_BusUV_LossExc_Gen]

& ≥1

EN

[En_BusUV_LossExc1_Gen]

SET

Ur<[V_RotUV_LossExc_Gen]

SET

Ur
EN

[En_RotUV_LossExc1_Gen]

SIG

Flg_Z_LossExc1_Gen

EN

[En_Z_LossExc1_Gen]

SET

Q>[Q_RevQ_LossExc_Gen]

EN

[En_RevQ_LossExc_Gen]

EN

[En_LossExc_Gen]

BI

[EBI_LossExc_Gen]

& ≥1

& ≥1

& &

[t_LossExc1_Gen] 0s

&

&

Op_LossExc1_Gen

≥1

&

&

SET

[TrpLog_LossExc1_Gen].Bit0

SIG

[FD_LossExc_Gen]

Figure 3.14-3 Logic diagram of loss-of-excitation protection (stage 1)

Figure 3.14-4 shows logic diagram of stage 2 of loss-of-excitation protection. If excitation is lost and voltage at generator terminal is lower than its setting, this stage will trip with a time delay. In configuring this stage, considering of security, it is strongly recommended that impedance criterion should be used as well as undervoltage criterion rather than that only undervoltage (busbar or generator terminal) criterion and rotor undervoltage criterion are used.


3-45 Date: 2013-06-28


Upp<[V_TermUV_LossExc_Gen]

EN

[En_TermUV_LossExc2_Gen]

SET


SET

Ur
EN


SIG

Flg_Z_LossExc2_Gen

EN

[En_Z_LossExc2_Gen]

SET


EN


& ≥1

≥1

& &

≥1

[t_LossExc2_Gen] 0s

&

&

&

EN

[En_LossExc_Gen]

BI

[EBI_LossExc_Gen]

Op_LossExc2_Gen

≥1

&

SET


SIG

[FD_LossExc_Gen]


Figure 3.14-5 shows logic diagram of stage 3 of loss-of-excitation protection. It is also used to trip with a long time delay. EN

[En_Alm_LossExc3_Gen]

SET


SET

Ur
≥1

& EN


SIG

Flg_Z_LossExc3_Gen

EN

[En_Z_LossExc3_Gen]

SET


EN


EN

[En_LossExc_Gen]

BI

[EBI_LossExc_Gen]

SIG

[FD_LossExc_Gen]

SET


≥1

& [t_LossExc3_Gen] 0s

&

Alm_LossExc_Gen

&

&

≥1

& [t_LossExc3_Gen] 0s

&

Op_LossExc3_Gen


3.15 Out-of-step Protection Out-of-step protection represents asynchronous operation of generator due to out of step. Out-of-step protection calculates impedance element by positive-sequence voltage and current,

3-46


3 Operation Theory

and impedance locus can reflect any kinds of fault situation correctly. Figure 3.15-1 shows operation characteristic of out-of-step protection that comprises three parts: lens part, boundary part and reactance line part.

jx

Za

U D

OL

Zc IL

1

2

3

IR

1

OR

0 L

Zb

R

R

Figure 3.15-1 Operation characteristic of out-of-step protection

1.

Lens divides impedance plane into inside part I and outside part O

2.

Boundary divides the impedance plane into left part L and right part R

3.

Reactance line divides the impedance plane into upper part U and lower part D

Considering lens and boundary comprehensively, the impedance plane is divided into four areas: OL, IL, IR and OR. If the locus of impedance is passing through these four areas in sequence from right to left or vice versa, and staying in each area for a moment longer than the setting, this case is considered as power swing. The times of passing through are accumulated and the grand total is considered as the times of pole sliding. When the grand total reaches its setting value, out-of-step protection operates. As to reactance line, if the impedance locus passes through the upper part U, the swing center is considered outside the generator. If the locus passes through the lower part D, the swing center is considered within the generator. Settings of times of pole sliding can be configured separately for these two cases. Out-of-step protection can be used either for alarm only or tripping. Minimum swing period which can be identified by this protection is 120 ms. Figure 3.15-2 shows logic diagram of out-of-step protection.


3-47 Date: 2013-06-28


[En_Alm_X_OOS_Gen]

SIG

Flg_Blk_OOS

SIG

Flg_OOS_Gen

EN

[En_OOS_Gen]

EN

En_Trp_X_OOS_Gen

BI

[EBI_OOS_Gen]

SIG

[FD_OOS_Gen]

SET

[TrpLog_OOS_Gen].Bit0

& Accumulated Times

Alm_X_OOS_Gen

&

&

& Accumulated Times

Op_X_OOS_Gen

Figure 3.15-2 Logic diagram of out-of-step protection

Where: “X” can be “Int” or “Ext”.

3.16 Generator Voltage Protection 3.16.1 Overvoltage Protection Overvoltage protection is used as protection against stator overvoltage occurring in various operation conditions. It will issue tripping command when the maximum phase-to-phase voltage at the generator terminal is in excess of the setting. Voltage calculation is independent of the variation of frequency. Two stages of overvoltage protection are equipped with PCS-985G for tripping, stage 2 can also operate for alarming. Stage 2 of overvoltage protection can be used as the no-load overvoltage protection, which can be disabled after the generator is connected into the power system (controlled by the logic setting [En_CB_BlkOV2_Gen]). Figure 3.16-1 shows logic diagram of overvoltage protection.

3-48



Upp>[V_OV1_Gen]

EN

[En_VoltProt_Gen]

BI

[EBI_VoltProt_Gen]

SIG

[FD_VoltProt_Gen]

SET

[TrpLog_OV1_Gen].Bit0

EN

[En_Alm_OV2_Gen]

SET

Upp>[V_OV2_Gen]

EN

[En_VoltProt_Gen]

&

& & [t_OV1_Gen] 0s

Op_OV1_Gen

& Alm_OV_Gen &

& BI

[EBI_VoltProt_Gen]

SIG

[FD_VoltProt_Gen]

SET

[TrpLog_OV2_Gen].Bit0

SIG

Flg_Gen_UnConnect

EN

[En_CB_BlkOV2_Gen]

& [t_OV2_Gen] 0s

Op_OV2_Gen

≥1

Figure 3.16-1 Logic diagram of overvoltage protection

Where: Flg_Gen_UnConnect is the internal generated flag indicating the generator is not connected into the power system.

3.16.2 Undervoltage Protection Undervoltage protection responses to reduction of phase-to-phase voltage at the terminal of generator and will trip terminal breaker of the generator with configurable delay. There are two stages equipped with undervoltage protection: one for alarm and the other for tripping. Figure 3.16-2 shows logic diagram of undervoltage protection. EN

[En_Alm_UV_Gen]

SET

Upp<[V_UV_Gen]

EN

[En_VoltProt_Gen]

BI

[EBI_VoltProt_Gen]

SIG

[FD_VoltProt_Gen]

SET

[TrpLog_UV_Gen].Bit0

& Alm_UV_Gen &

& & [t_UV_Gen] 0s

Op_UV_Gen

Figure 3.16-2 Logic diagram of undervoltage protection


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3 Operation Theory

3.17 Over-excitation Protection Over-excitation protection is used to prevent generator from damage due to over excitation. It represents multiple of over excitation of generator. Besides, over excitation protection comprises definite-time protection and inverse-time protection. For generator, over-excitation protection calculates the voltage from generator terminal to discriminate whether it is over excitation.

3.17.1 Definite-time Over-excitation Protection Two stages are equipped for definite-time over-excitation protection, and one stage for alarm purpose and one stage for trip purpose. Their time delays can be configured. Multiple of over excitation n can be expressed as follows: n  Upu / Fpu

Where: Upu is per unit value of voltage

Fpu is per unit value of frequency

Figure 3.17-1 shows logic diagram of definite time over excitation protection. EN

[En_OvExc_Gen]

& [t_Alm_OvExc_Gen] 0s

SET

U/F>[k_Alm_OvExc_Gen]

SET

U/F>[k_OvExc1_Gen]

EN

[En_OvExc_Gen]

BI

[EBI_OvExc_GTU]

SIG

[FD_OvExc_Gen]

SET

[TrpLog_OvExc1_Gen].Bit0

Alm_OvExc_Gen

&

& [t_OvExc1_Gen] 0s

Op_OvExc_Gen

Figure 3.17-1 Logic diagram of definite-time over-excitation protection

3.17.2 Inverse-time Over-excitation Protection Inverse-time over-excitation protection realizes inverse-time characteristic by linear processing on given inverse time operation characteristic, obtaining multiple of over excitation by calculation, and getting corresponding operation delay by sectional linear insertion. It reflects heat accumulation and radiation. Figure 3.17-1 shows inverse-time operation characteristics of over-excitation protection. It can be 3-50


3 Operation Theory

specified by 8 over excitation multiple settings n0~n7. U/F n0 n1 n2 n3 n4 n5 n6 n7

t0 t1 t2 t3

t4

t5

t(s)

t6

t7

Figure 3.17-2 Inverse-time characteristics

The over excitation multiple settings n (= U/F) are within range of 1.0~1.5 in general. Maximum time delay t is considered as long as 3000s. Relation between various settings of n and t are: n0 ≥ n1 ≥ n2 ≥ n3 ≥ n4 ≥ n5 ≥ n6 ≥ n7 t0 ≤ t1 ≤ t2 ≤ t3 ≤ t4 ≤ t5 ≤ t6 ≤ t7 Figure 3.17-3 shows logic diagram of inverse-time over-excitation protection. SET

U/F>[kn_InvOvExc_Gen]

EN

[En_OvExc_Gen]

BI

[EBI_OvExc_Gen]

SIG

[FD_OvExc_Gen]

SET

[TrpLog_InvOvExc_Gen].Bit0

& IDMT

& Op_InvOvExc_Gen

Figure 3.17-3 Logic diagram of inverse-time over-excitation protection

Where: n can be 0, 1, 2, 3, 4, 5, 6 or 7.

3.18 Power Protection Power protection comprises reverse power protection, sequence tripping reverse power protection and low power protection.

3.18.1 Reverse Power Protection Reverse power protection can prevent turbine blades or gears from damage in the case that the generator transforms into a motor mode and flows reverse power due to loss of its motive force. Operation criterion of reverse power protection is P<-[P_RevP_Gen] PCS-985G Generator Relay

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3 Operation Theory

Where: P is the power calculated from three phase voltages and currents at generator terminal. [P_RevP_Gen] is the reverse power setting. Two time delay are configured for reverse power protection, one for tripping and another for alarming. The setting range of reverse power setting is 0.5%~50%Pn. (Pn is rated active power of the generator) Figure 3.18-1 shows logic diagram of reverse power protection. SET

P≤-[P_RevP_Gen]

& [t_Alm_RevP_Gen] 0s

EN

[En_PwrProt_Gen]

SET

[TrpLog_RevP_Gen].Bit0

BI

[EBI_PwrProt_Gen]

SIG

[FD_PwrProt_Gen]

Alm_RevP_Gen

& [t_Trp_RevP_Gen] 0s

Op_RevP_Gen

Figure 3.18-1 Logic diagram of reverse power protection

3.18.2 Sequence Tripping Reverse Power Protection Sometimes, when overload, over-excitation or loss-of-excitation protection of generator initiate and tripping is needed, the steam valve of turbine has to be closed firstly. Sequence tripping reverse power protection is used for this condition. Such protection is a reverse power protection blocked by position contact of steam valve and circuit breaker of generator. It can trip relevant circuit breaker with a certain delay since the steam valve being closed. Its setting range is 0.5%~10% Pn. Figure 3.18-2 shows logic diagram of sequence tripping reverse power protection. BI

[BI_52b_GCB]

BI

[BI_Valve_Turbine]

SET

P≤-[P_SeqTrpRevP_Gen]

EN

[En_PwrProt_Gen]

SET

[TrpLog_SeqTrpRevP_Gen].Bit0

&

& & [t_SeqTrpRevP_Gen] BI

[EBI_PwrProt_Gen]

SIG

[FD_PwrProt_Gen]

Op_SeqTrpRevP_Gen

Figure 3.18-2 Logic diagram of sequence tripping reverse power protection

3-52


3 Operation Theory

3.18.3 Low Power Protection One stage of low power protection is equipped for tripping. It is blocked by the binary input for emergency shutoff generator [BI_NotUrgBrake]. The setting range of low power protection is 0.5%~10% Pn. (Pn is rated active power of the generator) Figure 3.18-3 shows logic diagram of low power protection.

BI

[EBI_PwrProt_Gen

SET

[TrpLog_UP_Gen].Bit0

SIG

[FD_PwrProt_Gen]

BI

Flg_Gen_Connect

BI

[BI_NotUrgBrake]

BI

[BI_Valve_Turbine]

SET

P<[P_UP_Gen]

EN

[En_PwrProt_Gen]

EN

[En_BO_UP_Gen]

& & t_UP_Gen 0

≥1

Op_UP_Gen

& & Alm_BO_UP_Gen

Figure 3.18-3 Logic diagram of low power protection

Where: FD_PwrProt_Gen: fault detector of low power protection. Flg_Gen_Connect: internal flag indicating the generator is connected into the power system.

3.19 Frequency Protection Frequency protection of generator comprises underfrequency and overfrequency protection.

3.19.1 Underfrequency Protection When frequency is lower than setting value, underfrequency protection will operate to issue alarm or trip if the accumulated time or once duration of under frequency operation reaches time delay. This protection is blocked by position contact of circuit breaker and no current flag. Three stages of underfrequency protection are equipped for PCS-985G. Stage 1 is usually configured as accumulating frequency protection, and can be reset to zero only after erasing reports. Stage 2 and stage 3 can be configured as continuous frequency protection.

3.19.2 Overfrequency Protection As to overfrequency protection, two stages are equipped for PCS-985G and they will issue alarm or trip when operates.


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3 Operation Theory

3.19.3 Logic Scheme EN

[En_Alm_UFn_Gen]

BI

[BI_52b_CB_HVS1(2)_Tr]

SET

& t

&

0

Alm_UFn_Gen

f<[f_UFn_Gen]

EN

[En_FreqProt_Gen]

SET

[TrpLog_UF_Gen].Bit0

BI

[EBI_FreqProt_Gen]

EN

[En_Trp_UFn_Gen]

SIG

[FD_Freq_Gen]

& & t

0

Op_UFn_Gen

Figure 3.19-1 Logic diagram of underfrequency protection

Where: n can be 1, 2, or 3. EN

[En_Alm_OFn_Gen]

SET

f >[f_OFn_Gen]

& t

&

EN

[En_FreqProt_Gen]

SET

[TrpLog_OF_Gen].Bit0

BI

[EBI_FreqProt_Gen]

EN

[En_Trp_OFn_Gen]

SIG

[FD_Freq_Gen]

0

Alm_OFn_Gen

& & t

0

Op_OFn_Gen

Figure 3.19-2 Logic diagram of overfrequency protection

Where: n can be 1 or 2.

3.20 Inadvertent Energization Protection Inadvertent energization protection is also called unwanted closing protection is used for following cases: 1.

In the course of generator’s hand turning (low frequency condition), if it has not been excited, breaker closure by accident may lead to asynchronous starting of the generator. The protection is put into use automatically with time delay t1 when two groups of voltage derived from two independent VTs are all less than undervoltage setting and exit with time delay t2 (designed to cooperate with low-frequency blocking criterion) when the two groups of voltage revert to normal level.

3-54


3 Operation Theory

2.

In the case that generator breaker is closed by accident in excited condition but frequency is under normal level which may occur in startup-and-shutdown process. The protection is put into use automatically with time delay t3 while low-frequency criterion is met and returns with time delay t4 after the frequency criteria releases. Here, t4 should be set as long as to ensure the completion of tripping course.

3.

In the case that generator breaker is closed by accident in excited condition but frequency is greater than the setting which may occur in startup-and-shutdown process. The protection is put into use with time delay t3 and returns with time delay t4, which can be enabled or disabled by logic setting, and is also controlled by position contact of circuit breaker. Here, t3 should coordinate with open time of circuit breaker, and t4 should be set as long as to ensure the completion of tripping course.

Considering security of the protection, both currents from generator terminal and neutral point are used in the logic as criteria. The logic setting [Opt_AccEnerg_Gen] is used to select the logic of inadvertent energization protection, “0”, standard version “1”, special version When [Opt_AccEnerg_Gen] =0, the logic diagram of inadvertent energization protection is shown in Figure 3.20-1. SIG

Flg_UF_Gen

SIG

Flg_UV_Gen

BI

[BI_52b_GCB]

SIG

Flg_NoCurr_CB_Gen

EN

[En_CB_Ctrl_AccEnerg_Gen]

SIG

Flg_OC_Term_Gen

SIG

Flg_OC_NeuP_Gen

SIG

Flg_NoCurr_CB_Tr

EN

[En_AccEnerg_Gen]

BI

[EBI_AccEnerg_Gen]

SIG

[FD_AccEnerg_Gen]

SET

[TrpLog_AccEnerg_Gen].Bit0

& t3

t4

t1

t2

t3

t4

≥1 ≥1

&

&

& [t_AccEnerg_Gen] 0s

&

Op_AccEnerg_Gen

&

Figure 3.20-1 Logic diagram of inadvertent energization protection (standard version)

When [Opt_AccEnerg_Gen] =1, the logic diagram of inadvertent energization protection is shown in Figure 3.20-2.


3-55 Date: 2013-06-28

3 Operation Theory SIG

SIG

BI

Flg_UF_Gen

& t3

t4

t1

t2

t3

t4

≥1

Flg_UV_Gen

[BI_52b_GCB]

SIG

Flg_NoCurr_CB_Gen

EN


SIG

Flg_OC_Term_Gen

SIG

Flg_OC_NeuP_Gen

SIG

Flg_NoCurr_CB_Tr

EN

[En_AccEnerg_Gen]

BI

[EBI_AccEnerg_Gen]

SIG

[FD_AccEnerg_Gen]

SET

[TrpLog_AccEnerg_Gen].Bit0

& &

&

& [t_AccEnerg_Gen] 0s

&

Op_AccEnerg_Gen

&

Figure 3.20-2 Logic diagram of inadvertent energization protection (special version)

Where: Flg_UF_Gen is the flag indicating whether or not low frequency element of generator operates. Flg_UV_Gen is the flag indicating whether or not under voltage element of generator operates. Flg_OC_Term_Gen is the flag indicating whether or not overcurrent current element of generator terminal operates. Flg_OC_NeuP_Gen is the flag indicating whether or not overcurrent current element of generator neutral point operates.

3.21 Startup and Shutdown Protection Protections functions that can reflect phase-to-phase fault and stator earth-fault are provided during startup and shutdown process of generator. For stator earth-fault, residual overvoltage protection is provided. For phase-to-phase fault of generator, overcurrent protections of differential circuit or low-frequency overcurrent protection is provided. Since frequency during startup and shutdown process is usually very low, algorithm independent of frequency is used for this protection. Whether the protection should be blocked or not by frequency element or auxiliary contact of circuit breaker can be determined by logic setting.

3-56



F<[f_UF_StShut_Gen]

SIG

Flg_GenDiff_StShut_Gen

EN

[En_GenDiff_StShut_Gen]

EN

[En_StShut_Gen]

BI

[EBI_StShut_Gen]

t 0s

&

& SET

[TrpLog_Diff_StShut_Gen].Bit0

SIG

[FD_StShut_Gen]

SET

F<[f_UF_StShut_Gen]

SIG

Flg_StaROV_StShut_Gen

EN

[En_StaROV_StShut_Gen]

EN

[En_StShut_Gen]

BI

[EBI_StShut_Gen]

Op_GenDiff_StShut_Gen

t 0s

&

& SET

[TrpLog_StaROV_StShut_Gen].Bit0

SIG

[FD_StShut_Gen]

SET

F<[f_UF_StShut_Gen]

SIG

Flg_OC_StShut_Gen

EN

[En_GenCur_StShut_Gen]

EN

[En_StShut_Gen]

BI

[EBI_StShut_Gen]

[t_StaROV_StShut_Gen] 0s

Op_ROV_Sta_StShut_Gen

t 0s

&

& SET

[TrpLog_OC_StShut_Gen].Bit0

SIG

[FD_StShut_Gen]

[t_OC_StShut_Gen] 0s

Op_GenCur_StShut_Gen

Figure 3.21-1 Logic diagram of generator startup and shutdown protection

3.22 Overload Protection of Excitation Windings Excitation winding overload protection is equipped to reflect average heating condition of excitation winding. Excitation transformer current, exciter current or rotor current of generator can be taken as criterion of this protection. Excitation winding protection comprises definite-time and inverse-time characteristics.

3.22.1 Definite-time Excitation Winding Overload Protection Definite-time excitation winding overload protection provides one stage for alarm purpose. Figure 3.22-1 shows logic diagram of definite-time excitation winding overload protection. SET

I>[I_Alm_OvLd_RotWdg]

& [t_Alm_OvLd_RotWdg] 0s

EN

Alm_OvLd_RotWdg

[En_OvLd_Exc]

Figure 3.22-1 Logic diagram of definite time excitation winding overload protection PCS-985G Generator Relay

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3 Operation Theory

3.22.2 Inverse-time Excitation Winding Overload Protection Inverse-time excitation winding overload protection consists of three parts: low-setting initiator, inverse-time part and high setting definite-time part. Minimum operation time delay ([tmin_InvOvLd_RotWdg]) is provided for extreme overload condition. When current in excitation circuit reaches the low setting [Ib_InvOvLd_RotWdg], the heating accumulation starts. When the heating accumulation reaches its setting, alarm will be issued. The inverse time protection can simulate heating accumulation and radiation process.

Il Ilh

Ilszd

t min

tmax t

Figure 3.22-2 Operation characteristic of inverse-time excitation winding overload protection

Where:

t min is upper-limit time delay ([tmin_InvOvLd_RotWdg]). t max is lower-limit time delay. I 1szd is pickup setting ([Ib_InvOvLd_RotWdg]).

I 1h ：is the upper-limit current setting. Its operation criterion is:

[( I l I jzzd）  1]  t  KLzd 2

Where:

I l is the current in excitation circuit.

3-58


3 Operation Theory

I jzzd is inverse-time reference current of excitation circuit. KL zd is setting of heat capacity factor of excitation windings. Figure 3.22-3 shows logic diagram of inverse time excitation winding overload protection. SET

I>[I_InvOvLd_RotWdg]

EN

[En_OvLd_Exc ]

BI

[EBI_Bak_Exc]

SIG

[FD_InvOvLd_RotWdg]

SET

[TrpLog_InvOvLd_RotWdg].Bit0

IDMT

&

&

[tmin_InvOvLd_RotWdg] 0s

& Op_InvOvLd_RotWdg

Figure 3.22-3 Logic diagram of inverse-time excitation winding overload protection

3.23 Excitation Transformer /Exciter Overcurrent Protection Excitation transformer or exciter overcurrent protection includes two stages used as backup protection. These two stages will trip the circuit breaker with configurable delay. Figure 3.23-1 shows its logic diagram.

SET

I>[I_OCn_Exc]

EN

[En_Bak_Exc]

& SET

& [t_OCn_Exc] 0s

[TrpLog_OCn_Exc].Bit0

BI

[EBI_Bak_Exc]

SIG

[FD_Bak_Exc]

Op_OCn_Exc

Figure 3.23-1 Logic diagram of excitation transformer or exciter overcurrent protection

Where: n can be 1 or 2.

3.24 Breaker Failure Protection at Generator Terminal When there is an internal fault of the generator, the protection operates to trip. If the circuit at generator terminal or at HV side of main transformer fails, it needs to initiate breaker failure protection and trip adjacent circuit breaker in time. Breaker failure protection uses the current from generator terminal CT as auxiliary criterion. The current auxiliary criterion can be phase overcurrent element or negative-sequence current element. Figure 3.24-1 shows logic diagram of breaker failure protection. PCS-985G Generator Relay

3-59 Date: 2013-06-28

3 Operation Theory BI

[BI_52b_GCB]

EN

[En_CB_Ctrl_BFP_GCB]

BI

[BI_ExtTrpCtrl]

SET

I>[I_OC_BFP_GCB]

EN

[En_OC_BFP_GCB]

SET

I2>[I_NegOC_BFP_GCB]

EN

[En_NegOC_BFP_GCB]

EN

[En_BFP_GCB]

≥1

& &

≥1

BI

[EBI_BFP_GCB]

SIG

[FD_BFP_GCB]

SET

[TrpLog_BFP11_GCB].Bit0

SET

[TrpLog_BFP12_GCB].Bit0

& &

&

&

[t_BFP11_GCB] 0s

OP_BFP11_GCB

[t_BFP12_GCB] 0s

OP_BFP12_GCB

&

Figure 3.24-1 Logic diagram of breaker failure protection

3.25 CT Circuit Supervision 3.25.1 Three-phase Current Circuit Failure Alarm The operation criterion is: 3I0 > 0.04 In+ 0.25×Imax Where: 3I0 is residual current In is secondary rated current (1A or 5A). Imax is maximum phase current. If this criterion is met, CT circuit failure alarm will be issued with a time delay of 10s. Once the condition reverts normal condition, the alarm will be reset with a time delay of 10s.

3.25.2 Differential Current Alarm in Differential Protection Circuit This function is enabled only when relevant differential protection logic setting is set as enabled. If the criterion is met, the alarm will be sent by delay 0.3s and corresponding differential protection will not be blocked. When the differential current eliminates, the alarm will be reset by delay 1.2s. In order to increase sensitivity of this alarm, percentage restraint differential current alarm criterion is adopted as shown as below. dI > di_bjzd dI > kbj ×Ires If the differential current reaches its threshold and reaches differential alarm level of percentage

3-60


3 Operation Theory

restraint factor multiplied by restraint current, the differential current alarm will be issued. Where: dI is differential current. di_bjzd is threshold value of differential current alarm. kbj is percentage coefficient of differential current alarm. Ires is restrained current.

3.25.3 Alarm or Blocking to Differential Protection by CT Circuit Failure Instantaneous CT circuit failure discrimination is equipped for differential protection. Only when related logic setting and relevant enabling binary input of protection are set “1”, the alarm or blocking to instantaneous CT circuit failure discrimination will be enabled. If an internal fault occurs, at least one of following four conditions will be present: 1.

Negative-sequence voltage at any side is greater than 2V

2.

Any phase current of a certain side increases after fault detector operating

3.

Maximum phase current is greater than 1.2Ie after fault detector operating

4.

At least three-phase currents increases after fault detector picks up

If none of above four conditions occurs within 40ms after differential protection′s fault detectors picks up, the protection treats it as CT circuit failure. If the logic setting [Opt_CTS_Blk_PcntDiff_x] (x can be Gen or Exc) is set as “1”, the differential protection will be blocked and alarm will be issued. If this logic setting is set as “0”, the differential protection will trip and alarm will be issued simultaneously. If the alarm is issued, the signal can be removed only when the failure is removed and the device is reset by manual. Before the generator is connected to power grid, the blocking and alarm to CT circuit failure will be disabled automatically.

3.26 VT Circuit Supervision 3.26.1 VT Circuit of Any Side Failure Alarm The operation criterion is: 1.

Positive-sequence voltage is smaller than 18V and any phase current is greater than 0.04In

2.

Negative-sequence voltage 3U2 is in excess of 8V

If any one condition occurs, VT circuit failure alarm will be issued with a time delay of 10s, and the alarm will be removed automatically by delay 10s when the failure is removed.


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3 Operation Theory

3.26.2 Voltage Valance on Generator Terminals When two groups of VT are equipped at generator terminal, VT circuit failure can be detected by comparing phase voltage with positive sequence voltage of these two groups of VT. Operation criterions are: |UAB-Uab| >5V |UBC-Ubc| >5V |UCA-Uca| >5V |U1 - U1′| >3V Where: UAB, UBC, UCA and U1 are phase-to-phase voltage and positive sequence voltage of VT group 1. Uab, Ubc, Uca and U1′ are phase-to-phase voltage and positive sequence voltage of VT group 2. If any condition mentioned above occurs, VT circuit failure alarm will be issued with delay 0.42s and the VT group used will be switched. When only a VT fails, it will not influence the function of related protection such as loss-of-excitation, out-of-step, overvoltage, over-excitation, reverse power, frequency, impedance protection and overcurrent protection. If only one group of VT is provided at generator′s terminal, user can disable this function.

3.26.3 Three-phase Voltage Circuit Failure Supervision Operation criterions are: 1.

Positive-sequence voltage (U1) is greater than 48V

2.

Calculated third harmonic residual voltage (3U0_3ω) is greater than k*U1.

k is percentage coefficient, and takes 0.2~0.5. When the above criterions are met, corresponding alarm signal of VT circuit failure will be issued with a time delay of 20s. The alarm signal will be removed automatically with a time delay of 20s after the abnormality disappears. For VT2 and other VTs, their percentage coefficient can be settable respectively and their failure criterions are also enabled or disabled respectively.

3.27 Mechanical protection Interfaces of mechanical protection such as thermo-technical protection, interruption of water protection, excitation system protection and one spare mechanical protection are equipped for the equipment. External protection equipments send those signals to PCS-985G to make the event record and send alarm and maybe tripping command to relevant circuit breaker with delay. There are eight binary inputs provided for those protections. 3-62


3 Operation Theory

Note! The names of eight mechanical protections can be user-defined by auxiliary software.


3-63 Date: 2013-06-28

3 Operation Theory

3-64


4 Supervision

4 Supervision Table of Contents 4 Supervision ..................................................................................... 4-a 4.1 Overview .......................................................................................................... 4-1 4.2 Relay Self-supervision.................................................................................... 4-1 4.2.1 Relay Hardware Supervision ............................................................................................... 4-1 4.2.2 Binary Output Supervision ................................................................................................... 4-1 4.2.3 Binary Input Supervision...................................................................................................... 4-1 4.2.4 Setting Checking.................................................................................................................. 4-1 4.2.5 Opto-coupler Power Supervision......................................................................................... 4-2 4.2.6 Fault Detector Element Supervision .................................................................................... 4-2 4.2.7 Test Mode Supervision ........................................................................................................ 4-2 4.2.8 Hardware Configuration Supervision................................................................................... 4-2

4.3 AC Circuit Supervision ................................................................................... 4-2 4.3.1 Voltage and Current Drift Supervision and Auto-adjustment............................................... 4-2 4.3.2 Sample Supervision ............................................................................................................. 4-2

4.4 Secondary Circuit Supervision ...................................................................... 4-2 4.4.1 Current Transformer Supervision (CTS) ............................................................................. 4-2 4.4.2 Voltage Transformer Supervision (VTS) .............................................................................. 4-3

4.5 Alarm Messages .............................................................................................. 4-3

List of Tables Table 4.5-1 Self-supervision report ........................................................................................... 4-4


4-a Date: 2013-06-29

4 Supervision

4.1 Overview Protection system is in quiescent state under normal conditions, and it is required to respond promptly for faults occurred on power system. When equipment is in energizing process before the LED “HEALTHY” is on, the equipment need to be checked to ensure no abnormality. Therefore, the automatic supervision function, which checks the health of the protection system when startup and during normal operation, plays an important role. The numerical relay based on the microprocessor operations is suitable for implementing this automatic supervision function of the protection system. In case a defect is detected during initialization when DC power supply is provided to the equipment, the equipment will be blocked with indication and alarm of relay out of service. It is suggested a trial recovery of the equipment by re-energization. Please contact supplier if the equipment is still failure. When a failure is detected by the automatic supervision, it is followed by a LCD message, LED indication and alarm contact outputs. The failure alarm is also recorded in event recording report and can be printed if required.

4.2 Relay Self-supervision 4.2.1 Relay Hardware Supervision The automatic supervision function can provide monitoring of all chips on protection DSP module and fault detector DSP module to prevent any damaged or errors during the normal operation. The alarm signals [Alm_DSP_ProtBrd] or [Alm_DSP_FDBrd] will be issued if any damages or errors are detected and the device will be blocked.

4.2.2 Binary Output Supervision The state of binary outputs of each BO module is continually monitored. If any abnormality is detected, the alarm signals [Bxx.Alm_Output] will be issued with device being blocked (xx is the slot No. of corresponding BO module).

4.2.3 Binary Input Supervision The state of binary inputs detected by protection DSP module and fault detector DSP module should be the same. Otherwise, the protective device will be blocked.

4.2.4 Setting Checking This relay has 30 setting groups, while only one is active at the same time. The settings of active setting group are checked to ensure they are reasonable. If settings are checked to be unreasonable or out of setting scopes, a corresponding alarm signal will be issued, and the protective device is blocked.


4-1 Date: 2013-06-29

4 Supervision

4.2.5 Opto-coupler Power Supervision Positive power supply of opto-coupler on each BI module is continuously monitored, and if a failure or damage on the module is detected, then the alarm signal [Alm_PwrLoss_Opto1] or [Alm_PwrLoss_Opto2] will be issued.

4.2.6 Fault Detector Element Supervision If any fault detector picks up to trigger oscillography function, the corresponding binary input changing report will be recorded in “IO Events” menu with operation report [FD_Prot] being issued. When fault detector in fault detector DSP module picks up, while the fault detector in protection DSP module doesn’t pick up, or fault detectors in protection DSP and fault detector DSP module picks up continuously, equipment will issue abnormality alarm but not be blocked.

4.2.7 Test Mode Supervision When protection equipment is in test mode the alarm signal [Alm_TestMode] is issued without blocking equipment.

4.2.8 Hardware Configuration Supervision Module configuration is checked automatically during equipment initialization, if plug-in module configuration is not consistent to the design drawing of an applied-specific, the alarm signal [Fail_BoardConfig] is issued with the equipment being blocked.

4.3 AC Circuit Supervision 4.3.1 Voltage and Current Drift Supervision and Auto-adjustment The voltage and current drift are influenced by the variation of temperature or other environment factors. PCS-985 can continually and automatically trace the drift value and adjust it to normal value.

4.3.2 Sample Supervision The device can provide monitoring of AC current and voltage samplings for protection DSP module and fault detector DSP module. If the detected values are wrong or inconsistent, an alarm [Alm_Sample_DSP] will be issued and the relay will be blocked.

4.4 Secondary Circuit Supervision 4.4.1 Current Transformer Supervision (CTS) The CTS function will be always processed all the time. The CTS logic in the relay is designed to detect the CT secondary circuit to ensure that current measurement is the actual value of power system. The main purpose is to detect faults in the secondary circuits of CT and to avoid influences on corresponding protection functions. 4-2


4 Supervision

Please refer to Section 3.31 for details.

4.4.2 Voltage Transformer Supervision (VTS) The VTS function is also processed continuously. The VTS logic in the relay is designed to detect the VT secondary circuit to ensure that voltage measurement is the actual value of power system. When VT failure is detected, equipment can automatically adjust the configuration of protective elements of which the stability would be affected and might lead to mal-operation. Please refer to Section 3.32 for details.

4.5 Alarm Messages PCS-985 can provide self-supervision of hardware circuit and device operation status. When any abnormal condition is detected, the fault information or report can be displayed and a corresponding alarm will be issued. Note! If alarm signal is issued with equipment being blocked, please try to make a fault diagnosis by referring the issued alarm messages but not simply reboot or re-power the relay. If user cannot find the failure reason on site, please inform the manufacturer or the agent for maintenance. All the alarm messages and relevant LED affections are listed in following table.


4-3 Date: 2013-06-29

4 Supervision Table 4.5-1 Self-supervision report Indicator LED No.

Alarm Message HEALTHY

ALARM

CT

VT

ALARM

ALARM

Meaning Description

Repairmen suggestion

The signal is issued with other specific 1

Fail_Device

OFF

OFF

OFF

OFF

The device fails.

alarm

signals,

and

please refer to the handling suggestion other specific alarm signals. The signal is issued with other specific

2

Alm_Device

GREEN

YELLOW

OFF

OFF

The device is abnormal.

alarm

signals,

and

please refer to the handling suggestion other specific alarm signals. Step1:

check

whether

the

selected clock synchronization mode

matches

the

clock

synchronization source; Step 2: check whether the wiring connection between the 3

Alm_TimeSync

GREEN

YELLOW

OFF

OFF

Time synchronization abnormality alarm.

equipment

and

synchronization

the source

clock is

correct; Step 3: check whether the setting

for

selecting

synchronization [Opt_TimeSync])

4-4

clock (i.e.

is

set


4 Supervision Indicator LED No.


ALARM

CT

VT

ALARM

ALARM

Meaning Description


correctly. If there is no clock synchronization, please set the setting [Opt_TimeSync] as “No TimeSync”. 4

Alm_Settings_ProtBrd

OFF

YELLOW

OFF

OFF

Error is found during checking settings on

Check

the

settings,

if

the

protection DSP module.

settings are configured correctly and this alarm signal still exists,

5

6

Alm_Settings_FDBrd

Alm_PersistFD_ProtBrd

OFF

GREEN

YELLOW

YELLOW

OFF

OFF

OFF

OFF

Error is found during checking settings on fault detector DSP module.

please Inform manufacturer for maintenance.

Duration of pickup of any fault detector in protection DSP module is in excess of 10s. Check the secondary circuit and Duration of pickup of any fault detector in

7

Alm_PersistFD_FDBrd

GREEN

YELLOW

OFF

OFF

the corresponding settings.

fault detector DSP module is in excess of 10s.

8

9

10

11

Alm_InconsistFD

Alm_Sample_DSP

Alm_BI

Fail_Setting_OvRange


GREEN

OFF

GREEN

OFF

YELLOW

YELLOW

YELLOW

YELLOW

OFF

OFF

OFF

OFF

OFF

OFF

OFF

OFF

Mismatch of pickup of the same type fault

Check

the

metering

detectors between protection DSP module

protection DSP module and

and fault detector DSP module.

fault detector DSP module.

FPGA on fault detector DSP module or

Inform

protection DSP module is damaged.

maintenance.

Any one of binary input sampled by

Check the sampled binary input

protection DSP module does not match with

of protection DSP module and

that sampled by fault detector DSP module.

fault detector DSP module.

Setting value is out of setting scope.

Please

manufacturer

reset

setting

of

for

values

4-5



ALARM

CT

VT

ALARM

ALARM

Meaning Description


according

to

described

in

the the

range

instruction

manual, then re-power or reboot the equipment and the alarm message will disappear and the equipment will restore to normal operation state. Step

1:

Go

to

the

menu

“Information”->”Board check

the

Info”,

abnormality

information. Step 2: For the abnormality board, if the board is not used,

12

Fail_BoardConfig

OFF

YELLOW

OFF

OFF

Mismatch between the configuration of

then remove, and if the board is

plug-in boards and the designing drawing of

used, then check whether the

a specific project

board is installed properly and work normally. After

the

abnormality

is

removed, re-power or reboot the

equipment

and

the

equipment will restore to normal operation state. 13

4-6

Alm_Version

GREEN

YELLOW

OFF

OFF

The error is found during checking the

Users may pay no attention to

version of software downloaded to the

the alarm signal in the project




ALARM

CT

VT

ALARM

ALARM

Meaning Description

device.


commissioning stage, but it is needed to download the latest package file (including correct version checksum file) provided by R&D engineer to make the alarm signal disappear. Then users get the correct software version. It is not allowed that the alarm signal is issued on the device already has been put into service. The devices having being put into service so that the alarm signal disappears.

Management procedure will upload and check the parameters and settings of each 14

Alm_Settings_MON

GREEN

YELLOW

OFF

OFF

protection plug-in module regularly, if the parameters and settings are inconsistent, the

Inform

manufacturer

for

maintenance.

alarm signal will be issued Please After configure file is updated, settings of the 15

Fail_SettingItem_Chgd

OFF

YELLOW

OFF

OFF

file and settings saved on the device are not matched.

mentioned

in

the

settings

the

prompt

message on the LCD, and go to the menu “Settings” and select “Confirm confirm


check

Settings” settings.

item

Then,

to the

4-7



ALARM

CT

VT

ALARM

ALARM

Meaning Description


device will restore to normal operation stage. Please check the value of setting [Active_Grp] and binary input of indicating active group, and make them matched. Then 16

Alm_BI_SettingGrp

GREEN

YELLOW

OFF

OFF

The active group set by settings in device

the

“ALARM”

and that set by binary input are not matched

extinguished

LED

will

and

be the

corresponding alarm message will

disappear

and

the

equipment will restore to normal operation state Loss of low voltage power supply of the 17

Alm_PwrLoss_Opto1

GREEN

YELLOW

OFF

OFF

optical couplers for binary inputs of the BI module

Check if the power circuit of BI module is connected correctly

Loss of high voltage power supply of the 18

Alm_PwrLoss_Opto2

GREEN

YELLOW

OFF

OFF

with DC module.

optical couplers for binary inputs of the BI module

19

Alm_Insuf_Memory

GREEN

YELLOW

OFF

OFF

20

Alm_DSP_FDBrd

OFF

YELLOW

OFF

OFF

21

Alm_DSP_ProtBrd

OFF

YELLOW

OFF

OFF

4-8

Alarm indicating the memory is insufficient DSP chip on fault detector DSP module is

Put the protective device out of

damaged.

service at once. Inform the

DSP chip on protection DSP module is

factory or agency to maintain it.

damaged.




ALARM

CT

VT

ALARM

ALARM

Meaning Description


HTM bus communication of protection DSP 22

Alm_InnerComm

OFF

YELLOW

OFF

OFF

module or fault detector DSP module is abnormal. Driving transistors of binary output module

23

Bx_Alm_Output

OFF

YELLOW

OFF

OFF

located in slot No.x are damaged or DSP module is damaged

24

Alm_PwrLoss_FPGA1

OFF

YELLOW

OFF

OFF

FPGA1 power supply is abnormal

25

Alm_PwrLoss_FPGA2

OFF

YELLOW

OFF

OFF

FPGA2 power supply is abnormal

26

Alm_PwrLoss_ADC1

OFF

YELLOW

OFF

OFF

ADC1 power supply is abnormal

27

Alm_PwrLoss_ADC2

OFF

YELLOW

OFF

OFF

ADC2 power supply is abnormal

28

Alm_SwOv_VTS1_Gen

GREEN

YELLOW

OFF

YELLOW

29

Alm_SwOv_VTS2_Gen

GREEN

YELLOW

OFF

YELLOW

Alarm indicating VT1 circuit failure and start to switch over voltage circuit. Alarm indicating VT2 circuit failure and start to switch over voltage circuit. Alarm indicating VT1 circuit failure and

30

Alm_BlkV3rdHDiff_VTS1

GREEN

YELLOW

OFF

YELLOW

31

Alm_BlkIntTurn_VTS2

GREEN

YELLOW

OFF

YELLOW

32

Alm_BlkIntTurn_VTS1

GREEN

YELLOW

OFF

YELLOW

33

Alm_VTS_HVS_Tr

GREEN

YELLOW

OFF

YELLOW


blocking third harmonics voltage differential

Check the metering and VT

protection.

secondary circuit.

Alarm indicating VT2 circuit failure and blocking inter-turn protection. Alarm indicating VT1 circuit failure and blocking inter-turn protection. Alarm indicating secondary circuit failure of

4-9



ALARM

CT

VT

ALARM

ALARM

Meaning Description


VT at HV side of main transformer. 34

Alm_VTS_Term_Gen

GREEN

YELLOW

OFF

YELLOW

35

Alm_VTS_NP_Gen

GREEN

YELLOW

OFF

YELLOW

36

Alm_DeltVTS1_Term_Gen

GREEN

YELLOW

OFF

YELLOW

37

Alm_DeltVTS2_Term_Gen

GREEN

YELLOW

OFF

YELLOW

38

Alm_Pos_GCB

GREEN

YELLOW

OFF

OFF

39

Alm_VTS_LossExc_RotWdg

GREEN

YELLOW

OFF

OFF

40

Alm_DPFC_IntTurn_Gen

GREEN

YELLOW

OFF

OFF

41

Alm_IntTurn2_Gen

GREEN

YELLOW

OFF

OFF

42

Alm_Diff_Gen

GREEN

YELLOW

OFF

OFF

43

Alm_Diff_Exc

GREEN

YELLOW

OFF

OFF

44

Alm_MR1

GREEN

YELLOW

OFF

OFF

4-10

Alarm indicating secondary circuit failure of VT at generator terminal. Alarm indicating secondary circuit failure of VT at the neutral point of generator. Alarm indicating secondary circuit failure at open-delta side of VT1 at generator terminal. Alarm indicating secondary circuit failure at open-delta side of VT2 at generator terminal. Alarm indicating the position of circuit

Check the corresponding binary

breaker at generator terminal is abnormal.

input.

Alarm indicating rotor voltage circuit failure


which used by loss-of-excitation protection.

secondary circuit.

Alarm indicating operation of DPFC interturn protective element.

Treat

Alarm indicating operation of alarm stage of

application requirement.

according

to

specific

calculated longitudinal residual voltage Alarm

indicating

differential

current

of

generator is abnormal. Alarm

indicating

differential

Check current

of

the

metering

and

secondary circuit.

excitation transformer or exciter is abnormal. Alarm indicating operation of mechanical

Treat

according

to

specific




ALARM

CT

VT

ALARM

ALARM

Meaning Description


repeater 1. 45

Alm_MR2

GREEN

YELLOW

OFF

OFF

46

Alm_MR3

GREEN

YELLOW

OFF

OFF

47

Alm_MR4

GREEN

YELLOW

OFF

OFF

48

Alm_PwrLoss_MechRly

GREEN

YELLOW

OFF

OFF

Alarm indicating operation of mechanical repeater 2. Alarm indicating operation of mechanical repeater 3. Alarm indicating operation of mechanical repeater 4. Alarm indicating power loss of mechanical

Provide the power supply for

relay.

mechanical relay.

Alarm 49

Alm_On_2PEF_RotWdg

GREEN

YELLOW

OFF

OFF


indicating

2

points

earth

fault

protection has been put into operation after operation of 1 point earth fault protection of rotor. Alarm indicating operation of sensitive stage

50

Alm_Sens1PEF_RotWdg

GREEN

YELLOW

OFF

OFF

of 1 point earth fault protective element of rotor.

51

Alm_1PEF_RotWdg

GREEN

YELLOW

OFF

OFF

52

Alm_LossExc_Gen

GREEN

YELLOW

OFF

OFF

53

Alm_OvExc_Gen

GREEN

YELLOW

OFF

OFF

54

Alm_OvLd_Sta

GREEN

YELLOW

OFF

OFF


Treat

Alarm indicating operation of normal stage of

according

to

specific


1 point earth fault protective element of rotor. Alarm

indicating

operation

of

loss-of-excitation protective element. Alarm indicating operation of over excitation protective element. Alarm

indicating

operation

of

overload

4-11



ALARM

CT

VT

ALARM

ALARM

Meaning Description


element of stator. 55

Alm_NegOC_Gen

GREEN

YELLOW

OFF

OFF

56

Alm_OvLd_RotWdg

GREEN

YELLOW

OFF

OFF

57

Alm_ROV_Sta

GREEN

YELLOW

OFF

OFF

58

Alm_V3rdHRatio_Sta

GREEN

YELLOW

OFF

OFF

Alarm

indicating

operation

of

negative

overcurrent protective element of generator. Alarm

indicating

operation

of

overload

protective element of rotor winding. Alarm

indicating

operation

of

residual

overvoltage protection of stator. Alarm indicating operation of 3rd harmonics ratio earth fault protective element of stator. Alarm indicating operation of 3rd harmonics

59

Alm_V3rdHDiff_Sta

GREEN

YELLOW

OFF

OFF

differential earth fault protective element of stator.

60

Alm_InjEF_Sta

GREEN

YELLOW

OFF

OFF

61

Alm_Inj_Circuit

GREEN

YELLOW

OFF

OFF

Stator earth fault alarm (judged by stator earth-fault protection with voltage injection) Alarm indicating external injection circuit for stator earth-fault protection is abnormal Alarm indicating operation of stage 1 of

62

Alm_UF1_Gen

GREEN

YELLOW

OFF

OFF

under

frequency

protective

element

of

generator. Alarm indicating operation of stage 2 of 63

Alm_UF2_Gen

GREEN

YELLOW

OFF

OFF

under

frequency

protective

element

of

generator. 64 4-12

Alm_UF3_Gen

GREEN

YELLOW

OFF

OFF

Alarm indicating operation of stage 3 of PCS-985G Generator Relay



ALARM

CT

VT

ALARM

ALARM

Meaning Description

under

frequency

protective


element

of

generator. 65

Alm_OF1_Gen

GREEN

YELLOW

OFF

OFF

66

Alm_OF2_Gen

GREEN

YELLOW

OFF

OFF

67

Alm_OV_Gen

GREEN

YELLOW

OFF

OFF

68

Alm_UV_Gen

69

Alm_RevP_Gen

GREEN

YELLOW

OFF

OFF

70

Alm_BO_UP_Gen

GREEN

YELLOW

OFF

OFF

Alarm indicating operation of stage 1 of over frequency protective element of generator. Alarm indicating operation of stage 2 of over frequency protective element of generator. Alarm indicating overvoltage of generator

Alarm indicating operation of reverse power protection. Alarm indicating generator under power alarming contact will close. Alarm indicating out-of-step of system occurs

71

Alm_Ext_OOS_Gen

GREEN

YELLOW

OFF

OFF

while the oscillation center is outside the protected zone. Alarm indicating out-of-step of system occurs

72

Alm_Int_OOS_Gen

GREEN

YELLOW

OFF

OFF

and the oscillation center is inside the protected zone.

73

Alm_Accel_OOS_Gen

GREEN

YELLOW

OFF

OFF

74

Alm_Decel_OOS_Gen

GREEN

YELLOW

OFF

OFF


Alarm

indicating

accelerate

out-of-step

indicating

decelerate

out-of-step

occurs. Alarm occurs.

4-13



ALARM

CT

VT

ALARM

ALARM

Meaning Description

Alarm 75

Alm_NeuVTS_TermVT1

GREEN

YELLOW

OFF

YELLOW

indicating

secondary


circuit

abnormality of VT1 at the neutral point of generator terminal. Alarm

76

Alm_NeuVTS_TermVT2

GREEN

YELLOW

OFF

YELLOW

indicating

secondary

circuit

abnormality of VT2 at the neutral point of generator terminal. Alarm

77

Alm_NeuVTS_HVS_Tr

GREEN

YELLOW

OFF

YELLOW

indicating

secondary

Check the metering and VT secondary circuit.

circuit

abnormality of VT at the neutral point of HV side of transformer. Alarm indicating secondary circuit failure of

78

Alm_CTS_Diff_Gen

GREEN

YELLOW

YELLOW

OFF

CT

used

in

differential

protection

of

generator. Alarm indicating secondary circuit failure of 79

Alm_CTS_Diff_Exc

GREEN

YELLOW

YELLOW

OFF

CT used in differential protection of excitation transformer or exciter. Disable the link and check the

80

Alm_CTS_Term_Gen

GREEN

YELLOW

YELLOW

OFF

Alarm

Alm_CTS_NP_Gen

GREEN

YELLOW

YELLOW

OFF

secondary

circuit

abnormality of CT at generator terminal. Alarm

81

indicating

indicating

secondary

secondary circuit. After clear the error, reset the relay.

circuit

abnormality of CT at the neutral point of generator. Alarm

82

Alm_CTS_Bak_Gen

GREEN

YELLOW

YELLOW

OFF

indicating

secondary

circuit

abnormality of CT at generator terminal for backup overcurrent protection.

4-14




ALARM

CT

VT

ALARM

ALARM

Meaning Description


No special treatment is needed. 83

Alm_TestMode

GREEN

YELLOW

OFF

OFF

The device is in the binary output test mode.

Just wait the completion of communication test or binary output test., or exit the test.

84

Alm_dU_Inject

GREEN

YELLOW

OFF

OFF

85

Alm_VTS_RotWdg

GREEN

YELLOW

OFF

YELLOW


Alarm indicating the external DC power

Check the external DC power

supply abnormity of the rotor.

supply.

Alarm indicating voltage circuit failure of rotor


winding.

secondary circuit.

4-15

4 Supervision

4-16


5 Management

5 Management Table of Contents 5 Management.................................................................................... 5-a 5.1 Overview .......................................................................................................... 5-1 5.2 Measurement ................................................................................................... 5-1 5.2.1 Measurement of Generator Protection ................................................................................ 5-1 5.2.2 Measurement of Excitation Transformer or Exciter Protection............................................ 5-4 5.2.3 Phase Angle Measurement ................................................................................................. 5-4

5.3 Status Signaling .............................................................................................. 5-5 5.4 Event and Fault Recorder ............................................................................... 5-9 5.4.1 Introduction .......................................................................................................................... 5-9 5.4.2 Event & Fault Records......................................................................................................... 5-9 5.4.3 Type of Event ....................................................................................................................... 5-9 5.4.4 State Change of Binary Inputs ............................................................................................. 5-9 5.4.5 Relay Alarm Signals ............................................................................................................ 5-9 5.4.6 Fault Detector Elements ...................................................................................................... 5-9 5.4.7 Protection Element ............................................................................................................ 5-10

5.5 Disturbance Record ...................................................................................... 5-13

List of Tables Table 5.2-1 Current values in generator protection ................................................................. 5-1 Table 5.2-2 Voltages values in generator protection ............................................................... 5-2 Table 5.2-3 Misc measured values in generator protection .................................................... 5-3 Table 5.2-4 Current values in excitation transformer or exciter protection .......................... 5-4 Table 5.2-5 Phase angles of generator ...................................................................................... 5-4 Table 5.2-6 Phase angle of excitation transformer or exciter ................................................. 5-5 Table 5.3-1 Enabling binary inputs of generator ...................................................................... 5-6 Table 5.3-2 Enabling binary inputs of excitation transformer or exciter protection ............ 5-6 PCS-985G Generator Relay

5-a Date: 2013-07-09

5 Management

Table 5.3-3 Binary inputs of mechanical protection ................................................................ 5-6 Table 5.3-4 Miscellaneous binary inputs................................................................................... 5-7 Table 5.3-5 Power supervision binary inputs ........................................................................... 5-7 Table 5.3-6 Fault detector flag generated internal by PROT ................................................... 5-7 Table 5.4-1 List of fault detector elements.............................................................................. 5-10 Table 5.4-2 List of the protection elements ............................................................................ 5-11

5-b


5 Management

5.1 Overview The relay also provides some auxiliary functions, such as on-line data metering, binary input status, event and disturbance recording, etc. All these make the relay meet the demands of the modern power grid requirements.

5.2 Measurement The equipment performs continuous measurement of the analogue input quantities. The measurement data shown below is displayed on the LCD of the relay front panel or on the local or remote PC. Equipment samples 24 points per cycle. Calculate the RMS value in each interval and LCD will be updated every 0.5 second. The following system quantities are displayed in RMS values of the secondary side of CT and VT. NOTE: Ie and In mentioned in following sections are units. Ie is secondary rated current of main transformer or generator, and In is secondary rated current of CT NOTE: The quantities listed in following tables are to be displayed on LCD for the device, but for a certain application, some of these quantities may be eliminated due of the scheme user required, so please look up the devices on site for actual quantities displayed. The quantities listed in following sections are to be displayed on LCD for PCS-985G, but for a certain application, some of these quantities may be eliminated due of the scheme user required, so please look up the devices on site for actual quantities displayed.

5.2.1 Measurement of Generator Protection Table 5.2-1 Current values in generator protection No.

Item

Description

Unit

1

Ida_Diff_Gen

Ie

2

Idb_Diff_Gen

3

Idc_Diff_Gen

Ie

4

Ia_Term_Gen

A

5

Ib_Term_Gen

6

Ic_Term_Gen

A

7

Ia_NP_Gen

A

8

Ib_NP_Gen

9

Ic_NP_Gen

10

I1_NP_Gen

Phase A, B and C of per unit value of generator differential current.

Phase A, B and C of generator terminal current

Phase A, B and C generator neutral point current

Ie

A

A A

Positive sequence current at generator terminal.


A

5-1 Date: 2013-07-09

5 Management No.

Item

Description

Unit

11

I2_NP_Gen

Negative sequence current at generator terminal.

A

12

I0_NP_Gen

Residual current at generator terminal.

A

13

Ia_Bak_Gen

14

Ib_Bak_Gen

15

Ic_Bak_Gen

16

I1_Bak_Gen

Positive sequence current of generator backup protection

A

17

I2_Bak_Gen

Negative sequence current of generator backup protection

A

18

I0_Bak_Gen

Residual current of generator backup protection

A

19

Id_TrvDiff_Gen

Transverse differential current of generator inter-turn protection

A

Path

A Phase A, B and C of current of generator backup protection

A A

Measurements-> Measurement1-> Gen Values1-> Gen Diff Values1 Measurements-> Measurements2-> Gen Values2-> Gen Diff Values2 Table 5.2-2 Voltages values in generator protection

No. 1

Item

Description

Unit

Ua_VT1_Term

V Phase A, B and C of voltage derived from VT1 at the generator

2

Ub_VT1_Term

3

Uc_VT1_Term

4

U1_VT1_Term

Calculated positive sequence voltage of VT1.

V

5

U2_VT1_Term

Calculated negative sequence voltage of VT1.

V

6

U0_VT1_Term

Calculated residual voltage of VT1.

V

terminal.

V V

rd

7

U0Cal_3rdH_VT1_Term

8

Ua_VT2_Term

9

Ub_VT2_Term

10

Uc_VT2_Term

11

U1_VT2_Term

Calculated positive sequence voltage of VT2

V

12

U2_VT2_Term

Calculated negative sequence voltage of VT2

V

13

U0_VT2_Term

Calculated residual voltage of VT2

V

14

U0Cal_3rdH_VT2_Term

15

Uab_VT1_Term

16

Ubc_VT1_Term

17

Uca_VT1_Term

18

Uab_VT2_Term

19

Ubc_VT2_Term

20

Uca_VT2_Term

21

U0_DeltVT1_Term

Calculated 3 harmonics of VT1 at the generator terminal. Phase A, B and C of voltage derived from VT2 at the generator terminal.

V V V V

rd

Calculated 3 harmonics of VT2 at the generator terminal. Voltage between phase A and phase B of VT1 at the generator terminal Voltage between phase B and phase C of VT1 at the generator terminal Voltage between phase C and phase A of VT1 at the generator terminal Voltage between phase A and phase B of VT2 at the generator terminal Voltage between phase B and phase C of VT2 at the generator terminal Voltage between phase C and phase A of VT2 at the generator terminal Residual voltage derived from open-delta side of VT1 at the generator terminal.

5-2

V V

V

V

V

V

V

V


5 Management No.

Item

Description Residual voltage derived from VT at the neutral point of

22

U0_NP_Gen

23

U0_3rdH_VT1_Term

24

U0_3rdH_NP_Gen

25

k_V3rdHRatio_Sta

generator.

Ud_3rdH_Sta

27

U0_Longl_Gen

rd

harmonics derived from open-delta side of VT1 at the

generator terminal. 3

rd

harmonics derived from open-delta side of VT at the neutral

point of generator. rd

3 harmonic voltage percentage of stator earth-fault protection. 3

26

rd

harmonics differential voltage between the terminal and the

neutral point of generator.

28

U0_3rdH_Longl_Gen

29

U02_Longl_Gen

Path

3

Longitudinal residual voltage of generator rd

3 harmonic of longitudinal residual voltage of generator Calculated residual voltage in longitudinal residual voltage protection of generator

Unit V

V

V / V V V V

Measurements-> Measurement1-> Gen Values1-> Gen Volt Values1 Measurements-> Measurements2-> Gen Values2-> Gen Volt Values2 Table 5.2-3 Misc measured values in generator protection

No.

Item

Description

Unit

1

P_Gen

Active power of generator.

%

2

Q_Gen

Reactive power of generator.

%

3

Accu_InvOvLd_Sta

Accumulation of thermal due to overload of stator.

%

4

Accu_InvNegOC_Gen

5

U/F_OvExc_Gen

Calculated ratio of per unit values of voltage and frequency.

/

6

Accu_InvOvExc_Gen

Accumulation of thermal due to over excitation of generator.

%

7

f_Gen

Real time calculated frequency of generator.

Hz

8

Accu_UF1_Gen

9

Accu_UF2_Gen

Accumulation of thermal due to negative sequence current through stator result from interaction between rotor and stator.

Accumulation of under frequency condition time of generator to decide operation of state 1 of under frequency protection. Accumulation of under frequency condition time of generator to decide operation of state 2 of under frequency protection. Negative sequence voltage of 2nd harmonics voltage of stator

%

Min

min

10

U2_2ndH_VT1_Gen

11

U_RotWdg

Voltage of positive pole of rotor to negative pole.

V

12

U+_RotWdg

Voltage of positive pole of rotor to ground.

V

13

U-_RotWdg

Voltage of negative pole of rotor to ground.

V

14

Rg_RotWdg

Calculated grounded resistance of rotor.

kΩ

15

Loc_RotWdgEF

Location of earth fault of rotor winding of generator.

%

16

Ig1_RotWdg

Leakage current 1 of rotor

A

17

Ig2_RotWdg

Leakage current 2 of rotor

A

18

U_Injector

Injected voltage of generator rotor

V

19

Accu_InvOvLd_RotWdg

Accumulation of thermal of rotor winding.

%

20

U0_Inj_Sta

Residual voltage of stator earth-fault protection.

V

derived from VT1.


V

5-3 Date: 2013-07-09

5 Management No.

Item

Description

Unit

21

I0_Inj_Sta

Residual current of stator earth-fault protection.

A

22

U20_Inj_Sta

20Hz voltage injected

V

23

I20_Inj_Sta

20Hz current injected

A

24

Angle_Inj_Sta

25

CorrAngle_Inj_Sta

26

RSec_Inj_Sta

Measured secondary resistance

Ω

27

XSec_Inj_Sta

Measured secondary reactance

Ω

28

RCom_Inj_Sta

Corrected resistance

Ω

29

RPri_Inj_Sta

Measured primary reactance

kΩ

Path

Injected 20Hz phase angle between same-phase voltage and current Corrected injected 20Hz phase angle between same-phase voltage and current

°

°

Measurements-> Measurement1-> Gen Values1-> Gen Misc Values1 Measurements-> Measurements2-> Gen Values2-> Gen Misc Values2

5.2.2 Measurement of Excitation Transformer or Exciter Protection Table 5.2-4 Current values in excitation transformer or exciter protection No.

Item

1

Ida_Diff_Exc

2

Idb_Diff_Exc

3

Idc_Diff_Exc

4

Icorra_S1_Exc

5

Icorrb_S1_Exc

6

Icorrc_S1_Exc

7

Icorra_S2_Exc

8

Icorrb_S2_Exc

9

Icorrc_S2_Exc

10

Unit

Phase A, B and C of differential current of excitation transformer or exciter.

Ib_S1_Exc

12

Ic_S1_Exc

13

Ia_S2_Exc

14

Ib_S2_Exc

15

Ic_S2_Exc

In In In In

Phase A, B and C of corrected current on the high voltage side of excitation transformer or terminal side of exciter (Side 1).

In In In

Phase A, B and C of corrected current on the low voltage side of excitation transformer or neutral point side of exciter (Side 2).

In In

Ia_S1_Exc

11

Path

Description

A Phase A, B and C of current on the high voltage side of excitation transformer or terminal side of exciter (Side 1).

A A A

Phase A, B and C of current on the low voltage side of excitation transformer or neutral point side of exciter (Side 2).

A A

Measurements-> Measurement1-> Exc Values1 Measurements-> Measurements2-> Exc Values2

5.2.3 Phase Angle Measurement Table 5.2-5 Phase angles of generator No.

Item

1

ANGa_Term&NP_Gen

2

ANGb_Term&NP_Gen

3

ANGc_Term&NP_Gen

Description

Unit

Phase angle between same-phase currents at generator terminal and generator’s neutral point

° ° °

5-4


5 Management No.

Item

4

ANGiab_Term_Gen

5

ANGibc_Term_Gen

6

ANGica_Term_Gen

7

ANGiab_NP_Gen

8

ANGibc_NP_Gen

9

ANGica_NP_Gen

10

Description Phase - Phase angle between phase A and B, B and C, C and A of current derived from CT at generator terminal.

ANGvbc_VT1_Term_Gen

12

ANGvca_VT1_Term_Gen

13

ANGvab_VT2_Term_Gen

14

ANGvbc_VT2_Term_Gen

15

ANGvca_VT2_Term_Gen

16

ANGva_VT1&VT2_Gen

17

ANGvb_VT1&VT2_Gen

18

ANGvc_VT1&VT2_Gen

19

ANG_V3rdH_Gen

20

ANGvia_Term_Gen

° ° ° °

Phase - Phase angle between phase A and B, B and C, C and A of current derived from CT at generator neutral point.

° °

ANGvab_VT1_Term_Gen

11

Unit

° Phase angle between phase A and B, B and C, C and A of voltage derived from VT1 at generator terminal.

° ° °

Phase angle between phase A and B, B and C, C and A of voltage derived from VT2 at generator terminal.

° ° °

Phase angle between same-phase voltages derived from VT1 and VT2 at generator terminal.

° °

rd

Phase angle of 3 harmonics voltage at generator neutral point.

° °

Phase angle between same-phase voltage and current of

21

ANGvib_Term_Gen

22

ANGvic_Term_Gen

Path

Measurements-> Measurements2-> Phase Angle Measurements2-> Gen PhaseAngle Values

generator terminal.

° °

Table 5.2-6 Phase angle of excitation transformer or exciter No.

Item

1

ANGia_S1&S2_Exc

2

ANGib_S1&S2_Exc

3

ANGic_S1&S2_Exc

4

ANGiab_S1_Exc

5

ANGibc_S1_Exc

6

ANGica_S1_Exc

7

ANGiab_S2_Exc

8

ANGibc_S2_Exc

9

ANGica_S2_Exc

Path

Description Phase angle between same-phase current at HV side and LV side of excitation transformer or exciter.

Phase angle between phase A and B, B and C, C and A of current at HV side of excitation transformer or exciter.

Unit ° ° ° ° ° ° °

Phase angle between phase A and B, B and C, C and A of current at LV side of excitation transformer or exciter.

° °

Measurements-> Measurements2-> Phase Angle Measurements2-> Exc PhaseAngle Values

5.3 Status Signaling All these signals can be displayed on LCD, locally printed or sent to automation system of substation via communication channel.


5-5 Date: 2013-07-09

5 Management Table 5.3-1 Enabling binary inputs of generator No.

Item

Description

1

EBI_Diff_Gen

Enabling binary input of differential protection of generator.

2

EBI_IntTurn_Gen

Enabling binary input of inter-turn protection of generator.

3

EBI_PPF_Gen

Enabling binary input of phase-to-phase backup protection of generator.

4

EBI_ROV_Sta

Enabling binary input of residual overvoltage protection of stator.

5

EBI_V3rdH_Sta

Enabling binary input of third harmonic voltage protection

6

EBI_InjEF_Gen

Enabling binary input of earth fault protection of generator (with injection).

7

EBI_EF_RotWdg

Enabling binary input of earth fault protection of rotor.

8

EBI_OvLd_Sta

Enabling binary input of overload protection of stator.

9

EBI_NegOC_Gen

Enabling binary input of negative overcurrent protection of stator.

10

EBI_LossExc_Gen

Enabling binary input of loss-of-excitation protection of generator.

11

EBI_OOS_Gen

Enabling binary input of out-of-step protection of generator.

12

EBI_VoltProt_Gen

13

EBI_OvExc_Gen

14

EBI_PwrProt_Gen

15

EBI_FreqProt_Gen

16

EBI_AccEnerg_Gen

Enabling binary input of accidental energization protection of generator.

17

EBI_StShut_Gen

Enabling binary input of startup and shutdown protection of generator.

18

EBI_BFP_GCB

Enabling binary input of breaker failure protection of generator

Path

Status-> Prot BI-> Gen Prot BI

Enabling binary input of over-voltage and under-voltage protection of generator. Enabling binary input

of over-excitation protection of

generator-

transformer unit. Enabling binary input of power protection of generator. Enabling binary input of over-frequency and under-frequency protection of generator.

Table 5.3-2 Enabling binary inputs of excitation transformer or exciter protection No.

Item

1

EBI_Diff_Exc

2

EBI_Bak_Exc

Path

Description Enabling binary input of differential protection of excitation transformer or exciter. Enabling binary input of backup protection of excitation transformer or exciter.

Status-> Prot BI-> Exc Prot BI Table 5.3-3 Binary inputs of mechanical protection

No.

Item

1

EBI_Trp_MRx

2

BI_MRx

Path

Description Enabling binary input of mechanical protection to allow mechanical repeater x to initial tripping. (x=1~8) Binary input indicating operation of mechanical repeater. (x=1~8)

Status-> Prot BI-> MR Prot BI

5-6


5 Management Table 5.3-4 Miscellaneous binary inputs No.

Item

Description Binary input of auxiliary contact of close position of circuit breaker at

1

BI_52b_GCB

2

BI_52b_CB_HVS1_Tr

3

BI_52b_CB_HVS2_Tr

4

BI_Valve_Turbine

5

BI_1PEF_RotWdg

6

BI_PD_CB

Binary input of pole disagreement of circuit breaker.

7

BI_ExtTrpCtrl

Binary input of operation of external protection

8

BI_NotUrgBrake

Binary input of braking blocking (non urgent situation) function

Path

generator terminal. Binary input of auxiliary contact of close position of circuit breaker at branch 1 of HV side of transformer. Binary input of auxiliary contact of close position of circuit breaker at branch 2 of HV side of transformer. Binary input of auxilary contact of close position of valve of turbine. Binary input indicating that rotor one point earth fault protection of the other set of generator-transformer unit protection operates to issue alarm signal

Status-> Prot BI-> Misc BI Table 5.3-5 Power supervision binary inputs

No.

Item

Description Binary input indicating the status of power supply for optical isolators on

1

BI_Pwr_Opto_B04

2

BI_Pwr_Superv_B05

3

BI_Pwr_Opto_B05

4

BI_Print

Binary input used to initiate printer

5

BI_GPS

Binary input used for synchronization time from GPS

6

BI_RstTarg

Binary input of signal reset

7

BI_Maintenance

Binary input used to device maintenance

Path

board 04 Binary input indicating binary input circuits on board 05 are working in good condition. Binary input indicating the status of power supply for optical isolators on board 05

Status-> Prot BI-> Pwr Superv BI Table 5.3-6 Fault detector flag generated internal by PROT

No.

Item

Description

1

St_PcntDiffProt_Gen

Percentage current differential protection of generator starts

2

St_DPFCDiffProt_Gen

DPFC percentage differential protection of generator starts

3

St_TrvDiff_Gen

Transverse differential protection stage 1 of generator starts

4

St_ROV_Longl_Gen

Stage 1 of longitudinal residual voltage protection starts

5

St_DPFC_IntTurn_Gen

DPFC inter-turn fault protection of generator starts.

6

St_ROV_Longl2_Gen

Stage 2 of longitudinal residual voltage protection starts

7

St_OC1Prot_Gen

Overcurrent protection stage 1 of generator starts

8

St_OC2Prot_Gen

Overcurrent protection stage 2 of generator starts

9

St_Z1Prot_Gen

Distance protection stage 1 of generator.

10

St_Z2Prot_Gen

Distance protection stage 2 of generator starts

11

St_ROVProt_Sta

Stator residual overvoltage protection starts


5-7 Date: 2013-07-09

5 Management No.

Item

Description

12

St_V3rdHRatio_Sta

Stator third harmonic voltage ratio protection of step-transformer starts

13

St_InjR_Sta

Earthling resistance element of stator earth-fault protection starts

14

St_InjI0_Sta

Earthling current element of stator earth-fault protection starts

15

St_1PEF_RotWdg

Rotor one-point earth-fault protection starts

16

St_2PEF_RotWdg

Rotor two-points earth-fault protection starts

17

St_OvLd_Sta

Definite-time overload protection starts

18

St_InvOvLd_Sta

Stator inverse-time overload protection starts

19

St_NegOC_Sta

Stator definite-time negative-sequence overload protection starts

20

St_InvNegOC_Sta

Stator inverse-time negative-sequence overload protection starts

21

St_LossExc1_Gen

Loss-of-excitation protection stage 1 of generator starts

22

St_LossExc2_Gen


23

St_LossExc3_Gen


24

St_Ext_OOS_Gen

Out-of-step case outside the generator starts

25

St_Int_OOS_Gen

In out-of-step case inside the generator starts

26

St_OV1_Gen

Overvoltage protection stage 1 of generator starts

27

St_OV2_Gen

Overvoltage protection stage 2 of generator starts

28

St_UV_Gen

Under voltage protection of generator starts

29

St_OvExc1_Gen

Definite time over excitation protection stage1 of generator starts

30

St_OvExc2_Gen

Inverse-time over-excitation protection of generator starts

31

St_RevP_Gen

Reverse power protection of generator starts

32

St_UP_Gen

Under power protection of generator starts

33

St_UF1_Gen

Low-frequency protection stage 1 of generator starts

34

St_UF2_Gen


35

St_UF3_Gen


36

St_OF1_Gen

Over-frequency protection stage 1 of generator starts

37

St_OF2_Gen

Over-frequency protection stage 2 of generator starts

38

St_GenDiff_StShut_Gen

Differential current element of generator startup/shutdown protection starts

39

St_StaROV_StShut_Gen

Residual element of generator startup/shutdown protection starts

40

St_OC_StShut_Gen

41

St_AccEnerg_Gen

Generator inadvertent energization protection starts

42

St_BFP_GCB_Prot

Breaker failure protection starts

43

St_DiffProt_Exc

Differential protection of exciter/excitation transformer starts

44

St_OC1_Exc

Overcurrent protection stage 1 of exciter/excitation transformer starts

45

St_OC2_Exc

Overcurrent protection stage 2 of exciter/excitation transformer starts

46

St_InvOvLd_RotWdg

Inverse-time overload protection of exciter/excitation transformer starts

47

St_MR1

Mechanical protection 1 of excitation transformer starts

48

St_MR2


49

St_MR3


50

St_MR4


51

St_MR5


52

St_MR6


Low-frequency current element of generator startup/shutdown protection starts

5-8


5 Management No.

Item

Description

53

St_MR7


54

St_MR8


Path

Status-> Outputs-> Prot FD

5.4 Event and Fault Recorder 5.4.1 Introduction The PCS-985G is equipped with integral measurements, event, fault and disturbance recording facilities suitable for analysis of complex system disturbances. The relay is flexible enough to allow for the programming of these facilities to specific user application requirements and is discussed below.

5.4.2 Event & Fault Records The relay records and time tags up to 32 events and stores them in non-volatile (battery backed up) memory. This enables the system operator to establish the sequence of events that occurred within the relay following a particular power system condition, switching sequence etc. When the available space is exhausted, the oldest event is automatically overwritten by the new one. The real time clock within the relay provides the time tag to each event, to a resolution of 1ms. The event records are available for viewing either via the front plate LCD or remotely, via the communications ports (courier and MODBUS versions only). Local viewing on the LCD is achieved in the menu column entitled “REPORT”. This column allows viewing of event and fault records and is shown by setting sequence No. of the event or fault report by user. Refer to Section 8 for details of operation method.

5.4.3 Type of Event An event may be a change of state of a control input or output relay, an alarm condition and operation reports of protection etc.

5.4.4 State Change of Binary Inputs If one or more of the opto inputs has changed state since the last time that the protection algorithm ran, the new status is logged as an event. Please see Section 5.3 for details about the binary input signals.

5.4.5 Relay Alarm Signals Any alarm signal generated by the relays will also be logged as individual events. Please see Section 4.4 for details about the alarm signals.

5.4.6 Fault Detector Elements The signal of fault detector indicates one protection element (or several protection elements) picks


5-9 Date: 2013-07-09

5 Management

up to trig disturbance and fault recording with 500ms delay for dropping off. The following table is the list of the fault detector elements, please see Chapter 3 for detailed message. Table 5.4-1 List of fault detector elements No.

Item

Description Internally generated binary input indicating alarm triggering disturbance

1

AlmTrigDFR

2

FD_Diff_Gen

Fault detector of differential protection of generator picks up.

3

FD_Freq_Gen

Fault detector of frequency protection of generator picks up.

4

FD_IntTurn_Gen

Fault detector of generator inter-turn protection picks up.

5

FD_NegOC_Gen

6

FD_OOS_Gen

Fault detector of out-of-step protection of generator picks up.

7

FD_OvExc_Gen

Fault detector of generator overexcitation protection picks up.

8

FD_PPF_Gen

Fault detector of phase-to-phase fault protection of generator picks up.

9

FD_PwrProt_Gen

Fault detector of power protection of generator picks up.

10

FD_VoltProt_Gen

Fault detector of voltage protection of generator picks up.

11

FD_LossExc_Gen

Fault detector of loss-of-excitation protection of generator picks up.

12

FD_MechRly

Fault detector of mechanical protection of excitation transformer picks up.

13

FD_EF_RotWdg

Fault detector of earth fault protection of rotor picks up.

14

FD_InvOvLd_RotWdg

Fault detector of inverse-time overload protection of rotor picks up.

15

FD_SPDiff2_Gen

Fault detector of incomplete differential protection 2 of generator picks up.

16

FD_StaEF_Gen

Fault detector of stator earth-fault protection of generator picks up

17

FD_InjStaEF_Gen

Fault detector of stator earth-fault protection with voltage injection picks up

18

FD_StaOvLd_Gen

Fault detector of stator overload protection of generator picks up.

19

FD_StShut_Gen

Fault detector of startup and shutdown protection of generator picks up.

20

FD_AccEnerg_Gen

Fault detector of accidental energization protection of generator picks up.

21

FD_Bak_Exc

Fault detector of backup protection of excitation transformer picks up.

22

FD_Diff_Exc

Fault detector of differential protection of excitation transformer picks up.

23

FD_BFP_GCB

Fault detector of breaker failure protection picks up.

fault recorder

Fault detector of generator negative-sequence overcurrent protection picks up.

5.4.7 Protection Element Any operation of protection elements, (either a pickup or a trip condition) will be logged as an event record, consisting of a text string indicating the operated element and an event sequence number. Again, this number is intended not only for use by the event extraction software, such as PCSPC, but also for the user. All the protection element operation reports are listed as below. Please see Chapter 3 for details about these operation reports.

5-10


5 Management Table 5.4-2 List of the protection elements No.

Item

Description

1

FD_Prot

The fault detector element.

2

Op_InstDiff_Gen

Operation of instantaneous unrestraint differential protection of generator

3

Op_PcntDiff_Gen

Operation of percentage differential protection of generator

4

Op_DPFC_Diff_Gen

5

Op_SensTrvDiff_Gen

6

Op_InsensTrvDiff_Gen

7

Op_SensIntTurn_Gen

8

Op_InsensIntTurn_Gen

9

Op_DPFC_IntTurn_Gen

10

Op_SensIntTurn2_Gen

11

Op_OC1_Gen

Operation of stage 1 of overcurrent protection of generator

12

Op_OC2_Gen

Operation of stage 2 of overcurrent protection of generator

13

Op_Z1_Gen

Operation of stage 1 of distance protection of generator

14

Op_Z2_Gen

Operation of stage 2 of distance protection of generator

15

Op_SensROV_Sta

16

Op_InsensROV_Sta

17

Op_V3rdHRatio_Sta

18

Op_InjEF_Sta

19

Op_InjI0_Sta

20

Op_1PEF_RotWdg

Operation of 1 point earth fault protection of rotor

21

Op_2PEF_RotWdg

Operation of 2 point earth fault protection of rotor

22

Op_OvLd_Sta

Operation of definitive time overload protection of stator

23

Op_InvOvLd_Sta

Operation of inverse time overload protection of stator

24

Op_NegOC_Gen

Operation of negative sequence overcurrent protection of rotor

25

Op_InvNegOC_Gen

26

Op_LossExc1_Gen

Operation of stage 1 of loss-of-excitation protection of generator

27

Op_LossExc2_Gen


28

Op_LossExc3_Gen


29

Op_Ext_OOS_Gen

Operation of out-of-step protection outside zone of generator

30

Op_Int_OOS_Gen

Operation of out-of-step protection inside zone of generator

Operation of DPFC (Deviation of Power Frequency Component) differential protection of generator Operation of high sensitive transverse differential protection of generator Operation of high-setting stage of transverse differential protection of generator Operation of high sensitive longitudinal residual overvoltage protection of generator. Operation of high-setting stage of longitudinal residual overvoltage protection of generator. Operation of DPFC (Deviation of Power Frequency Component) of inter-turn protection of generator Operation of calculated longitudinal residual overvoltage protection of generator

Operation of sensitive stage residual overvoltage element of earth fault protection of stator Operation of insensitive stage residual overvoltage element of earth fault protection of stator rd

Operation of 3 harmonics ratio earth fault protection of stator Operation of stator earth-fault protection with injected according to earthing resistance criterion Operation of stator earth-fault protection with injected according to earthing current criterion

Operation of inverse time negative sequence overcurrent protection of rotor


5-11 Date: 2013-07-09

5 Management 31

Op_OV1_Gen

Operation of stage 1 of overvoltage protection of generator

32

Op_OV2_Gen

Operation of stage 2 of overvoltage protection of generator

33

Op_UV_Gen

Operation of under voltage protection of generator

34

Op_OvExc_Gen

Operation of definitive time over-excitation protection of generator

35

Op_InvOvExc_Gen

Operation of inverse time over-excitation protection of generator

36

Op_RevP_Gen

Operation of reverse power protection of generator

37

Op_SeqTrpRevP_Gen

38

Op_UP_Gen

Operation of low power protection of generator

39

Op_UF1_Gen

Operation of stage 1 of under-frequency protection of generator

40

Op_UF2_Gen


41

Op_UF3_Gen


42

Op_OF1_Gen

Operation of stage 1 of over-frequency protection of generator

43

Op_OF2_Gen

Operation of stage 2 of over-frequency protection of generator

44

Op_GenDiff_StShut_Gen

45

Op_ StaROV _StShut_Gen

46

Op_GenCur_StShut_Gen

47

Op_AccEnerg_Gen

Operation of accidental energization protection of generator

48

Op_BFP11_GCB

Operation of stage 1 breaker failure protection at generator terminal

49

Op_BFP12_GCB

Operation of stage 2 breaker failure protection at generator terminal

50

Op_InstDiff_Exc

51

Op_PcntDiff_Exc

52

Op_OC1_Exc

53

Op_OC2_Exc

54

Op_InvOvLd_RotWdg

Operation of inverse time overload protection of rotor winding

55

Op_MR1

Operation of repeater of external mechanical input 1

56

Op_MR2


57

Op_MR3


58

Op_MR4


59

Op_MR5


60

Op_MR6


61

Op_MR7


62

Op_MR8


63

TrpOutp5

Operation of the tripping output 5

64

TrpOutp6


65

TrpOutp7


Operation of sequence tripping with reverse power controlled protection of generator

Operation of differential current element of generator during startup and shutoff process Operation of stator residual overvoltage element of generator during startup and shutoff process Operation of under-frequency overcurrent element of generator during startup and shutoff process

Operation of instantaneous differential protection of excitation transformer or exciter Operation of percentage differential protection of excitation transformer or exciter Operation of stage 1 of overcurrent protection of excitation transformer or exciter Operation of stage 2 of overcurrent protection of excitation transformer or exciter

5-12


5 Management 66

TrpOutp8


67

TrpOutp9


68

TrpOutp10


69

TrpOutp11


70

TrpOutp12


71

TrpOutp13


72

TrpOutp14


73

TrpOutp15


74

TrpOutp16


75

TrpOutp17


76

TrpOutp18


77

TrpOutp19


78

TrpOutp20


79

TrpOutp21


80

TrpOutp22


81

TrpOutp23


82

TrpOutp24


83

TrpOutp25


84

TrpOutp26


85

TrpOutp27


86

TrpOutp28


87

TrpOutp29


5.5 Disturbance Record The integral disturbance recorder has an area of memory specifically set aside for record storage. The number of records that may be stored by the relay is dependent upon the selected recording duration. The recorder of CPU board can typically store a minimum of 32 records, among them 8 records with instantaneous waveform. The record is composed of tripping element, faulty phase, operation time and the waveform content is composed of differential currents, corrected current of each side of generator or transformer, three-phase current of each side, residual current of each side (if available), three-phase voltages, residual voltage of each side, negative sequence voltage and tripping pulse. The MON board can store up to 4 seconds (24 sampling points per cycle) or 8 seconds (12 sampling points per cycle) continual waveform, which including all channels analog quantities (sampled data, differential currents and so on), all the binary input changing state, binary output, pick up flags of fault detectors, alarm signals, operation signals and tripping signals. Disturbance records continue to be recorded until the available memory is exhausted, at which time the oldest record(s) are overwritten to make space for the newest one. It is not possible to view the disturbance records locally via the LCD; they must be extracted using suitable software such as PCS-PC. The CPU board can also record latest 8 cycles of waveform in normal operation condition, which is PCS-985G Generator Relay

5-13 Date: 2013-07-09

5 Management

composed of three phases current, corrected current of each side for differential protection, three phases voltage and residual voltage of each side. This function can help user to check the pole’s correctness of secondary circuit by comparing the phase of related quantities shown in wave figure.

5-14


6 Hardware

6 Hardware Table of Contents 6 Hardware ......................................................................................... 6-a 6.1 Overview .......................................................................................................... 6-1 6.1.1 CT Requirement .................................................................................................................. 6-4

6.2 Plug-in Module Terminal Definition ............................................................... 6-5 6.2.1 PWR Plug-in Module (Power Supply) ................................................................................. 6-5 6.2.2 MON Plug-in Module (Monitor) ............................................................................................ 6-7 6.2.3 DSP Module 1 (Protection Calculation) ............................................................................... 6-9 6.2.4 DSP Module 2 (Fault Detector) ......................................................................................... 6-10 6.2.5 BI Module (Binary Input) .................................................................................................... 6-10 6.2.6 BO Module (Binary Output) ............................................................................................... 6-13 6.2.7 AI Module (Analog Input) ................................................................................................... 6-19

List of Figures Figure 6.1-1 Hardware diagram.................................................................................................. 6-1 Figure 6.1-2 Front view of PCS-985 (only for reference) ......................................................... 6-3 Figure 6.1-3 Typical rear view of PCS-985 (only for reference) .............................................. 6-3 Figure 6.2-1 View of PWR plug-in module ................................................................................ 6-6 Figure 6.2-2 Output contacts of PWR plug-in module............................................................. 6-6 Figure 6.2-3 View of MON plug-in module ................................................................................ 6-8 Figure 6.2-4 Connection of communication terminal .............................................................. 6-9 Figure 6.2-5 Rear view of DSP module.................................................................................... 6-10 Figure 6.2-6 Terminal definition of NR1502D.......................................................................... 6-11 Figure 6.2-7 Terminal definition of NR1505A.......................................................................... 6-11 Figure 6.2-8 Terminal definition of NR1533A/B ...................................................................... 6-12 Figure 6.2-9 Trip output contact without latching.................................................................. 6-18 Figure 6.2-10 Trip output contact with latching ..................................................................... 6-19 PCS-985G Generator Relay

6-a Date: 2013-06-29

6.1 verview

6 Hardware

Figure 6.2-11 AC current and voltage ...................................................................................... 6-20 Figure 6.2-12 Pin definition of the AI module ......................................................................... 6-21

List of Tables Table 6.1-1 PCS-985 module configuration .............................................................................. 6-2 Table 6.2-1 Terminal definition and description ....................................................................... 6-6 Table 6.2-2 Alarm signals.......................................................................................................... 6-13 Table 6.2-3 Trip signals ............................................................................................................. 6-14 Table 6.2-4 Trip signals ............................................................................................................. 6-15 Table 6.2-5 Abnormality signals............................................................................................... 6-16 Table 6.2-6 Alarm signals.......................................................................................................... 6-17

6-b


6 Hardware

A/D

Protection Calculation DSP

A/D

Fault Detector DSP

Output Relay

Conventional CT/VT

External Binary Input

6.1 Overview

ECVT Pickup Relay

ECVT ETHERNET LCD Uaux

Power Supply

+E GPS

LED

CPU RJ45

Keypad PRINT

Figure 6.1-1 Hardware diagram

PCS-985 adopts 32-bit microchip processor CPU as control core for logic calculation and management function, meanwhile, adopts high-speed digital signal processor DSP to be in charge of all the protection calculation. 24 points are sampled in every cycle and parallel processing of sampled data can be realized in each sampling interval to ensure ultra-high reliability and safety of protection equipment. The working process of the device is as follows: firstly, the current and voltage is converted into small voltage signal and sent to DSP module after being filtered and converted by AD for protection calculation and fault detector respectively. When DSP module completes all the protection calculation, the result will be sent to 32-bit CPU on MON module to be recorded. Protection calculation DSP module carries out protection logic calculation, tripping output, and MON module completes SOE (sequence of event) record, waveform recording, printing, communication between protection and SAS and communication between HMI and CPU. The work process of fault detector DSP module is similar to that of protection DSP module, and the only difference is, when fault detector DSP module decides a fault detector picks up, only positive power supply of output relay is switched on. PCS-985 is comprised of intelligent modules, except that few particular modules’ position cannot be changed in the whole device (PWR module and DSP module), the others like AI (analog input) module such as AC current, AC voltage and etc., and BI/BO module such as binary input, tripping output, signal output, and etc can be flexibly configured according to the remained slot positions.


6-1 Date: 2013-06-29

6.1 verview

6 Hardware Table 6.1-1 PCS-985 module configuration No.

Module description

1

Management module (MON module)

2

Protection calculation module (DSP module 1)

3

Fault detector calculation module (DSP module 2)

4

Analog input module ( AI module )

5

Binary input module (BI module)

6

Tripping output module (BO trip module )

7

Signal output module (BO signal module )

8

Power supply module (PWR module)

9

Human machine interface module (HMI module)



MON module provides functions like management function, completed event record, setting management, etc.



DSP modules are totally the same, to carry out filtering, sampling and protection calculation and fault detector calculation respectively.



AI module converts AC current and voltage to low voltage signals with current transformers

and voltage transformers respectively. 

BI module provides binary input, and the binary is inputted via 24V, 48V, 110V/125V, or 220V/250V opto-coupler (configurable).



BO trip module provides all tripping outputs.



BO signal module provides all kinds of signal output contact, including annunciation signal, remote signal, fault and disturbance signal, operation abnormal signal, etc.



PWR module converts DC 250/220/125/110V into different DC voltage levels for various modules of the equipment



HMI module is comprised of LCD, keypad, LED indicator and test serial ports, and it is convenient for user to perform human-machine interaction with equipment.

Following figures show front and rear views of PCS-985 respectively. Programmable LED indicators (No.8-No.20) can be defined by user through PCS-PC software.

6-2


6 Hardware

1

PCS-985

11 HEALTHY

2

12

GENERATOR RELAY

ALARM

3

13 TRIP

14

GR P

4 VT ALARM

5

15 CT ALARM

6

16

ENT

ES

C

STA EF ALARM

7

17 ROT EF ALARM

8

18

9

19

10

20

Figure 6.1-2 Front view of PCS-985 (only for reference) Slot No.

01

02

03

NR1101D

NR1151D

NR1151D

1

2

3

1

2

3

4

5

6

4

5

6

04

05

06

NR1502D

NR1505A

NR1533A

07

08

NR1526A NR1526A

09

10

NR1526A

NR1533A

11

12

NR1541C NR1541C

13

14

15

NR1541C

NR1541C

NR1541D

P1 NR1301A 5V

ETHERNET

BJ

BJJ BSJ

1 2

BO_COM1 BO_FAIL

3

BO_ALM

4

BO_COM2

5

BO_FAIL

6

BO_ALM

7

OPTO+

8

OPTO-

9

NR1401

NR1401

DANGER

Slot No.

16

17

NR1401

DANGER

18

19

DANGER

20

NR1526A

NR1401

21

NR1417

10

PWR+

11

PWR-

12

GND

NR1541A

NR1541A

DANGER

22

23

24

25

26

27

28

29

30

31

32

Figure 6.1-3 Typical rear view of PCS-985 (only for reference) PCS-985G Generator Relay

6-3 Date: 2013-06-29

6.1 verview

6 Hardware

6.1.1 CT Requirement -Rated primary current Ipn: According to the rated current or maximum load current of primary apparatus. -Rated continuous thermal current Icth: According to the maximum load current. -Rated short-time thermal current Ith and rated dynamic current Idyn: According to the maximum fault current. -Rated secondary current Isn -Accuracy limit factor Kalf: Ipn

Rated primary current (amps)

Icth

Rated continuous thermal current (amps)

Ith

Rated short-time thermal current (amps)

Idyn

Rated dynamic current (amps)

Isn

Rated secondary current (amps)

Kalf

Accuracy limit factor ( Kalf=Ipal/Ipn)

IPal

Rated accuracy limit primary current (amps)

Performance verification Esl > Esl′ Esl

Rated secondary limiting e.m.f (volts) Esl = kalf×Isn×(Rct+Rbn)

Kalf

Accuracy limit factor (Kalf=Ipal/Ipn)

IPal

Rated accuracy limit primary current (amps)

Ipn


Isn


Rct

Current transformer secondary winding resistance. (ohms)

Rbn Sbn

Esl′ k Ipcf

Rated resistance burden (ohms) Rbn=Sbn/Isn

2

Rated burden (VAs)

Required secondary limiting e.m.f (volts) Esl′ = k×Ipcf ×Isn×(Rct+Rb)/Ipn stability factor = 2 Protective checking factor current (amps) Same as the maximum prospective fault current

Isn


Rct

Current transformer secondary winding resistance. (ohms)

Rb

Real resistance burden (ohms) Rb=Rr+2×RL+Rc

6-4


6 Hardware Rc

Contact resistance, 0.05-0.1 ohm (ohms)

RL

Resistance of a single lead from relay to current transformer (ohms)

Rr

Impedance of relay phase current input (ohms)

Ipn


For example: 1.

Kalf=30, Isn=5A, Rct=1ohm, Sbn=60VA

Esl = kalf×Isn×(Rct+Rbn) = kalf×Isn×(Rct+ Sbn/Isn2) = 30×5×(1+60/25)=510V 2.

Ipcf=40000A, RL=0.5ohm, Rr=0.1ohm, Rc=0.1ohm, Ipn=2000A

Esl′ = 2×Ipcf×Isn×(Rct+Rb)/Ipn = 2×Ipcf ×Isn×(Rct+(Rr+2×RL+Rc))/Ipn = 2×40000×5×(1+(0.1+2×0.5+0.1))/2000=440V Thus, Esl > Esl′

6.2 Plug-in Module Terminal Definition The device consists of power supply module, MON module, DSP module, AI module, BI module, tripping output module, signal output module, input and output signal for mechanical relay. The definition and application of each module and its terminal is introduced as follows:

6.2.1 PWR Plug-in Module (Power Supply) PWR module (slot P1) is a DC/DC or AC/DC converter with electrical insulation between input and output. It has an input voltage range as described in Chapter 2 “Technical Data”. The standardized output voltages are +5V and +24V DC. The tolerances of the output voltages are continuously monitored. The +5V DC output provides power supply for all the electrical elements that need +5V DC power supply in this device. The +24V DC output provides power supply for the static relays of this device. The use of an external miniature circuit breaker is recommended. The miniature circuit breaker must be in the on position when the device is in operation and in the off position when the device is in cold reserve. A 12-pin connector is fixed on PWR module. The terminal definition of the connector is described as below.


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6 Hardware

NR1301A 5V OK

BO_ALM

ALM

BO_FAIL

1

BO_COM1

2

BO_FAIL

3

BO_ALM

4

BO_COM2

5

BO_FAIL

6

BO_ALM

7

OPTO+

8

OPTO-

9 10 PWR+ 11 PWR12 GND

Figure 6.2-1 View of PWR plug-in module

01 BO_FAIL 02 BO_ALM 03 04 BO_FAIL 05 BO_ALM 06

Figure 6.2-2 Output contacts of PWR plug-in module

Terminals′ definition and description are shown as follows: Table 6.2-1 Terminal definition and description Terminal No.

Symbol

Description

01

BO_COM1

Common terminal 1

02

BO_FAIL

Device failure output 1 (01-02, NC)

03

BO_ALM

Device abnormality alarm output 1 (01-03, NO)

04

BO_COM2

Common terminal 2

6-6


6 Hardware Terminal No.

Symbol

Description

05

BO_FAIL

Device failure output 2 (04-05, NC)

06

BO_ALM

Device abnormality alarm output 2 (04-06, NO)

07

OPTO+

Positive power supply for BI module (24V)

08

OPTO-

Negative power supply for BI module (24V)

09

Blank

Not used

10

PWR+

Positive input of power supply for the device (250/220V/125/110V)

11

PWR-

Negative input of power supply for the device (250/220V/125/110V)

12

GND

Grounded connection of the device

Note!

The standard rated voltage of PWR module is self-adaptive to 220Vdc or 110Vdc. For non-standard rated voltage power supply module please specify when place order, and check if the rated voltage of power supply module is the same as the voltage of power source before the device being put into service. PWR module provides terminal 12 and grounding screw for device grounding. Terminal 12 shall be connected to grounding screw and then connected to the earth copper bar of panel via dedicated grounding wire. Effective grounding is the most important measure for a device to prevent EMI, so effective grounding must be ensured before the device is put into service. PCS-985, like almost all electronic relays, contains electrolytic capacitors. These capacitors are well known to be subject to deterioration over time if voltage is not applied periodically. Deterioration can be avoided by powering the relays up once a year.

6.2.2 MON Plug-in Module (Monitor) MON module (slot 01) consists of high-performance built-in processor, FLASH, SRAM, SDRAM, Ethernet controller and other peripherals. Its functions include management of the complete device, human machine interface, communication and waveform recording etc. MON module uses the internal bus to receive the data from other modules of the device. It communicates with the LCD module by RS-485 bus. This module comprises 100BaseT Ethernet interfaces, RS-485 communication interfaces, PPS/IRIG-B differential time synchronization interface and RS-232 printing interface. Modules with various combinations of memory and interface are available as shown in the table below.


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NR1102M

NR1102N

NR1101D

TX ETHERNET

ETHERNET

RX TX RX ETHERNET

Figure 6.2-3 View of MON plug-in module Module ID

Interface

Terminal No.

4 RJ45 Ethernet

RS-485 NR1102M

To SCADA 01

SYN+

02

SYN-

03

SGND

UTP shield Network Cable

Twisted pair wire

05

RTS

06

TXD

07

SGND

To printer

2 RJ45 Ethernet

To SCADA


2 FO Ethernet

To SCADA

Optical fiber ST

RS-485

01

SYN+

02

SYN-

03

SGND

To clock synchronization

04

RS-232

Twisted pair wire

05

RTS

06

TXD

07

SGND

To printer

2 RJ45 Ethernet NR1101D

Physical Layer


04

RS-232

NR1102N

Usage

RS-485

01

A

02

B

03

SGND

To SCADA


To SCADA

Twisted pair wire

6-8


6 Hardware Module ID

Interface

Terminal No.

Usage

Physical Layer

04

RS-485

05

A

06

B

07

SGND

To SCADA

08

RS-485

09

SYN+

10

SYN-

11

SGND


12

RS-232

13

RTS

14

TXD

15

SGND

To printer

16

The correct connection is shown in Figure 6.2-4. Generally, the shielded cable with two pairs of twisted pairs inside shall be applied. One pair of the twisted pairs are respectively used to connect the “+” and “–” terminals of difference signal. The other pair of twisted pairs are used to connect the signal ground of the communication interface. The module reserves a free terminal for all the communication ports. The free terminal has no connection with any signal of the device, and it is used to connect the external shields of the cable when connecting multiple devices in series. The external shield of the cable shall be grounded at one of the ends only. Twisted pair wire 01

B

02

SGND

03

COM

04

Twisted pair wire SYN+

01

SYN-

02

SGND

03

Clock SYN

To the screen of other coaxial cable with single point earthing

A

04

Twisted pair wire 05

TXD

06

SGND

07

PRINT

RTS

Figure 6.2-4 Connection of communication terminal

6.2.3 DSP Module 1 (Protection Calculation) The module (slot 02) consists of high-performance digital signal processor, optical-fiber interface, 16-digit high-accuracy ADC that can perform synchronous sampling and other peripherals. The PCS-985G Generator Relay

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6 Hardware

functions of this module include analog data acquisition, calculation of protection logic and tripping output etc.

NR1151D

1

2

3

4

5

6

Figure 6.2-5 Rear view of DSP module

6.2.4 DSP Module 2 (Fault Detector) The module (slot 03) consists of high-performance digital signal processor, optical-fiber interface, 16-digit high-accuracy ADC that can perform synchronous sampling and other peripherals. The functions of this module include analog data acquisition, calculation of fault detector elements and providing positive power supply to output relay. (DSP module 1 and DSP module 2 have same hardware configuration, see Figure 6.2-5.)

6.2.5 BI Module (Binary Input) There are three kinds of BI modules available, NR1502D, NR1505A and NR1533A/B. The device provides 13 HV binary signals (220V or 110V), including 4 binary signals of mechanical protection, 8 binary signals of auxiliary contact and 1 spare binary signals. The device also provides 38 LV binary signals (24V). Four binary signals [BI_TimeSyn], [BI_Print], [BI_Pwr_Opto] and [BI_RstTarg] are fixed, they are used to time synchronization, print, device maintenance and reset signal respectively. The power supply for the device is independent with that of mechanical protection, and they are equipped with the monitoring circuit of power supply. 6-10


6 Hardware

Up to 4 BI modules (slot 04, 05, 06, 10) can be equipped with the device. They are respectively NR1502D for LV binary signal, NR1505A for both HV and LV binary signal and NR1533A/B for binary signal of mechanical protection. The terminal definition of BI module is described as below. B04

NR1502D

B04

EBI_IntTurn_Gen

BI02

02

01

BI01

EBI_Diff_Gen

EBI_V3rdH_Sta

BI04

04

03

BI03

EBI_ROV_Sta

EBI_OvLd_Sta

BI06

06

05

BI05

EBI_EF_RotWdg

EBI_LossExc_Gen

BI08

08

07

BI07

EBI_NegOC_Gen

EBI_VoltProt_Gen

BI10

10

09

BI09

EBI_OOS_Gen

EBI_PwrProt_Gen

BI12

12

11

BI11

EBI_OvExc_GTU

BI_Pwr_Opto

BI13

14

13

16

15

OPT(24V)

EBI_AccEnerg_Gen

BI15

18

17

BI14

EBI_FreqProt_Gen

EBI_PPF_Gen

BI17

20

19

BI16

EBI_StShut_Gen

EBI_Bak_Exc

BI19

22

21

BI18

EBI_Diff_Exc

EBI_Trp_MechRly1

BI21

24

23

BI20

EBI_BFP_GCB

EBI_Trp_MechRly3

BI23

26

25

BI22

EBI_Trp_MechRly2

EBI_Trp_MechRly5

BI25

28

27

BI24

EBI_Trp_MechRly4

30

29

BI26

EBI_Trp_MechRly6

Figure 6.2-6 Terminal definition of NR1502D B05

NR1505A

B05

EBI_Trp_MechRly8

BI02

02

01

BI01

EBI_Trp_MechRly7

Spare

BI04

04

03

BI03

EBI_InjStaEf_Gen

Spare

BI06

06

05

BI05

Spare

Spare

BI08

08

07

BI07

Spare

Spare

BI10

10

09

BI09

Spare

BI_TimeSyn

BI12

12

11

BI11

Spare

BI_Print

BI14

14

13

BI13

BI_RstTarg

BI_Pwr_Opto

BI16

16

15

BI15

BI_Maintenance

18

17

OPT(24V)

BI_52b_CB_HVS1_Tr

BI02

20

19

BI01

BI_52b_GCB

BI_Valve_Turbine

BI04

22

21

BI03

BI_52b_CB_HVS2_Tr

BI_PD_CB

BI06

24

23

BI05

BI_ExtTrpCtrl

BI_NotUrgBrake

BI08

26

25

BI07

BI_1PEF_RotWdg

BI_Pwr_Superv

BI10

28

27

BI09

BI_Reserved

30

29

OPT(220V)

Figure 6.2-7 Terminal definition of NR1505A


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B06

NR1533A/B

B06 RESET

Reset

BO_MR2

04

03

BI01

BI_MR1

BO_MR3

06

05

BI02

BI_MR2

BO_MR4

08

07

BI03

BI_MR3

Com

10

09

BI04

BI_MR4

BO_MR1

12

11

BO_MR1

BO_MR2

14

13

BO_MR2

BO_MR3

16

15

BO_MR3

BO_MR4

18

17

BO_MR4

Com

20

19

Com

BO_MR1

22

21

BO_MR2

24

23

BO_MR3

26

25

BO_MR4

28

27

Com

30

29

B10

V+

Pwr+ (For MR)

V-

Pwr- (For MR)

Power Supply

Event Recorder

01

Trip

Remote Signal

02

Binary Input

Local Signal

BO_MR1

NR1533A/B

B10 RESET

Reset

BO_MR6

04

03

BI01

BI_MR5

BO_MR7

06

05

BI02

BI_MR6

BO_MR8

08

07

BI03

BI_MR7

Com

10

09

BI04

BI_MR8

BO_MR5

12

11

BO_MR5

BO_MR6

14

13

BO_MR6

BO_MR7

16

15

BO_MR7

BO_MR8

18

17

BO_MR8

Com

20

19

Com

BO_MR5

22

21

BO_MR6

24

23

BO_MR7

26

25

BO_MR8

28

27

Com

30

29

V+

Pwr+ (For MR)

V-

Pwr- (For MR)

Power Supply

Event Recorder

01

Trip

Remote Signal

02

Binary Input

Local Signal

BO_MR5

Figure 6.2-8 Terminal definition of NR1533A/B

6-12


6 Hardware

Note!

NR1533A is 220V mechanical protection BI module and NR1533B is 110V mechanical protection BI module.

6.2.6 BO Module (Binary Output) 6.2.6.1 Signal Binary Output Module Seven BO modules (slot 07, 08, 09, 15, 24, 31, 32) are used to output alarm signals, trip signals and other abnormality signals. The terminal definition of BO module is described as below. NR1526A

B07 01

BO_Alm_CTS

04

03

BO_Alm_VTS

06

05

BO_Alm_RevP

08

07

BO_Alm_OvExc

10

09

Com

12

11

BO_Alm_OvLd

14

13

BO_Alm_NegOC

16

15

BO_Alm_OvLd_RotWdg

18

17

BO_Alm_EF_Sta

20

19

Com

22

21

BO_EF_RotWdg

24

23

BO_Alm_LossExc

26

25

BO_Alm_OOS

28

27

BO_Alm_Freq

30

29

Com

Alarm Signal

02

Table 6.2-2 Alarm signals No.

Alarm Signal

Description

1

BO_Alm_CTS

CT circuit failure alarm

2

BO_Alm_VTS

VT circuit failure alarm

3

BO_Alm_RevP

Reverse power alarm

4

BO_Alm_OvExc

Overexcitation alarm

5

BO_Alm_OvLd

Overload alarm

6

BO_Alm_NegOC

Negative-sequence overload alarm

7

BO_Alm_OvLd_RotWdg

Excitation overload alarm

8

BO_Alm_EF_Sta

Stator earth fault alarm

9

BO_Alm_EF_RotWdg

Rotor earth fault alarm

10

BO_Alm_LossExc

Loss-of-excitation alarm


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6 Hardware No.

Alarm Signal

Description

11

BO_Alm_OOS

Out-of-step alarm

12

BO_Alm_LowFreq

Low-frequency alarm

NR1526B

B08

NR1541A-100482

02

01

BO_Fail

#

04

03

BO_Diff_Exc

#

06

05

BO_Bak_Exc

#

08

07

BO_MechRly

10

09

Com

B32

02

01

04

03

06

05

08

07

10

09

12

11

RLY01

BO_Diff_Exc

RLY02

BO_Bak_Exc

#

11

BO_AccEnerg_Gen

14

13

BO_RevP_Gen

16

15

BO_SeqTrpRevP_Gen

18

17

20

Trip Signal

12

# RLY03

BO_MechRly

# RLY04

14

13

BO_AccEnerg_Gen

#

RLY05

16

15

BO_RevP_Gen

#

RLY06

18

17

BO_StShut_Gen

BO_StShut_Gen

#

RLY07

20

19

BO_BFP_GCB

19

Com

#

RLY08

22

21

BO_UF_Gen

22

21

BO_BFP_GCB

#

RLY09

24

23

BO_SeqTrpRevP_Gen

24

23

BO_UF_GEN

#

RLY10

26

25

SPARE

#

RLY11

28

27

SPARE

#

RLY12

30

29

SPARE

26

25

SPARE

28

27

SPARE

30

29

Trip Signal

#

# Magnetic latching output contact

Com

Table 6.2-3 Trip signals No.

Alarm Signal

Description

1

BO_Fail

Device failure output

2

BO_Diff_Exc

Excitation differential protection tripping

3

BO_Bak_Exc

Excitation backup protection tripping

4

BO_MechRly

Mechanical protection tripping

5

BO_AccEnerg_Gen

Generator inadvertent energization protection tripping

6

BO_RevP_Gen

Generator reverse power protection tripping

7

BO_SeqTrpRevP_Gen

8

BO_StShut_Gen

Generator startup and shutoff protection tripping

9

BO_BFP_GCB

Generator breaker failure protection tripping

10

BO_UF_GEN

Generator under voltage protection tripping

Generator sequential-tripping reverse power protection tripping. It also can be trip signal of forward low power protection (BO_FLP_Gen)

6-14


6 Hardware NR1526A 02

B09 01

NR1541A-100482 #

BO_Diff_Gen

B31

02

01

04

03

06

05

08

07

10

09

12

11

RLY01

BO_Diff_Gen

#

04

03

BO_EF_Sta

06

05

BO_IntTurn_Gen

08

07

BO_OvLd_Sta

10

09

Com

# RLY02

BO_EF_Sta

# # RLY03

BO_IntTurn_Gen

#

12

11

BO_VoltProt_Gen

14

13

BO_LossExc

16

15

BO_OSS_Gen

18

17

BO_NegOC_Gen

20

19

Com

22

21

RLY04

14

13

BO_OvLd_Sta

#

RLY05

16

15

BO_VolProt_Gen

#

RLY06

18

17

BO_LossExc

#

RLY07

20

19

BO_OSS_Gen

#

RLY08

22

21

BO_NegOC_Gen

BO_EF_RotWdg

#

RLY09

24

23

BO_EF_RotWdg

#

RLY10

26

25

BO_OvExc_Gen

#

RLY11

28

27

BO_FreqProt_Gen

#

RLY12

30

29

BO_PPF_Gen

24

23

BO_OvExc_Gen

26

25

BO_FreqProt_Gen

28

27

BO_PPF_Gen

30

29

Com

Trip Signal

#

# Magnetic latching output contact

Table 6.2-4 Trip signals No.

Alarm Signal

Description

1

BO_Diff_Gen

Generator differential protection tripping

2

BO_EF_Sta

Stator earth fault protection tripping

3

BO_IntTurn_Gen

Generator interturn fault protection tripping

4

BO_OvLd_Sta

Stator overload protection tripping

5

BO_VoltProt_Gen

Generator voltage protection tripping

6

BO_LossExc

Generator loss-of-excitation protection tripping

7

BO_OSS_Gen

Generator out-of-step protection tripping

8

BO_NegOC_Gen

Generator negative sequence overload protection tripping

9

BO_EF_RotWdg

Rotor earth fault protection tripping

10

BO_OvExc_Gen

Generator over excitation protection tripping

11

BO_FreqProt_Gen

Generator frequency protection tripping

12

BO_PPF_Gen

Generator phase-to-phase backup protection tripping


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6 Hardware NR1541D

B15

02

01

04

03

06

05

08

07

10

09

12

11

RLY04

14

13

RLY05

16

15

RLY06

18

17

RLY07

20

19

RLY08

22

21

RLY09

24

23

RLY10

26

25

RLY11

28

27

RLY12

30

29

RLY01

BO_Alarm

RLY02

SPARE

RLY03

SPARE

BO_Alm_OV_Gen

BO_Alm_UP_Gen

SPARE

BO_Alm_UV_Gen

Table 6.2-5 Abnormality signals No.

Alarm Signal

Description

1

BO_Alarm

Output contact of device abnormality alarm

2

BO_Alm_OV_Gen

Output contact of generator over voltage alarm

3

BO_Alm_UP_Gen

Output contact of generator low power alarm

4

BO_Alm_UV_Gen

Output contact of generator under voltage alarm

6-16


6 Hardware NR1526A

B24 01

BO_Alm_CTS

04

03

BO_Alm_VTS

06

05

BO_Alm_RevP

08

07

BO_Alm_OvExc

10

09

Com

12

11

BO_Alm_OvLd

14

13

BO_Alm_NegOC

16

15

BO_Alm_OvLd_RotWdg

18

17

BO_Alm_EF_Sta

20

19

Com

22

21

BO_EF_RotWdg

24

23

BO_Alm_LossExc

26

25

BO_Alm_OOS

28

27

BO_Alm_Freq

30

29

Com

Alarm Signal

02

Table 6.2-6 Alarm signals No.

Alarm Signal

Description

1

BO_Alm_CTS

CT circuit failure alarm

2

BO_Alm_VTS

VT circuit failure alarm

3

BO_Alm_RevP

Reverse power alarm

4

BO_Alm_OvExc

Overexcitation alarm

5

BO_Alm_OvLd

Overload alarm

6

BO_Alm_NegOC

Negative-sequence overload alarm

7

BO_Alm_OvLd_RotWdg

Excitation overload alarm

8

BO_Alm_EF_Sta

Stator earth fault alarm

9

BO_Alm_EF_RotWdg

Rotor earth fault alarm

10

BO_Alm_LossExc

Loss-of-excitation alarm

11

BO_Alm_OOS

Out-of-step alarm

12

BO_Alm_LowFreq

Low-frequency alarm

6.2.6.2 Trip Binary Output Module PCS-985B provides 4 trip binary output modules (slot 11, 12, 13, 14). And the definition of all trip output signal can be user-defined by auxiliary software. The trip output signal can be set to be broadened, and the time is settable, default value is 140ms. The instantaneous drop-off contacts can be used to initiate breaker failure protection. The terminal definition of BO module is described as below.


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6 Hardware NR1541C 02

B11

NR1541C

01

RLY01

B12

02

01

04

03

06

05

08

07

10

09

12

11

RLY01

04

03 BO_TrpOutp1

06

05

08

07

10

09

RLY02

BO_TrpOutp5 RLY02

RLY03

RLY03

12

11

RLY04

14

13

RLY04

14

13

RLY05

16

15

RLY05

16

15

RLY06

18

17

RLY06

18

17

RLY07

20

19

RLY07

20

19

BO_TrpOutp2

BO_TrpOutp6

BO_TrpOutp7

BO_TrpOutp3 RLY08

22

21

RLY08

22

21

RLY09

24

23

RLY09

24

23

RLY10

26

25

RLY10

26

25

RLY11

28

27

RLY11

28

27

RLY12

30

29

RLY12

30

29

BO_TrpOutp8

NR1541C 02

B13

NR1541C

01

RLY01

BO_TrpOutp9 04

03

06

05

RLY02

BO_TrpOutp10 08

07

10

09

RLY03

RLY04

BO_TrpOutp4

BO_TrpOutp11 12

11

14

13

B14

02

01

04

03

06

05

08

07

10

09

12

11

RLY04

14

13

BO_TrpOutp21

RLY05

16

15

BO_TrpOutp22

RLY01

BO_TrpOutp18

RLY02

BO_TrpOutp19

RLY03

BO_TrpOutp20

BO_TrpOutp12 RLY05

16

15

RLY06

18

17

BO_TrpOutp13

RLY06

18

17

BO_TrpOutp23

RLY07

20

19

BO_TrpOutp14

RLY07

20

19

BO_TrpOutp24

RLY08

22

21

BO_TrpOutp15

RLY08

22

21

BO_TrpOutp25

RLY09

24

23

BO_TrpOutp16

RLY09

24

23

BO_TrpOutp26

RLY10

26

25

RLY10

26

25

BO_TrpOutp27

RLY11

28

27

RLY11

28

27

BO_TrpOutp28

RLY12

30

29

RLY12

30

29

BO_TrpOutp29

BO_TrpOutp17

Figure 6.2-9 Trip output contact without latching

Note!

The trip output contact can be latching shown as below. # means that this contact is a magnetic-latching contact

6-18


6 Hardware NR1541A #

02

B11

NR1541A #

01

RLY01

#

04

#

03 BO_TrpOutp1

#

06

05

#

08

07

#

10

09

#

RLY02

# #

RLY03

#

12

#

11 BO_TrpOutp2

B12

02

01

04

03

06

05

08

07

10

09

12

11

RLY01 BO_TrpOutp5 RLY02

RLY03 BO_TrpOutp6

#

RLY04

14

13

#

RLY04

14

13

#

RLY05

16

15

#

RLY05

16

15

#

RLY06

18

17

#

RLY06

18

17

#

RLY07

20

19

#

RLY07

20

19

BO_TrpOutp3

#

RLY08

22

21

#

RLY08

22

21

#

RLY09

24

23

#

RLY09

24

23

#

RLY10

26

25

#

RLY10

26

25

#

RLY11

28

27

#

RLY11

28

27

#

RLY12

30

29

#

RLY12

30

29

BO_TrpOutp4

NR1541B # #

02

# #

# # #

BO_TrpOutp9 04

03

06

05 BO_TrpOutp10

08

07

10

09

RLY03

RLY04

NR1541C

01

RLY02

#

BO_TrpOutp8

B13

RLY01

BO_TrpOutp11 12

11

14

13

BO_TrpOutp7

B14

02

01

04

03

06

05

08

07

10

09

12

11

RLY04

14

13

BO_TrpOutp21

RLY05

16

15

BO_TrpOutp22

RLY01

BO_TrpOutp18

RLY02

BO_TrpOutp19

RLY03

BO_TrpOutp20

BO_TrpOutp12 RLY05

16

15

RLY06

18

17

BO_TrpOutp13

RLY06

18

17

BO_TrpOutp23

RLY07

20

19

BO_TrpOutp14

RLY07

20

19

BO_TrpOutp24

RLY08

22

21

BO_TrpOutp15

RLY08

22

21

BO_TrpOutp25

RLY09

24

23

BO_TrpOutp16

RLY09

24

23

BO_TrpOutp26

RLY10

26

25

RLY10

26

25

BO_TrpOutp27

RLY11

28

27

RLY11

28

27

BO_TrpOutp28

RLY12

30

29

RLY12

30

29

BO_TrpOutp29

BO_TrpOutp17

Figure 6.2-10 Trip output contact with latching

6.2.7 AI Module (Analog Input) PCS-985B can provide 48 analog input channels, and the terminal definition of analog current and analog voltage input is described as below.


6-19 Date: 2013-06-29

6.1 verview

6 Hardware B16

NR1401X A

Current channel 1

Current channel 2

Current channel 3

Current channel 4

01

B18

02

NR1401X

A'

B

03

04

B'

C

05

06

C'

A

07

08

A'

B

09

10

B'

C

11

12

C'

A

13

14

A'

Current channel 5

Current channel 6

Current channel 7

A

01

02

A'

B

03

04

B'

C

05

06

C'

A

07

08

A'

B

09

10

B'

C

11

12

C'

A

13

14

A'

B

15

16

B'

B

15

16

B'

C

17

18

C'

C

17

18

C'

A

19

20

A'

A

19

20

A'

B

21

22

B'

B

21

22

B'

C

23

24

C'

C

23

24

C'

Current channel 8

12I

B20

VT2 of generator terminal

VT at HV side of main transformer

Residual VT at HV side of main transformer

B22

NR1401X A

VT1 of generator terminal

12I

01

02

N

B

03

04

N

C

05

06

N

L

07

08

N

A

09

10

N

B

11

12

N

C

13

14

N

L

15

16

N

A

17

18

N

B

19

20

N

C

21

22

N

L

23

24

N

Current channel 9 (for measurement CT)

Reserved

Transverse differential current Residual current at neutral point Residual VT2 at generator neutral point Residual VT at generator neutral point

NR1401X A

01

02

A’

B

03

04

B’

C

05

06

C’

L

07

08

N

L

17

18

N

L

19

20

N

L

21

22

N

L

23

24

N

6I2U

12U

Figure 6.2-11 AC current and voltage

If stator earth-fault protection with voltage injection is used, the pin definition of the AI module will be changed as following figure.

6-20


6 Hardware Slot 30

NR1418 IR+

Slot 30

01 02

Input from DC current transmitter

IR-

NR1417

03

IR+

02

Input from DC current transmitter

IR-

04 UR2+ Rotor voltage used in loss-of-excitation protection

05 06

UR2-

UR1+

Rotor voltage used in rotor earth-fault protection with pingpang principle

07

04 Rotor voltage used by loss-of-excitation protection& rotor earth-fault protection with voltage injection

UR2+

06 UR2-

07

09

09

10

UOUT

10

11

11

12

12

13

13

15

Rotor voltage used by rotor earth-fault protection with external voltage injection principle

17

14 RGND

19

TEST

17 18

UIN+

20 21

15 16

18

UR1-

05

08

16 TEST

03

08

14 RGND

01

19 20

UIN-

22

21 22

Figure 6.2-12 Pin definition of the AI module

Note! 1.

Three-phase current channel 9 is measurement CT channel, it can be connected with the measurement CT that used for reverse power protection.

2.

Traditional rotor earth-fault protection use the voltage channel of B22_23~B22_24 (Generator neutral point residual VT1)

3.

Rotor earth-fault protection with voltage injection adopts the following 2 channels: 1) B22_19~B22_20, residual current from neutral point; 2) B22_21~B22_22, from generator neutral point residual VT2.

4.

For rotor earth-fault protection with ping-pang type, NR1418 should be selected. In NR1418, UR2+ should be connected to positive pole of rotor winding, and UR2should be connected to negative pole of rotor winding. UR2+ and UR2- are applied to acquire the rotor voltage used for loss-of-excitation protection.


6-21 Date: 2013-06-29

6.1 verview

6 Hardware

UR1+ and UR1- are applied as the inputs of big power resistor (13.6kΩ). UR1+ and UR1- should be connected to the positive/negative pole of rotor winding via the big power resistor. RGND is applied to connect the shaft of rotor winding. TEST is applied for test (the test resistor is 18kΩ). 5.

For rotor earth-fault protection with voltage injection, NR1417 should be selected. In NR1417, UR2+ should be connected to positive pole of rotor winding, and UR2should be connected to negative pole of rotor winding. UR2+ and UR2- are applied to acquire the rotor voltage for loss-of-excitation protection. UOUT is applied as the input of big power resistor (47kΩ). RGND is applied to connect the shaft of rotor winding. TEST is applied for test (the test resistor is 18kΩ). UIN+ and UIN- are applied to connect to the external power supply, can be 220V (NR1417A) or 220V (NR1417B) (predetermined when ordering).

6-22


7 Settings

7 Settings Table of Contents 7 Settings ........................................................................................... 7-a 7.1 Overview .......................................................................................................... 7-1 7.2 Device Setup ................................................................................................... 7-1 7.2.1 Communication Settings...................................................................................................... 7-1 7.2.2 Device Settings .................................................................................................................... 7-4

7.3 General Settings ............................................................................................. 7-5 7.3.1 System Settings ................................................................................................................... 7-5 7.3.2 Enable Settings.................................................................................................................... 7-5 7.3.3 Main Transformer System Settings ..................................................................................... 7-7 7.3.4 Generator System Settings ................................................................................................. 7-7 7.3.5 System Settings of Excitation Transformer or Exciter ......................................................... 7-9 7.3.6 Implicit Configuration Settings ............................................................................................. 7-9

7.4 Protection Settings ....................................................................................... 7-12 7.4.1 Settings of Differential Protection of Generator................................................................. 7-12 7.4.2 Settings of Inter-turn Fault Protection of Generator .......................................................... 7-15 7.4.3 Settings of Phase-to-phase Backup Protection of Generator ........................................... 7-17 7.4.4 Settings of Stator Earth-fault Protection ............................................................................ 7-21 7.4.5 Settings of Stator Earth-fault Protection with Voltage Injection ......................................... 7-25 7.4.6 Settings of Rotor Earth-fault Protection ............................................................................. 7-27 7.4.7 Settings of Thermal Overload Protection of Stator ............................................................ 7-29 7.4.8 Settings of Negative-sequence Overcurrent Protection .................................................... 7-31 7.4.9 Settings of Loss-of-excitation Protection ........................................................................... 7-33 7.4.10 Settings of Out-of-step Protection ................................................................................... 7-38 7.4.11 Settings of Overvoltage Protection .................................................................................. 7-41 7.4.12 Settings of Overexcitation Protection of Generator ......................................................... 7-43


7-a Date: 2013-07-04

7 Settings

7.4.13 Settings of Power Protection of Generator...................................................................... 7-44 7.4.14 Settings of Underfrequency and Overfrequency Protection ........................................... 7-46 7.4.15 Settings of Startup and Shutdown Protection of Generator ............................................ 7-47 7.4.16 Settings of Inadvertent Energization Protection of Generator ........................................ 7-49 7.4.17 Settings of Breaker Failure Protection of Generator ....................................................... 7-50 7.4.18 Settings of Differential Protection of Excitation Transformer or Exciter .......................... 7-52 7.4.19 Settings of Backup Protection of Excitation Transformer or Exciter ............................... 7-53 7.4.20 Settings of Overload Protection of Excitation Transformer or Exciter ............................. 7-54 7.4.21 Settings of Mechanical Protection ................................................................................... 7-55

7.5 Calculated Parameters ................................................................................. 7-56 7.5.1 Calculated Parameters of Secondary Rated Current........................................................ 7-56 7.5.2 Calculated Parameters of Secondary Rated Voltage ........................................................ 7-57 7.5.3 Calculated Parameters of Differential Coefficient ............................................................. 7-57

List of Tables Table 7.2-1 Communication settings ......................................................................................... 7-1 Table 7.2-2 Device settings......................................................................................................... 7-4 Table 7.3-1 List of system settings ............................................................................................ 7-5 Table 7.3-2 List of protection configuration settings .............................................................. 7-5 Table 7.3-3 List of transformer system settings ...................................................................... 7-7 Table 7.3-4 List of generator system settings .......................................................................... 7-8 Table 7.3-5 List of excitation transformer or exciter settings................................................. 7-9 Table 7.3-6 List of implicit configuration settings ................................................................. 7-10 Table 7.4-1 List of generator differential protection settings ............................................... 7-12 Table 7.4-2 List of inter-turn fault protection settings........................................................... 7-15 Table 7.4-3 List of phase-to-phase backup protection settings ........................................... 7-17 Table 7.4-4 List of stator earth fault protection settings ....................................................... 7-21 Table 7.4-5 List of stator earth-fault protection with voltage injection settings ................. 7-25 Table 7.4-6 List of earth fault protection settings of rotor .................................................... 7-27 Table 7.4-7 List of thermal overload protection settings of stator ....................................... 7-29

7-b


7 Settings

Table 7.4-8 List of negative sequence overload protection .................................................. 7-31 Table 7.4-9 List of loss-of-excitation protection .................................................................... 7-33 Table 7.4-10 List of out-of-step protection ............................................................................. 7-38 Table 7.4-11 List of overvoltage protection settings ............................................................. 7-41 Table 7.4-12 List of over excitation protection settings of generator.................................. 7-43 Table 7.4-13 List of power protection settings of generator ................................................ 7-44 Table 7.4-14 List of frequency protection settings ................................................................ 7-46 Table 7.4-15 List of startup and shutdown protection settings of generator ..................... 7-47 Table 7.4-16 List of accidental energaization protection settings of generator ................. 7-49 Table 7.4-17 List of breaker failure protection settings of generator .................................. 7-50 Table 7.4-18 List of differential protection settings of excitation transformer or exciter.. 7-52 Table 7.4-19 List of backup protection settings of excitation transformer or exciter ....... 7-53 Table 7.4-20 List of overload protection settings of exciter ................................................. 7-54 Table 7.4-21 List of mechanical protection settings .............................................................. 7-55 Table 7.5-1 List of calculated parameters of secondary rated current ................................ 7-57 Table 7.5-2 List of calculated parameters of secondary rated voltage ................................ 7-57 Table 7.5-3 List of calculated parameters of differential coefficient.................................... 7-57


7-c Date: 2013-07-04

7 Settings

7.1 Overview The device has some setting groups for protection to coordinate with the mode of power system operation, one of which is assigned to be active. However, general settings and device setup are shared by all protection setting groups, and settings of protection element are set according to secondary values.

7.2 Device Setup 7.2.1 Communication Settings 

Settings list Table 7.2-1 Communication settings

No.

Settings item

1

IP_LAN1

2

Mask_LAN1

3

IP_LAN2

4

Mask_LAN2

5

En_LAN2

6

IP_LAN3

7

Mask_LAN3

8

En_LAN3

9

IP_LAN4

Range 000.000.000.000~ 255.255.255.255 000.000.000.000~ 255.255.255.255 000.000.000.000~ 255.255.255.255 000.000.000.000~ 255.255.255.255 0/1 000.000.000.000~ 255.255.255.255 000.000.000.000~ 255.255.255.255 0/1 000.000.000.000~ 255.255.255.255 000.000.000.000~

10

Mask_LAN4

11

En_LAN4

12

Gateway

13

En_Broadcast

0/1

14

Protocol_NET

0~3

255.255.255.255 0/1 000.000.000.000~ 255.255.255.255

Description IP address of Ethernet port 1.

Subnet mask of Ethernet port 1.

IP address of Ethernet port 2.

Subnet mask of Ethernet port 2. Enable(1)/disable(0) the IP address of port 2. IP address of Ethernet port 3.

Subnet mask of Ethernet port 3. Enable(1)/disable(0) the IP address of port 3. IP address of Ethernet port 4.

Subnet mask of Ethernet port 4. Enable(1)/disable(0) the IP address of port 4. Gateway of router Enable(1)/disable(0) sending message in broadcast mode via network. (IEC103). Communication protocol of port


7-1 Date: 2013-07-04

7 Settings No.

Settings item

Range

15

Fmt_Net_103

0, 1

16

Addr_RS485A

0～255

17

Baud_RS485A

4800,9600,19200, 38400,57600,115200bps

Description Time scale format of IEC 60870-5-103 protocol (for Ethernet port). Communication address between the protective device with the SCADA or RTU via RS-485 serial port 1. Baud rate of rear RS-485 serial port 1. Communication protocol of rear RS-485 serial port 1. 0: IEC60870-5-103;

18

Protocol_RS485A 0～9

1: Modbus 2: Reserved Others: Not available Spontaneous events are sent in the format of FUN and INF

19

Inf_RS485A_103

0, 1

based on IEC 60870-5-103 protocol (for RS-485 serial port 1).

20

Fmt_RS485A_103 0, 1

21

Addr_RS485B

22

Baud_RS485B

0～255 4800,9600,19200, 38400,57600,115200bps

Time scale format of IEC 60870-5-103 protocol (for RS-485 serial port 1). Communication address between the protective device with the SCADA or RTU via RS-485 serial port 2. Baud rate of rear RS-485 serial port 2. Communication protocol of rear RS-485 serial port 2. 0: IEC60870-5-103;

23

Protocol_RS485B 0～9

1: Modbus 2: Reserved Others: Not available Spontaneous events are sent in the format of FUN and INF

24

Inf_RS485B_103

0, 1

based on IEC 60870-5-103 protocol (for RS-485 serial port 2). Time scale format of IEC 60870-5-103 protocol (for RS-485

25

Fmt_RS485B_103 0, 1

26

Baud_Printer

4800,9600,19200,38400bps

Baud rate of printer port

27

En_AutoPrint

0/1

Enable(1)/disable(0) automatic printing function

serial port 2).

Conventional 28

Opt_TimeSyn

SAS Advanced

Select the mode of time synchronization of equipment.

NoTimeSyn 29

IP_Server_SNTP

30

IED_Name

000.000.000.000~

The address of the external SNTP clock synchronization

255.255.255.255

server sending SNTP message to the equipment. IED name used in IEC61850 communication

7-2


7 Settings



Setting Explanation

1.

[En_LAN1], [En_LAN2], [En_LAN3], [En_LAN4]

Put Ethernet 1, Ethernet 2, Ethernet 3 and Ethernet 4 in service They are used for Ethernet communication based on the 103 protocol. When the IEC 61850 protocol is applied, the IP address of Ethernet A will be GOOSE source MAC address. 2.

[Opt_TimeSyn]

There are four selections for clock synchronization of device, each selection includes different time clock synchronization signals shown in following table. Item

Description PPS(RS-485): Pulse per second (PPS) via RS-485 differential level.

Conventional

IRIG-B(RS-485): IRIG-B via RS-485 differential level. PPM(DIN): Pulse per minute (PPM) via the binary input [BI_TimeSyn]. PPS(DIN): Pulse per second (PPS) via the binary input [BI_TimeSyn]. SNTP(PTP): Unicast (point to point) SNTP mode via Ethernet network.

SAS

SNTP(BC): Broadcast SNTP mode via Ethernet network. Message (IEC103): Clock messages through IEC103 protocol. IEEE1588: Clock message via IEEE1588.

Advanced

IRIG-B(Fiber): IRIG-B via optical-fibre interface. PPS(Fiber) PPS: Pulse per second (PPS) via optical-fibre interface.

NoTimeSync

When no time synchronization signal is connected to the equipment, please select this option and the alarm message [Alm_TimeSync] will not be issued anymore.

―Conventional‖ mode and ―SAS‖ mode are always be supported by device, but ―Advanced‖ mode is only supported when NET-DSP module is equipped. The alarm signal [Alm_TimeSyn] may be issued to remind user loss of time synchronization signals. 1)

When ―SAS‖ is selected, if there is no conventional clock synchronization signal, the device will not send the alarm signal [Alm_TimeSyn]. When ―Conventional‖ mode is selected, if there is no conventional clock synchronization signal, ―SAS‖mode will be enabled automatically with the alarm signal [Alm_TimeSyn] being issued simultaneously.

2)

When ―Advanced‖ mode is selected, if there is no conventional clock synchronization signal connected to NET-DSP module, ―SAS‖ mode is enabled automatically with the alarm signal [Alm_TimeSyn] being issued simultaneously.

3)

When ―NoTimeSyn‖ mode is selected, the device will not send alarm signals without Note! Above table listed all the communication settings, the device delivered to the user maybe only show some settings of them according to the communication interface configuration. If only the Ethernet ports are applied, the settings about the serial ports (port A and port B) are not listed in this submenu. In addition, the settings about the Ethernet ports only listed in this


7-3 Date: 2013-07-04

7 Settings

submenu according to the actual number of Ethernet ports. The standard arrangement of the Ethernet port is two, at most four (predetermined when ordering). Set the IP address according to actual arrangement of Ethernet numbers and the un-useful port/ports need not be configured. If the PCS-PC configuration tool auxiliary software is connected with this device through the Ethernet, the IP address of the PCS-PC must be set as one of the available IP address of this device. Note! The clock message via IEC103 protocol is invalid when the device receives the IRIG-B signal through RC-485 port. 

Access Path

Access path in menu is: MainMenuSettingsDevice SetupComm Settings

7.2.2 Device Settings 

Settings list Table 7.2-2 Device settings

No.

1

2

Setting Item

HDR_EncodeMode

Un_BinaryInput

Range

Description Select encoding format of header (HDR) file

0:GB18030

COMTRADE recording file. Default value is

1: UTF-8

―UTF-8‖.

24V, 48V, 110V, 220V

Voltage level of binary input Enable/disable moveable disk to realize the

3

En_MDisk

0, 1

backup and recovery function. Default value is 0, and the function is reserved.



Setting Explanation

1.

[HDR_EncodeMode]

The logic settings to select encoding format of header file. Default value of [HDR_EncodeMode] is 1(i.e. UTF-8 code) and please set it to 0(i.e. GB18030) according to the special requirement. 2.

[Un_BinaryInput]

This setting is used to set voltage level of binary input module. If low-voltage BI module is equipped, 24V or 48V can be set according to the actual requirement, and if high-voltage BI module is equipped, 110V or 220V can be set according to the actual requirement. 

Access Path

Access path in menu is: 7-4


7 Settings

MainMenuSettingsDevice SetupDevice Settings

7.3 General Settings 7.3.1 System Settings 

Settings List Table 7.3-1 List of system settings

No.

Setting Item

Range

Step

1

Active_Grp

1~30

1

2

Substation

Max 20 characters

3

PrimaryEquip_Name Max 20 characters

4

PrimaryEquip_ID

Setting Explanation

1.

[Active_Grp]

Current setting group. Name of the substation Name of the protected primary equipment, such as transformer, line, etc.

Max 20 characters



Description

Number of the device.

The current protection setting group number, and total 30 group settings are provided. The device settings, communication settings and system settings, are common for all protection groups. 

Access Path

Access path in menu is: Main Menu -> Settings -> General Settings -> System Settings

7.3.2 Enable Settings If any of the following settings is set as ―1‖, corresponding protection function is enabled. If any of the following settings is set as ―0‖, corresponding protection function is disabled and related setting submenu and settings will be hidden. 

Settings List Table 7.3-2 List of protection configuration settings

No.

Symbol

Range

1

En_Diff_Gen

0/1

2

En_IntTurn_Gen

0/1

3

En_PPF_Gen

0/1

4

En_EF_Sta

0/1

5

En_InjEF_Sta

0/1

Description Logic setting used to enable (1) or disable (0) differential protection of generator. Logic setting used to enable (1) or disable (0) inter-turn fault protection of generator. Logic setting used to enable (1) or disable (0) phase to phase fault protection of generator Logic setting used to enable (1) or disable (0) stator earth fault protection of generator. Logic setting used to enable (1) or disable (0) stator earth-fault


7-5 Date: 2013-07-04

7 Settings protection with voltage injection of generator. 6

En_EF_RotWdg

0/1

7

En_OvLd_Sta

0/1

8

En_NegOC_Gen

0/1

9

En_LossExc_Gen

0/1

10

En_OOS_Gen

0/1

11

En_VoltProt_Gen

0/1

12

En_OvExc_Gen

0/1

13

En_PwrProt_Gen

0/1

14

En_FreqProt_Gen

0/1

15

En_StShut_Gen

0/1

16

En_AccEnerg_Gen

0/1

17

En_BFP_GCB

0/1

18

En_Diff_Exc

0/1

19

En_Bak_Exc

0/1

20

En_OvLd_Exc

0/1

21

En_MechRly

0/1

22

En_VTComp_Term_Gen

0/1

23

En_NeuVTS_VT2

0/1

24

En_NeuVTS_OtherVT

0/1

25

En_TestMode

0/1



Setting Explanation

1.

[En_TestMode]

Logic setting used to enable (1) or disable (0) earth fault protection of rotor winding. Logic setting used to enable (1) or disable (0) overload protection of stator. Logic setting used to enable (1) or disable (0) negative sequence overcurrent protection of generator. Logic setting used to enable (1) or disable (0) loss of excitation protection of generator. Logic setting used to enable (1) or disable (0) out-of-step protection of generator. Logic setting used to enable (1) or disable (0) overvoltage and undervoltage protection of generator. Logic setting used to enable (1) or disable (0) overexcitation protection of generator. Logic setting used to enable (1) or disable (0) overpower and underpower protection of generator. Logic setting used to enable (1) or disable (0) overfrequency and underfrequency protection of generator. Logic setting used to enable (1) or disable (0) all relative protections in Startup/shutdown conditions of generator. Logic setting used to enable (1) or disable (0) relevant protection in case of accident energization of generator. Logic setting used to enable (1) or disable (0) generator terminal circuit breaker failure protection. Logic setting used to enable (1) or disable (0) differential protection of exciting transformer or exciter. Logic setting used to enable (1) or disable (0) backup protection of exciting transformer or exciter. Logic setting used to enable (1) or disable (0) overload protection of exciting transformer or exciter. Logic setting used to enable (1) or disable (0) mechanical protection. Logic setting used to enable(1) or disable(0) voltage balance function of VTs at the generator terminal. Logic setting used to enable(1) or disable(0) neutral line failure supervision of VT2 (i.e. inter-turn fault protection used VT) Logic setting used to enable(1) or disable(0) neutral line failure supervision of other VT (except for VT2). Logic setting used to enable(1) or disable(0) debugging operation through PCS-PC software.

7-6


7 Settings

This logic setting is configured for equipment debugging status. If it is set as ―1‖, debugging window can be open by PCS-PC software. Under debugging window, corresponding protection tripping signals and alarm signals can be issued, corresponding tripping contacts can be energized without actual happening of corresponding fault. If it is set as ―0‖, debugging window can not be open. 

Access Path

Access path in menu is: Main Menu -> Settings -> General Settings ->Enable Settings

7.3.3 Main Transformer System Settings 

Setting List Table 7.3-3 List of transformer system settings

No.

Symbol

Range

Step

Unit

1

U1n_HVS_Tr

0.01-2000

0.01

kV

2

U1n_VT_HVS_Tr

0.01-2000

0.01

kV

3

U2n_VT_HVS_Tr

0.01-200

0.01

V

4

U2n_DeltVT_HVS_Tr

0.01-300

0.01

V

Description System rated voltage at HV side of main transformer Rated primary voltage of VT at HV side of main transformer. Rated secondary voltage of VT at HV side of main transformer. Rated secondary voltage of open-delta of VT at HV side of main transformer. Logic setting of selecting connection mode of main

5

Opt_Conn_Tr

0/1

transformer 0: Yd connection mode 1: YYd connection mode Logic setting of circuit breaker at terminal of generator.

6

Opt_GCB

0/1

0: There is circuit breaker located at generator terminal 1: There is no circuit breaker located at generator terminal



Access Path

Access path in menu is: Main Menu -> Settings -> General Settings ->TrSys Settings

7.3.4 Generator System Settings 

Setting List


7-7 Date: 2013-07-04

7 Settings Table 7.3-4 List of generator system settings No.

Symbol

Range

Step

Unit MW

1

Pn_Gen

0.1-2000.0

0.1

2

PF_Gen

0.01-1.00

0.01

3

U1n_Gen

0.01-100.0

0.01

kV

4

U1n_VT_Term_Gen

0.01-100.0

0.01

kV

5

U2n_VT_Term_Gen

0.01-200.0

0.01

V

6

U2n_DeltVT_Term_Gen

0.01-300.0

0.01

V

7

U1n_VT_NP_Gen

0.01-100.0

0.01

kV

8

U2n_VT_NP_Gen

0.01-300.0

0.01

V

9

I1n_CT_Term_Gen

0-60000

1

A

10

I2n_CT_Term_Gen

1，5

1

A

11

I1n_CT_NP_Gen

0-60000

1

A

12

I2n_CT_NP_Gen

1，5

1

A

13

I1n_CT_TrvDiff_Gen

0-60000

1

A

14

I2n_CT_TrvDiff_Gen

1，5

1

A

15

k_U_RotWdg

0-2.000

0.001

16

Urmax_Transmitter

0-4000



Setting Explanation

1.

[k_U_RotWdg]

Description Capacity of active power of generator Rated power factor of generator. System rated voltage at the terminal of generator. Rated primary voltage of VT at the terminal of generator. Rated secondary voltage of VT at the terminal of generator. Rated secondary open-delta voltage at the terminal of generator. Rated primary voltage of VT at the neutral point of generator. Rated secondary voltage of VT at the neutral point of generator. Rated primary current of CT at the terminal of the generator. Rated secondary current of CT at the terminal of the generator. Rated primary current of CT at the neutral point of the generator. Rated secondary current of CT at the neutral point of the generator. Rated primary current of CT used for transverse differential protection. Rated

secondary

current

of

CT

used

for

transverse differential protection. Correction coefficient of rotor voltage.

V

The maximum value of transmitter input voltage

This is the correction coefficient of rotor voltage. For the occasion that partial rotor voltage is connected to the device, rotor voltage needs to be corrected by the setting. For example, if only half of rotor voltage is connected to the device, this setting should be set as ―2‖, if total rotor voltage is connected to the device, this setting should be set as ―1‖. 

Access Path

Access path in menu is: Main Menu -> Settings -> General Settings ->GenSys Settings

7-8


7 Settings

7.3.5 System Settings of Excitation Transformer or Exciter 

Setting List Table 7.3-5 List of excitation transformer or exciter settings

No.

Symbol

Range

Step

Unit

1

Sn_Exc

0-100.0

0.01

MVA

2

U1n_S1_Exc

0-100.00

0.01

kV

3

U1n_S2_Exc

0-100.00

0.01

kV

4

I1n_CT_S1_Exc

0-60000

1

A

5

I2n_CT_S1_Exc

1, 5

1

A

Description Capacity of the exciter or excitation transformer System rated voltage on HV side of the excitation transformer. System rated voltage on LV side of the excitation transformer. Primary rated current of the CT on HV side of the excitation transformer or CT at the terminal of the exciter. Secondary rated current of the CT on HV side of the excitation transformer or CT at the terminal of the exciter. Primary rated current of the CT on LV side of the

6

I1n_CT_S2_Exc

0-60000

1

A

excitation transformer or CT at the neutral point of the exciter. Secondary rated current of the CT on LV side of the

7

I2n_CT_S2_Exc

1，5

1

A

excitation transformer or CT at the neutral point of the exciter.

Logic setting ―1‖ - enable, ―0‖ – disable Logic setting of excitation system, ―0‖: the excitation transformer is used in the generator 8

Opt_Exc

0/1

system instead of exciter. ―1‖: the exciter is used in the generator system instead of excitation transformer. Logic setting of selecting the connection mode of excitation transformer. 0: Yy-12 connection mode;

9

Opt_Conn_ET

1: Dd-12 connection mode; 2: Dy-11 connection mode; 3: Yd-11 connection mode; 4: Dy-1 connection mode.



Access Path

Access path in menu is: Main Menu -> Settings -> General Settings ->ExcSys Settings

7.3.6 Implicit Configuration Settings The settings in the following list are associated with application-specific primary layout of generator and exciter, tripping logics. These settings can not be seen on LCD of equipment and only be viewed and configured on PC through PCS-PC software. These settings are usually


7-9 Date: 2013-07-04

7 Settings

configured in factory or configured by field commission engineer according to the design drawing and project requirement. 

Setting List Table 7.3-6 List of implicit configuration settings

No.

settings

Range

Description

1

Cfg_Polar_CT

0-3FF

CT polarity definition

2

Cfg_CT_Term_Gen

Current channel 0-8

3

Cfg_CT_NP_Gen

Current channel 0-8

4

Cfg_CT_Bak_Gen

Current channel 0-8

5

Cfg_CT_PwrProt_Gen

Current channel 0-9

6

Cfg_CT_S1_Exc

Current channel 0-8

7

Cfg_CT_S2_Exc

Current channel 0-8

Logic setting of selecting three-phase current channel for CT at generator terminal Logic setting of selecting residual current channel for CT at neutral point 1 of generator Logic setting of selecting three-phase backup current channel for generator Logic setting of selecting three-phase current channel of CT for power protection Logic setting of selecting three-phase current channel for CT of side 1 of excitation transformer or exciter Logic setting of selecting three-phase current channel for CT of side 2 of excitation transformer or exciter Logic setting of selecting three-phase current CT for

8

Opt_CT_PwrProt_Gen

0/1

reverse power protection of generator. ―0‖: CT of P level. ―1‖: CT of S level. Logic setting of selecting residual voltage at generator

9

Opt_3U0_Gen

0/1

terminal ―0‖: the voltage is measured residual voltage. ―1‖: the voltage is calculated residual voltage.

10

Cfg_Ext_TrpOutp

0-3FFFFFFF

11

t_Ext_TrpOutp

0-450

12

kmax_V3rdHDiff_Sta

3-6

13

t_CurrMemory

1-20s

Logic setting to configure which output relays will delay dropoff since corresponding tripping signal dropoff. DDO (delay dropoff) time of tripping output relays, its default value is 140ms. Differential current adjust coefficient for third harmonic differential current protection, 3.0 generally. Memory time of current, 10s generally. Ratio coefficient to judge whether neutral line failure of

14

K_NeuVTS_VT2

0.1-1.0

VT2 (inter-turn fault protection used VT) happens, 0.4 generally. Ratio coefficient to judge whether neutral line failure of

15

K_NeuVTS_OtherVT

0.1-1.0

16

K_dU_RotWdg

0.05-0.3

Rotor voltage fluctuation coefficient

17

k1_U0_Longl_Gen

0-3.5

Calculated longitudinal residual voltage coefficient 1

18

k2_U0_Longl_Gen

0-3.5

Calculated longitudinal residual voltage coefficient 2

other VT (except for VT2) happens, 0.2 generally.

7-10


7 Settings 19

Polar_VT_NP_Gen



Setting Explanation

1.

[Cfg_Polar_CT]

Polarity adjustment for calculated longitudinal residual

0-1

voltage

Generally, CT polarity definition is shown as the below table. However if some CT polarity direction is reversed by incorrect wiring connecting, there is still chance to correct it by configuring this logic setting easily. Please set the corresponding digit of the logic setting. Bit.1-9 are corresponding to 9 three-phase current channels one by one. If any bit is set as ―0‖, the program will reverse the current polarity of this channel before calculation.

2.

0

No definition

1

Three-phase channel 1

2


3


4


5


6


7


8



9

[Cfg_CT_Term_Gen]

Configurable setting for deciding which channel is chosen to input three-phase current for CT at generator terminal. Following table gives all the choices that user can decide. Only one bit at most can be set as ―1‖ simultaneously. 0

No definition

1


2


3


4


5


6


7


8



9

The definition of each bit of other configurable settings is the same to that of [Cfg_CT_Term_Gen]. 3.

[K_dU_RotWdg]

Rotor voltage fluctuation coefficient, it is used to adjust the permissible rotor voltage fluctuation for rotor earth-fault protection. The permissible rotor voltage fluctuation is bigger if the coefficient is bigger. Rotor earth-fault protection will be blocked if rotor voltage fluctuation is too big. 4.

[k1_U0_Longl_Gen], [k2_U0_Longl_Gen]

Calculated longitudinal residual voltage coefficient 1 and calculated longitudinal residual voltage PCS-985G Generator Relay

7-11 Date: 2013-07-04

7 Settings

coefficient 2. The two coefficients are used in calculated longitudinal residual voltage protection for compensation function. The two coefficients can be gotten by stator earth-fault testing. 5.

[Polar_VT_NP_Gen]

Polarity adjustment for calculated longitudinal residual voltage, it is only used to adjust the polarity of neutral point residual voltage in calculated longitudinal residual voltage protection, the polarity of neutral point residual voltage in stator earth-fault protection will not be affected. 

Access Path

Access path in menu is: Main Menu -> Settings -> General Settings ->Config Settings

7.4 Protection Settings 7.4.1 Settings of Differential Protection of Generator 

Settings List Table 7.4-1 List of generator differential protection settings

No.

Symbol

Range

Step

Unit

1

I_Pkp_PcntDiff_Gen

0.10–1.50

0.01

Ie

2

I_InstDiff_Gen

2.00–14.00

0.01

Ie

3

I_AlmDiff_Gen

0.05–1.00

0.01

Ie

Description Pickup setting of percentage current differential protection Current

setting

of

unrestrained

instantaneous differential protection. Differential current alarm setting of generator. Restraint coefficient setting of the first

4

Slope1_PcntDiff_Gen

0.00–0.50

0.01

slope

of

percentage

differential

protection 5

Slope2_PcntDiff_Gen

0.30–0.80

0.01

6

TrpLog_Diff_Gen

0000–3FFFFFFF

1

Maximum value of restraint coefficient of the differential characteristic curve. Tripping

output

logic

setting

of

differential protection of generator.

Logic setting ―1‖ - enable, ―0‖ – disable Logic 7

En_InstDiff_Gen

0/1

settings

of

disable(0)

or

enable(1) unrestrained instantaneous differential protection Logic

8

En_PcntDiff_Gen

0/1

settings

enable(1)

of

disable(0)

percentage

or

differential

protection Logic 9

En_DPFC_Diff_Gen

0/1

settings

enable(1)

of

DPFC

disable(0)

or

percentage

differential protection 10

Opt_CTS_Blk_PcntDiff_Gen

0/1

Logic setting of selecting whether

7-12


7 Settings percentage differential protection will be blocked during CT circuit failure. ―0‖: the protection will not be blocked during CT circuit failure. ―1‖: the protection will be blocked during CT circuit failure.



Setting Explanation

1.

[I_Pkp_PcntDiff_Gen]

This is pickup setting of percentage current differential protection, which is also the setting of fault detector of percentage differential protection. It shall be higher than maximum unbalance current when the generator operates on normal rated load, i.e.

I cdqd  Krel  2  0.03I f 2n or I cdqd  Krel  Iunb.0

Equation 7.4-1

Where:

I f 2 n is secondary rated current of generator, I f 2n 

I f 1n n fLH

Where:

I f 1n is primary rated current of generator and n fLH is ratio of generator CT. I f 1n 

Pn / cos  3U f 1n

Where:

Pn is rated capacity of generator;

cos is power factor of generator and U f 1n is rated voltage of generator terminal. K rel is reliability factor, 1.5 in general; I unb.0 is the measured actual unbalance current during rated load of generator, 0.2 I f 2 n -0.3 I f 2 n


7-13 Date: 2013-07-04

7 Settings

is recommended for reference. Where:

I cdqd represents the setting [I_Pkp_PcntDiff_Gen]. 2.

[I_InstDiff_Gen]

Setting of unrestrained instantaneous differential protection. Unrestraint instantaneous differential protection is a complementary part of differential protection. Its current setting shall be higher than maximum unbalance current due to breaker’s asynchronous closure. For large unit, it can be set as 3 or 4 times of rated current. 4 times of rated current is recommended. 3.

[I_AlmDiff_Gen]

Differential current alarm setting of generator. It shall be higher than normal unbalance differential current and lower than [I_Pkp_PcntDiff_Gen]. 4.

[Slope1_PcntDiff_Gen]

Restraint coefficient setting of the first slope of percentage differential protection, it shall be:

K bl1  K rel  K cc  K er

Equation 7.4-2

Where:

K rel is reliability coefficient which is considered to be 1.0~2.0 in general; K cc is the type factor of CT, takes 0.5; K er is error factor of CT ratio, takes 0.1.

K bl1 represents [Slope1_PcntDiff_Gen] which is set as 0.05~0.1 in general. 5.

[Slope2_PcntDiff_Gen]

Maximum value of restraint coefficient of the differential characteristic curve. With type factor of CT not taken into account, the maximum unbalance current is, ,

I unb. max  K ap  K er  I k . max

Equation 7.4-3

Where:

K ap is non periodic component factor, usually no less than 2.0; K er is error factor of CT ratio, no more than 0.1; 7-14


7 Settings

I k .max is periodic component of secondary value of external three phase short circuit current and it can be taken as 4 times of rated current if it is less than 4 times of rated current. Maximum slope of percentage differential protection is:

kbl 2 

I unb.max*  I cdqd *  2kbl1

Equation 7.4-4

I k .max*  2

Where:

I unb.max* , I cdqd * and I k .max* are all per unit value of rated current of generator; kbl 2 ([Slope2_PcntDiff_Gen] ) is taken as 0.50 generally. If the percentage differential protection is configured based on rules mentioned above, when phase-to-phase metallic short circuit fault occurs at the terminal of generator, sensitivity factor will meet requirement K sen ≥ 2 surely. 

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> GenDiffProt Settings

7.4.2 Settings of Inter-turn Fault Protection of Generator 

Setting List Table 7.4-2 List of inter-turn fault protection settings

No.

Symbol

Range

Step

Unit

1

I_SensTrvDiff_Gen

0.10 – 50.00

0.01

A

2

I_InsensTrvDiff_Gen

0.10 – 50.00

0.01

A

3

t_TrvDiff_Gen

0.00 – 10.00

0.01

S

Description Current setting of high sensitive transverse differential protection. Current

setting

of

high-setting

transverse differential protection. Delay

of

transverse

differential

protection Voltage setting of high sensitive

4

V_SensROV_Longl_Gen

1 – 10.00

0.01

V

longitudinal

residual

overvoltage

protection. Delay 5

t_ROV_Longl_Gen

0.10 – 10.00

0.01

s

of

longitudinal

residual

overvoltage. Short delay 0.10s – 0.20s is recommended for operation and output of this protection.


7-15 Date: 2013-07-04

7 Settings Tripping 6

TrpLog_IntTurn_Gen

0000–3FFFFFFF

1

output

turn-to-turn

logic

fault

setting

of

protection

of

disable(0)

or

generator. Logic setting ―1‖ - enable, ―0‖ – disable Logic 7

En_SensTrvDiff1_Gen

0/1

settings

of

enable(1) high sensitive transverse differential protection 1 of generator. Logic

8

En_InsensTrvDiff1_Gen

0/1

settings

enable(1)

of

disable(0)

high-setting

or

transverse

differential protection 1 of generator. Enable high sensitive longitudinal 9

En_SensROV_Longl_Gen

0/1

residual overvoltage protection of generator.

10

En_DPFC_IntTurn_Gen

Enable directional DPFC inter-turn

0/1

fault protection of generator. Enable alarm function of calculated

11

En_Alm_ROV2_Longl_Gen

0/1

longitudinal

residual

overvoltage

protection of generator Enable Tripping function of calculated 12

En_Trp_ROV2_Longl_Gen

0/1

longitudinal

residual

overvoltage

protection of generator



Setting Explanation

1.

[I_SensTrvDiff_Gen]

Setting of this protection shall be higher than maximum unbalance current during normal operation condition. Reliability factor can be more than 2. The setting value is usually:

I op  0.05 I f ln / na

Equation 7.4-5

Where:

I OP represents the setting [I_SensTrvDiff_Gen].

I f ln is primary rated current of generator and na is ratio of residual CT of transverse differential protection. Phase current restraint factor is a fixed coefficient in the program. 2.

[I_InsensTrvDiff_Gen]

This is the current setting of high-setting transverse differential protection. It is equivalent to traditional transverse differential protection. Setting of this protection is as follows which shall be higher than maximum unbalance current during external short circuit fault.

7-16


7 Settings

I op （0.20~0.30）I f ln / na

Equation 7.4-6

Where:

I OP represents the setting [I_SensTrvDiff_Gen].

I f ln is primary rated current of generator and n a is ratio of residual CT of transverse differential protection. 3.

[t_TrvDiff_Gen]

This is the delay of transverse differential protection (act on only after the occurrence of one-point ground of rotor). When one point earth fault occurs within rotor of generator and one point earth fault protection operates, in order to prevent unwanted operation of transverse protection due to instantaneous two points earth fault within the rotor, operation of this protection shall be delayed for 0.5 s – 1 s.

Note! When a turn-to-turn fault occurs, the equipment will trip relevant breakers without delay according to the tripping output logic setting, but a time delay decided by user will act on after occurrence of one-point ground of rotor. 

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> GenIntTurnProt Settings

7.4.3 Settings of Phase-to-phase Backup Protection of Generator 

Setting List Table 7.4-3 List of phase-to-phase backup protection settings

No. 1

Symbol V_NegOV_VCE_Gen

Range 1.00 – 20.00

Step

Unit

0.01

V

Description Negative sequence voltage setting of composite voltage control element. Setting

2

Vpp_UV_VCE_Gen

2.00 –100.00

0.01

V

of

phase-to-phase

undervoltage of composite voltage control element.

3

I_OC1_Gen

0.10 –100.00

0.01

A

4

t_OC1_Gen

0.00 – 10.00

0.01

S

5

TrpLog_OC1_Gen

00–3FFFFFFF

1


Current

setting

of

overcurrent

protection stage 1. Time delay of overcurrent protection stage 1. Tripping

output

logic

setting

of

7-17 Date: 2013-07-04

7 Settings overcurrent protection stage 1 Current 6

I_OC2_Gen

0.10 –100.00

0.01

A

setting

of

overcurrent

protection stage 2, which shall be higher

than

rated

current

of

transformer. 7

t_OC2_Gen

0.00 – 10.00

8

TrpLog_OC2_Gen

00–3FFFFFFF

9

Z1_Fwd_Gen

0.10 –100.00

0.01

S

stage2. Tripping

1

0.01

Time delay of overcurrent protection

output

logic

setting

of

overcurrent protection stage2. Ω

Positive direction impedance setting of distance protection stage1. Negative direction impedance setting of distance protection stage1. In

10

Z1_Rev_Gen

0.10 –100.00

0.01

Ω

general, this setting is set as 5-10% of the positive direction impedance setting.

11

t_Z1_Gen

0.00 – 10.00

12

TrpLog_Z1_Gen

00–3FFFFFFF

13

Z2_Fwd_Gen

0.10 –100.00

0.01

Ω

14

Z2_Rev_Gen

0.10 –100.00

0.01

Ω

15

t_Z2_Gen

0.00 – 10.00

0.01

S

16

TrpLog_Z2_Gen

00–3FFFFFFF

0.01

S

Tripping

1

1

Delay of distance protection stage1. output

logic

setting

of

distance protection stage1. Positive direction impedance setting of distance protection stage2. Negative direction impedance setting of distance protection stage2 Delay of distance protection stage2 Tripping

output

logic

setting

of

distance protection stage2.


En_VCE_Ctrl_OC1_Gen

settings

of

disable(0)

or

enable(1) controlling function to stage

0/1

1

of

overcurrent

protection

by

composite voltage element Logic 18

En_VCE_Ctrl_OC2_Gen

settings

of

disable(0)

or

enable(1) controlling function to stage

0/1

2

of

overcurrent

protection

by

composite voltage element. Logic

settings

enable(1) 19

En_HVS.VCE_Ctrl_OC_Gen

0/1

of

controlling

disable(0)

or

function

to

overcurrent protection by composite voltage

element

from

HVS

of

transformer. Logic setting of selecting protection 20

Opt_VTS_Ctrl_OC_Gen

performance during VT circuit failure.

0/1

―0‖: when VT circuit failure at one side is detected, the voltage-controlled

7-18


7 Settings overcurrent element will become a pure

overcurrent

composite

relay

voltage

without element

controlling. ―1‖: when VT circuit failure at one side is

detected,

element

will

composite be

voltage

disabled

if

corresponding logic setting is set as ―1‖. 21

En_Mem_Curr_Gen

Logic

0/1

Logic

22

settings

of

disable(0)

or

enable(1) memory function of current.

En_CB_Ctrl_OC1_Gen

settings

of

disable(0)

or

enable(1)

stage 1 of overcurrent

protection

controlled

network

connected

by

power

status

of

generator, it will be blocked if the generator is connected with the power network.



Setting Explanation

1.

[V_NegOV_VCE_Gen]

This is negative sequence voltage setting of composite voltage control element. Setting and displayed value of negative sequence voltage are U2. Setting of negative sequence voltage relay shall be higher than unbalance voltage during normal operation, generally

U op.2  (0.06--0.08 ) U n

Equation 7.4-7

Where: U n is secondary rated voltage. Sensitivity factor shall be checked by phase-to-phase short circuit fault on HV side bus of main transformer:

K sen 

U 2. min U op 2

Equation 7.4-8

Where:

U 2. min is minimum negative sequence voltage at location of the equipment during phase-to-phase short circuit fault on HV side bus of main transformer. K sen ≥ 1.5 is required. 2.

[Vpp_UV_VCE_Gen]

This is the voltage setting of phase-to-phase undervoltage of composite voltage control element.


7-19 Date: 2013-07-04

7 Settings

Its operating voltage U op can be set as following: For turbine generator, U op  0.6U gn and for hydro-generator, U op  0.7U gn Where U gn is rated phase-to-phase voltage of generator. Sensitivity factor shall be checked by three-phase short circuit fault on HV side bus of main transformer:

K sen 

U op

Equation 7.4-9

) X t  I k(3. max

) Where I k(3. max is maximum secondary fault current during three-phase short circuit on HV side bus

of main transformer; X t is reactance of main transformer, X t  Z t . K sen ≥ 1.2 is required. 3.

[I_OC1_Gen]

This is the current setting of overcurrent protection stage 1. Setting of overcurrent relay shall be higher than rated current of generator.

I op 

K rel I gn Kr

Equation 7.4-10

Where:

K rel is reliability factor, 1.3 – 1.5;

K r is release factor, 0.85 – 0.95;

I gn is secondary rated current of generator. Sensitivity factor of overcurrent relay shall be checked by following:

K sen 

) I k( .2min I op

Equation 7.4-11

( 2)

Where I k . min is minimum fault current through location of the relay during phase-to-phase metallic short circuit on HV side of main transformer. K sen ≥ 1.2 is required. 4.

[t_OC1_Gen]

Time delay of overcurrent protection stage 1. Delay of this protection shall be higher than that of operation of backup protection of step-up transformer. This protection is used for islanding and generator shutting off. 5.

[Z1_Fwd_Gen]

7-20


7 Settings

This is the positive direction impedance setting of distance protection stage1. Here positive direction means the direction is pointing to the transformer instead of generator itself. If the value of this setting is greater than the next one, then the characteristic of distance protection is set as excursive impedance circle; if it is equal to the next one, the characteristic is whole impedance circle; if the next one is set as ―0‖, the characteristic becomes directional impedance. Generally, low impedance protection is considered as the backup protection of generator in case that voltage-controlled overcurrent protection cannot satisfy the sensitivity requirement of generator. 6.

[Z1_Rev_Gen]

Negative direction impedance setting of distance protection stage1. In general, this setting is set as 5-10% of the positive direction impedance setting. 7.

[En_Mem_Curr_Gen]

That the setting is set as ―1‖ indicates the excitation mode of generator is self shunt excitation mode. In that case, the protection will remember the current value at the initiation of fault, and operates based on it, no matter whether the current will decrease due to the descending excitation voltage result from terminal voltage’s getting down when external fault occurs. Once this setting is set as ―1‖, the backup overcurrent protection of generator is always controlled by composite voltage element.

Note! In the above Table，current used in backup protection of generator comes from the backup current input channel. 

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> GenPPFBakProt Settings

7.4.4 Settings of Stator Earth-fault Protection 

Setting List Table 7.4-4 List of stator earth fault protection settings

No.

Symbol

Range

Step

Unit

Description Voltage setting of residual voltage

1

V_ROV_VCE_Tr

1.00-100.00

0.01

V

control

element

for

ground

overcurrent protection. 2

V_SensROV_Sta

0.10 – 20.00

0.01

V

3

V_InsensROV_Sta

0.10 – 20.00

0.01

V


Voltage

setting

of

fundamental

residual overvoltage protection. Voltage

setting

of

high-setting

fundamental residual overvoltage

7-21 Date: 2013-07-04

7 Settings protection. 4

t_ROV_Sta

0.00 – 10.00

0.01

S

5

t_InsensROV_Sta

0.00 – 10.00

0.01

S

Delay

k_V3rdHRatio_PreSync_Sta

0.50 – 10.00

0.01

fundamental

residual

overvoltage protection. Delay of high-setting fundamental residual overvoltage protection. Ratio

6

of

setting

of

3

rd

harmonics

before incorporation of generator in power network.

7

k_V3rdHRatio_PostSync_Sta

0.50 – 10.00

Ratio setting of 3

0.01

rd

harmonics after

incorporation in power network. Restraint coefficient of percentage

8

k_V3rdHDiff_Sta

0.05 – 2.00

0.01

third harmonic voltage earth fault protection.

9

10

t_V3rdH_Sta

0.00 – 10.00

TrpLog_EF_Sta

0000–3FFFFFFF

0.01

S

1

Delay of percentage third harmonic voltage earth fault protection. Tripping output logic setting of stator earth fault protection.

Logic setting ―1‖ - enable, ―0‖ – disable Logic settings of disable(0) or 11

En_Alm_ROV_Sta

0/1

enable(1) alarm function of residual overvoltage. Logic settings of disable(0) or

12

En_Trp_ROV_Sta

0/1

enable(1)

residual

overvoltage

protection. Logic settings of disable(0) or 13

En_Alm_V3rdHRatio_Sta

0/1

enable(1) alarm function of third harmonic voltage ratio element. Logic settings of disable(0) or

14

En_Alm_V3rdHDiff_Sta

0/1

enable(1) alarm function of third harmonics differential voltage. Logic settings of disable(0) or

15

En_Trp_V3rdHRatio_Sta

0/1

enable(1) tripping function of third harmonic voltage ratio element. Logic settings of disable(0) or

16

En_Trp_InsensROV_Sta

enable(1) tripping function of high

0/1

setting

residual

overvoltage

protection Logic settings of disable(0) or 17

En_Alm_DeltVTS1_Gen

enable(1)

0/1

open-delta

failure

supervision of VT1 at generator terminal. Logic settings of disable(0) or

18

En_Alm_VTS_NP_Gen

0/1

enable(1)

open-delta

failure

supervision of VT at neutral point of 7-22


7 Settings generator.



Setting Explanation

1.

[V_SensROV_Sta]

This is the setting of fundamental residual overvoltage protection. Setting of this protection U op shall be higher than maximum unbalance voltage U unb. max of single phase VT at neutral point during normal operation.

U op  K rel U unb. max

Equation 7.4-12

Where K rel is reliability factor, 1.2–1.3 generally; U unb. max is the maximum measured fundamental unbalance residual voltage derived from single VT at the neutral point of generator. To assure its security, user should check the transferred residual voltage through coupling capacitance between HV side and LV side of transformer when external earth fault occurs on the HV side of the transformer. Meanwhile, settings, including time delay and operation setting, should be considered to cooperate with that of earth fault protection of the system.

Note! The residual voltage used in this protection comes from VT at the neutral point of generator. 2.

[V_InsensROV_Sta]

This is the setting of high-setting fundamental residual overvoltage protection. Only residual voltage at neutral point is taken for high setting zone of fundamental residual voltage protection. If ratio of VT on neutral point is nTVN 

U gn 3

/100V , this setting is usually 20 V – 25 V.

Residual voltage transferred by coupling capacitance per phase between HV and LV side windings of step-up transformer shall be checked when external fault occurs at HV side of the transformer. Coordination both on setting and delay between this protection and system earth fault protection could be achieved then. 3.

[k_V3rdHRatio_PreSync_Sta]

This is the ratio setting of 3rd harmonics before incorporation of generator in power network. 



Let third harmonic voltage at the end and neutral point of generator be U t and U n , ratio setting of third harmonic voltage percentage earth fault protection shall be PCS-985G Generator Relay

7-23 Date: 2013-07-04

7 Settings 

Ut



Un  

And   K rel

Equation 7.4-13

3  nTVN during pre-configuration, nTV 0

Where:

K rel is reliability factor, 1.3 – 1.5 in general; nTV 0 is ratio of open-delta residual voltage at the terminal of generator; nTVN is ratio of residual VT on neutral point. During incorporation of generator to power system, the ratio U 3T / U 3N

changes considerably

owing to variation of equivalent capacitive reactance at generator terminal. So two different settings are designed for protection before and after connection of generator with system, and these two settings can be switched over with alternation of contacts’ position of the terminal breaker. The setting shall be (1.3 – 1.5)× before incorporation and (1.3 – 1.5)× 2 after that. Where  1 and  2 are the maximum real-measured third harmonic voltage ratio before and after incorporation respectively. 4.

[k_V3rdHDiff_Sta]

This is the restraint coefficient of percentage third harmonic voltage earth fault protection. 







U t  k p U n  k zd U n

Equation 7.4-14

Where: 

k p is vectorial automatic tracing regulation factor; k zd is restraint factor [3rdHarm Diff. Ratio], 0.3~0.5 is recommended. U t is 3rd harmonics derived from the terminal of generator.

U n is 3rd harmonics derived from the neutral point of generator. 5.

[t_V3rdH_Sta]

This is the delay of percentage third harmonic voltage earth fault protection. It shall be longer than that of backup protection against external fault. 

Access Path

7-24


7 Settings

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> StaEFProt Settings

7.4.5 Settings of Stator Earth-fault Protection with Voltage Injection 

Setting List Table 7.4-5 List of stator earth-fault protection with voltage injection settings

No.

Symbol

Range

Step

Unit

Description Resistance

1

R_Alm_InjEF_Sta

0.10 – 30.00

0.01

kΩ

setting

of

external

voltage-injecting earth fault protection of stator for alarm. Resistance

2

R_Trp_InjEF_Sta

0.10 – 30.00

0.01

kΩ

setting

of

external

voltage-injecting earth fault protection of stator for tripping. Time

3

t_Alm_InjEF_Sta

0.00 – 10.00

0.01

S

delay

setting

of

external

voltage-injecting earth fault protection of stator for alarm. Time

4

t_Trp_InjEF_Sta

0.00 – 10.00

0.01

S

delay

setting

of

external

voltage-injecting earth fault protection of stator for tripping.

5

I_ROC_InjEF_Sta

0.00 – 4.00

0.01

A

Current setting of ground overcurrent protection. Voltage setting of residual voltage element

6

V_Supv_InjEF_Sta

0.00 – 15.00

0.01

V

for supervising the working condition of external power supply. Current setting of residual current element

7

I_Supv_InjEF_Sta

0.00 – 40

0.01

mA

for supervising the working condition of external power supply. Correction angle to eliminate angle error of

8

ANG_corr_InjEF_Sta

0.0 – 360

0.1

°

the CTs and angle distortions caused by a less

than

ideal

earthing

or

neutral

transformer. Compensating resistance caused by the 9

R_InjEF_Sta

0.0 – 3000.0

0.1

Ω

angle error of the CTs and angle distortions caused by a less than ideal earthing or neutral transformer. Compensating reactance caused by the

10

X_InjEF_Sta

0.0 – 3000.0

0.1

Ω

angle error of the CTs and angle distortions caused by a less than ideal earthing or neutral transformer.

11

Rp_InjEF_Sta

0.0 – 3000.0

0.1

12

k_R_InjEF_Sta

0.1 – 21.00

0.01

Ω


Parallel load resistance value. Compensating coefficient for parallel load resistance value.

7-25 Date: 2013-07-04

7 Settings Tripping output logic setting of external 13

TrpLog_InjEF_Sta

0000–3FFFFFFF

1

voltage-injecting

stator

earth

fault

protection Logic setting ―1‖ - enable, ―0‖ – disable Logic settings of disable(0) or enable(1) 14

En_Alm_R_InjEF_Sta

0/1

alarm function of external voltage-injecting stator earth fault protection. Logic settings of disable(0) or enable(1) trip

15

En_Trp_R_InjEF_Sta

0/1

function of external voltage-injecting stator earth fault protection. Logic settings of disable(0) or enable(1)

16

En_Trp_IO_Sta

residual overcurrent element act on in

0/1

external voltage-injecting stator earth fault protection. Logic settings of disable(0) or enable(1)

17

En_TestMode_InjEF_Sta

compensation

0/1

voltage-injecting

test stator

in earth

external fault

protection.



Setting Explanation

1.

[I_ROC_InjEF_Sta]

This is the current setting of ground overcurrent protection. Cooperating with the criteria of earthing resistance, residual current criteria acts as backup protection against earth fault within 80% of the stator’s winding apart from the terminal of generator. This criteria responses to the current flowing thought the connection line between generator neutral point and the ground. This setting can be set as:

I op＝K rel  0.2 

U N sec 1  RL nCT

Where:

U Nsec is secondary voltage of ground-transformer when single-phase metallic short circuit fault occurs at the terminal of generator;

nCT is ratio of inter-CT connected at secondary side of ground-transformer;

RL is secondary load resistance of secondary side of ground-transformer. K rel is reliability coefficient. Generally 1.1~1.3 is recommended. 2.

[V_Supv_InjEF_Sta]

7-26


7 Settings

This is voltage setting of residual voltage element for supervising the working condition of external power supply. If measured residual voltage is below this setting and measured residual current is below the next one, it means the external power supply fails. 3.

[ANG_corr_InjEF_Sta]

Correction Angle to eliminate angle error of the CTs and angle distortions caused by a less than ideal earthing or neutral transformer. The correct setting for this parameter can only be determined with a primary test. The adjustment should be made for the tripping value. 4.

[R_InjEF_Sta]

The setting is used to compensate the resistance caused by the angle error of the CTs and angle distortions caused by a less than ideal earthing or neutral transformer. The correct setting for this parameter can only be determined with a primary test. The adjustment should be made for the tripping value. Note! In large power units with generator circuit breaker, applications can be found where there is some additional loading equipment on the low-voltage side of the unit transformer to reduce the influence by the residual voltage when the generator circuit breaker is open. The 20 Hz source is connected via the neutral transformer in the generator neutral point. With the generator circuit breaker closed, the protection measures the loading resistance on the unit transformer side, which can be mistaken for an earth resistance. 

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> InjStaEFProt Settings

7.4.6 Settings of Rotor Earth-fault Protection 

Setting List Table 7.4-6 List of earth fault protection settings of rotor

No.

Symbol

Range

Step

Unit

Description Impedance

1

R_Sens1PEF_RotWdg

0.10 – 100.00

0.01

kΩ

stage

of

setting one-point

of

sensitive

earth

fault

protection of rotor. 2

R_1PEF_RotWdg

0.10 – 100.00

0.01

kΩ

3

t_Alm_1PEF_RotWdg

0.00 – 10.00

0.01

S

Impedance setting of

one-point

earth fault protection of rotor. Delay

of

one-point

earth

fault

protection of rotor operates to alarm.

4

t_Trp_1PEF_RotWdg

0.00 – 10.00

0.01


S

Delay

of

one-point

earth

fault

protection of rotor operates to trip.

7-27 Date: 2013-07-04

7 Settings 5

t_2PEF_RotWdg

0.00 – 10.00

0.01

S

Delay

of

two-point

earth

fault

protection of rotor. For rotor earth fault protection with injection principle, it is switching

6

t_Switch

0.50 – 10.00

0.01

S

cycle of square wave power. For rotor earth fault protection with ping-pang principle, it is switching cycle of electronic switch. The

7

R_Injected

0.10 – 100.00kΩ

0.01

kΩ

power

external

connected

resistance,

it

heavy

is

47kΩ

generally. Logic setting for selecting principle of earth fault protection of rotor 8

Opt_EF_RotWdg

0-2

1

―0‖: ping-pang principle ―1‖:

injection

principle

of

double-ends ―2‖: injection principle of single-end 9

TrpLog_EF_RotWdg

0000 – 3FFFFFFF

1

Tripping output logic setting of earth fault protection of rotor.

Logic setting ―1‖ - enable, ―0‖ – disable Logic settings of disable(0) or 10

En_Alm_Sens1PEF_RotWdg

enable(1)

0/1

alarm

function

of

sensitive stage of one-point earth fault protection of rotor. Logic settings of disable(0) or

11

En_Alm_1PEF_RotWdg

enable(1)

0/1

alarm

function

of

one-point earth fault protection of rotor. Logic settings of

12

En_Trp_1PEF_RotWdg

enable(1)

0/1

tripping

disable(0) or function

of

one-point earth fault protection of rotor. Logic settings of disable(0) or

13

En_2PEF_RotWdg

0/1

enable(1)

two-point

earth

fault

protection of rotor.



Setting Explanation

1.

[R_Sens1PEF_RotWdg]

This is the impedance setting of sensitive stage of one-point earth fault protection of rotor. General specification of generator specifies that insulation resistance of its excitation winding shall be higher than 1 MΩ for air cooled and hydrogen-cooled turbine generator during cooling state, and 2 kΩ for water cooled excitation winding. General specification of hydro-generator specifies that insulation resistance of its excitation winding shall be higher than 0.5 MΩ in any case. 7-28


7 Settings

Sensitive stage of this protection is used for alarm. Its setting could be 20 kΩ – 80 kΩ generally. 2.

[R_1PEF_RotWdg]

This is the impedance setting of one-point earth fault protection of rotor. Setting of one point earth fault protection can be 20 kΩ for air-cooled and hydrogen-cooled turbine generator and 2.5 kΩ for water cooled excitation winding. This protection can be used for alarm or generator shutting with delay. Actual measured insulation resistance is used for this protection. 

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> RotWdgEFProt Settings

7.4.7 Settings of Thermal Overload Protection of Stator 

Setting List Table 7.4-7 List of thermal overload protection settings of stator

No.

Symbol

Range

Step

Unit

1

I_OvLd_Sta

0.10 – 50.00

0.01

A

2

t_OvLd_Sta

0.00 – 10.00

0.01

S

3

TrpLog_OvLd_Sta

0000–3FFFFFFF

4

I_Alm_OvLd_Sta

0.10 – 50.00

0.01

A

5

t_Alm_OvLd_Sta

0.00 – 10.00

0.01

S

6

I_InvOvLd_Sta

0.10 – 100.00

0.01

A

7

tmin_InvOvLd_Sta

0.00 – 10.00

0.01

S

8

A_Therm_Sta

1.00 –100.00

0.01

9

K_Disspt_Sta

1.02 – 2.00

0.01

10

TrpLog_InvOvLd_Sta

0000–3FFFFFFF



Setting Explanation

1.

[I_OvLd_Sta]

Description Current setting of definite time overcurrent protection. Delay of definite time overcurrent protection. Tripping output logic setting of definite time

1

overcurrent protection.

1

Current setting of definite time overcurrent alarm. Delay of alarm issued by definite time overcurrent element. Pickup current of inverse time overcurrent protection. Delay

of

upper

limit

of

inverse

time

overcurrent protection Thermal

capacity

parameter

of

stator

winding. Heat dissipation factor for inverse time overcurrent. Tripping output logic setting of inverse time overcurrent protection.

This is the setting of definite time overcurrent protection.


7-29 Date: 2013-07-04

7 Settings

Setting of this protection is determined by the requirement of reliable release during permissive continuous load current of generator.

I OP  K rel

I gn

Equation 7.4-15

Kr

Where:

K rel is reliability factor, 1.05 generally;

K r is release factor, 0.85 – 0.95;

I gn is secondary rated current of generator. Delay of this protection shall be longer than maximum delay of backup protection. Alarm will be issued or load will be reduced when it operates. 2.

[I_InvOvLd_Sta]

This is the pickup current of inverse time overcurrent protection. Characteristic of this protection is indefinite time relationship between multiple of load current and corresponding permissive duration which is determined by permissive overload capability of stator provided by the factory.

t

K tc I *2

Equation 7.4-16

 K sr2

Where:

K tc is heat capacity factor of stator winding;

I * is per unit value of load current referred to rated current of stator; K sr is heat dissipation factor, 1.02 – 1.05 generally. Minimum delay for upper limit of this protection shall coordinate with unrestraint protection. Current setting of lower limit of this protection shall coordinate with definite time overload protection mentioned above, namely

I OP. min  K c 0 K rel

I gn

Equation 7.4-17

Kr

Where: K C 0 is coordination factor, 1.05 in general. 

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> StaOvLdProt Settings

7-30


7 Settings

7.4.8 Settings of Negative-sequence Overcurrent Protection 

Setting List Table 7.4-8 List of negative sequence overload protection

No.

Symbol

Range

Step

Unit

1

I_NegOC_Gen

0.10 – 20.00

0.01

A

2

t_NegOC_Gen

0.00 – 10.00

0.01

S

Description Current setting of negative sequence overcurrent protection. Delay

of

TrpLog_NegOC_Gen

0000–3FFFFFFF

1

sequence

overcurrent protection. Tripping

3

negative

output

negative

logic

sequence

setting

of

overcurrent

protection. Current setting of alarm issued by 4

I_Alm_NegOC_Gen

0.05 – 20.00

0.01

A

negative

sequence

overcurrent

element. 5

t_Alm_NegOC_Gen

0.00 – 10.00

0.01

S

Delay of alarm issued by negative sequence overcurrent element. Pickup

6

I_InvNegOC_Gen

0.05 – 5.00

0.01

A

current

negative

of

inverse

sequence

time

overcurrent

protection. Permitted 7

I_Neg_Perm_Gen

0.05 – 5.00

0.01

A

inverse

continuous time

overcurrent

currents

negative

protection

of

sequence for

lasting

operation. Delay of upper limit of inverse negative 8

tmin_InvNegOC_Gen

0.10 – 10.00

0.01

S

sequence

overcurrent

protection. Minimum delay for upper limit of this protection shall coordinate with unrestraint protection. Delay of upper limit of inverse negative

9

tmax_InvNegOC_Gen

0.10 – 5000.00

0.1

S

sequence

overcurrent

protection. Maximum delay for upper limit of this protection shall coordinate with unrestraint protection.

10

A_Therm_RotBody

1.00 – 100.00

0.01

Heat dissipation factor for inverse time negative sequence overcurrent. Tripping output logic setting of inverse

11

TrpLog_InvNegOC_Gen

0000– 3FFFFFFF

1

time negative sequence overcurrent protection.



Setting Explanation

1.

[I_NegOC_Gen]

This is the setting of negative sequence overcurrent protection. PCS-985G Generator Relay

7-31 Date: 2013-07-04

7 Settings

Setting of this protection is determined by the threshold under which this protection can release reliably, that threshold value is continuously permissive negative sequence current I 2  . So,

I OP  K rel

I 2 I gn

Equation 7.4-18

Kr

Where:

I OP is the setting [I_OvLd_Sta]. K rel is reliability factor, 1.05;

K r is release factor, 0.85 – 0.95; I 2 is per unit value of continuously permissive negative sequence current,

I gn is secondary rated current of generator. 2.

[t_NegOC_Gen]

This is the delay of negative sequence overcurrent protection. Delay of this protection shall be longer than maximum delay of backup protection. Alarm will be issued when it operates. 3.

[I_InvNegOC_Gen]

This is the pickup current of inverse time negative sequence overcurrent protection. Characteristic of this protection is determined by permissive negative sequence overload capability of rotor surface provided by the manufacturer.

t

I 22*

A  I 22

Equation 7.4-19

Where:

A is permissive negative sequence current factor of rotor surface;

I 2* is per unit value of negative sequence current of generator; I 2 is per unit value of permissive continues negative sequence current. Minimum delay for upper limit of this protection shall coordinate with unrestraint protection. 4.

[I_Neg_Perm_Gen]

This is the permitted continuous currents of inverse time negative sequence overcurrent protection 7-32


7 Settings

for lasting operation. Current setting of lower limit of this protection shall be the operating current corresponding to delay 1000 s, namely

I OP. min 

A  I 22 1000

Equation 7.4-20

This protection is used for islanding or program tripping. 

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> GenNegOCProt Settings

7.4.9 Settings of Loss-of-excitation Protection 

Setting List Table 7.4-9 List of loss-of-excitation protection

No.

Symbol

Range

Step

Unit Impedance

1

X1_LossExc_Gen

0.000-2.000

0.001

2

X2_LossExc_Gen

0.000-2.000

0.001

3

Q_RevQ_LossExc_Gen

0.01 –50.00

0.01

%

4

V_RotUV_LossExc_Gen

0.10–500.00

0.01

V

5

Un_RotNoLoad_LossExc_Gen

0.10–500.00

0.01

V

6

k_RotUV_LossExc_Gen

0.00–10.00

0.01

pu

7

V_TermUV_LossExc_Gen

0.10–100.00

0.01

V

8

V_BusUV_LossExc_Gen

0.10–100.00

0.01

V

9

t_LossExc1_Gen

0.10 –10.00

0.01

S

10

t_LossExc2_Gen

0.10 –10.00

0.01

S

11

t_LossExc3_Gen

0.10–3000.00

0.01

S

12

TrpLog_LossExc1_Gen

00–3FFFFFFF

1

13

TrpLog_LossExc2_Gen

00–3FFFFFFF

1


Description setting

1

of

2

of

loss-of-excitation protection Impedance

setting

loss-of-excitation protection Reverse power setting of reactive power Low voltage setting of rotor. Rated

excitation

voltage

of

the

generator without load. Restrained coefficient of low voltage criterion of rotor. Low voltage setting for generator terminal undervoltage criterion. Low

voltage

setting

for

busbar

undervoltage criterion. Delay of loss-of-excitation protection stage 1 Delay of loss-of-excitation protection stage 2 Delay of loss-of-excitation protection stage 3 Tripping

output

logic

setting

of

loss-of-excitation protection stage 1 Tripping

output

logic

setting

of

loss-of-excitation protection stage 2

7-33 Date: 2013-07-04

7 Settings 14

TrpLog_LossExc3_Gen

00–3FFFFFFF

1

Tripping

output

logic

setting

of

loss-of-excitation protection stage 3


En_Z_LossExc1_Gen

0/1

settings

enable(1)

of

disable(0)

or

criterion

in

impedance

loss-of-excitation protection stage 1 Logic 16

En_RotUV_LossExc1_Gen

0/1

settings

of

disable(0)

or

enable(1) the criterion of rotor voltage in loss-of-excitation protection stage 1 Logic

17

En_BusUV_LossExc1_Gen

settings

of

disable(0)

or

enable(1) the criterion of busbar

0/1

voltage in loss-of-excitation protection stage 1 Logic

18

En_TermUV_LossExc2_Gen

settings

of

disable(0)

or

enable(1) the criterion of generator

0/1

terminal voltage in loss-of-excitation protection stage 2 Logic

19

En_Z_LossExc2_Gen

0/1

settings

enable(1)

of

disable(0)

or

criterion

in

impedance

loss-of-excitation protection stage 2 Logic 20


0/1

settings

of

disable(0)

or


21

En_Z_LossExc3_Gen

0/1

settings

enable(1)

of

disable(0)

or

criterion

in

impedance

loss-of-excitation protection stage 3. Logic 22


0/1

settings

of

disable(0)

or


23

En_Alm_LossExc3_Gen

0/1

settings

enable(1)

of

disable(0)

or

function

of

alarm

loss-of-excitation protection stage 3 Logic setting of selecting impedance circle 24

Opt_Z_LossExc_Gen

―0‖, choose steady state stability

0/1

circle. ―1‖, choose asynchronous impedance cycle.

25

En_RevQ_LossExc_Gen

Logic

0/1

settings

of

disable(0)

or

enable(1) reverse power criterion Logic setting of selecting the input

26

Opt_RotV_LossExc_Gen

mode of rotor voltage

0/1

―0‖, input directly ―1‖, input by transmitter

7-34


7 Settings



Setting Explanation

1.

[Xd_Gen]

This is the impedance setting1 of loss-of-excitation protection. In the following figure,

jx Xc

R Xa

Xb

Figure 7.4-1 Impedance circle of loss of excitation protection

For asynchronous impedance cycle, this setting represents for X a , and the next setting (NO.2) is

X b . Here

Xa  

2 X d' U gn  na  2 S gn  nv

X b  ( X d 

Equation 7.4-21

2 U gn  na X d' ) 2 S gn  nv

Equation 7.4-22

Where: '

X d and X d are unsaturated per unit value of transient reactance and synchronous reactance of generator,

U gn and S gn are rated voltage and rated apparent power of generator; n a and n v are CT ratio and VT ratio. For steady state stability limit circle, this setting represents for X C , and the next setting is X b , here

Xc  Xs 

2 U gn  na

Equation 7.4-23

S gn  nv

X b  ( X d 

2 U gn  na X d' ) 2 S gn  nv

Equation 7.4-24

Where:


7-35 Date: 2013-07-04

7 Settings

X s is equivalent reactance on system side (including step-up transformer) connected with the generator (per unit value, reference capacity is apparent power of the generator). Asynchronous impedance circle and steady state stability limit circle can be selected by logic setting [Opt_Z_LossExc_Gen]. For practical project, impedance between asynchronous impedance circle and steady state stability limit circle can be selected for optimal combination of reliability and speed. 2.

[Q_RevQ_LossExc_Gen]

This is the reverse power setting of reactive power Reverse reactive power criterion:

Q zd  K rel 

Q jx

Equation 7.4-25

Pgn

Where:

K rel

is reliability factor, 1 - 1.3;

Q jx is permissive incoming reactive power to the generator; Pgn is rated active power of the generator. Reverse reactive power criterion can be selected by logic setting [En_RevQ_LossExc_Gen] . 3.

[V_RotUV_LossExc_Gen]

This is the low voltage setting of rotor. There are two low voltages setting of rotor, they are a) Excitation undervoltage criterion

U fd .op  K rel  U fd 0

Equation 7.4-26

Where:

U fd .op is this setting. K rel is reliability factor, 0.60 – 0.80;

U fd 0 is rated excitation voltage of the generator without load. b) Variable excitation voltage criterion For a generator connecting with power system, there is a necessary excitation voltage U fd 0 for keeping steady state stability.

7-36


7 Settings

Variable excitation voltage criterion is

U fd .op  K xs  U fd 0 

P Sn

Equation 7.4-27

K xs  K rel  ( X d  X S )

Equation 7.4-28

Where:

K xs

is rotor voltage criterion coefficient.

K rel is reliability factor, 0.70 – 0.85; X d and X s are per unit value of synchronous reactance of generator and equivalent reactance of system connecting with the generator (referred to rated capacity of the generator);

P is current active power of the generator;

U fd 0 is rated excitation voltage of generator without load. 4.

[V_GTermUV_LossExc_Gen]

This is the low voltage setting for generator terminal undervoltage criterion. This criterion is used mainly to prevent generator terminal voltage lower than the permissible value due to loss of excitation of generator. Under voltage criterion for three phase simultaneously:

U op.3 ph  K rel  U gn

Equation 7.4-29

Where:


U gn is rated voltage of generator. 5.

[V_BusUV_LossExc_Gen]

This is the low voltage setting for busbar undervoltage criterion. This criterion is used mainly to prevent voltage collapse due to loss of excitation of generator for a system without enough spare reactive power. Voltage on bus of system side is adopted for this criterion. Under voltage criterion for three phase simultaneously:

U op.3 ph  K rel  U h. min

Equation 7.4-30


7-37 Date: 2013-07-04

7 Settings

Where:


U h. min is minimum normal operation voltage of HV side of the system. This criterion can also be configured as 0.90 – 0.95 times of terminal voltage of generator.

Note! There must be one stage of loss-of-excitation protection, the criterion of busbar voltage is not enabled and it will operate to reduce power output. Following criterion are recommended for various stages of this protection: Criterion

Stage 1

Stator side impedance

√

Busbar under voltage criterion

√

√

Stage 3

√

√

√

Generator terminal under voltage criterion Rotor voltage criterion

√

power output reduction

√

√

√

√

√ √

switching over backup excitation Delay ( s )



Stage 2

0.5–1s

√

0.5–1s

0.5–1s

>1s

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> GenLossExcProt Settings

7.4.10 Settings of Out-of-step Protection 

Setting List Table 7.4-10 List of out-of-step protection

No.

Symbol

Range

Step

Unit

Description Impedance

setting

A

of

out-of-step

setting

B

of

out-of-step

setting

C

of

out-of-step

1

Za_OOS_Gen

0.00 –100.00

0.01

Ω

2

Zb_OOS_Gen

0.00 –100.00

0.01

Ω

3

Zc_OOS_Gen

0.00 –100.00

0.01

Ω

4

ANG_Reach_OOS_Gen

0 – 90.00

0.01

°

Reach angle of system impedance.

5

ANG_Inner_OOS_Gen

0 –150.00

0.01

°

Internal angle of lens characteristic

protection. Impedance protection. Impedance protection.

Pole sliding number setting for external 6

n_Slip_Ext_OOS_Gen

1-1000

1

fault of generator. When the oscillation center situates outside the protected section, times of pole sliding shall be set

7-38


7 Settings as 2 – 15 for alarm and more than 15 for tripping. Pole sliding number setting for internal fault of generator. When the oscillation 7

n_Slip_Int_OOS_Gen

1-1000

1

center

situates

within

the

protected

section, time of pole sliding shall be set as 1-2 in general. Tolerating current of breaker in tripping. 8

Ibrk_CB_HVS_Tr

0.10 – 100.00

0.01

A

This is an auxiliary criterion and is determined by interruption capacity of the circuit breaker of main transformer.

9

TrpLog_OOS_Gen

00–3FFFFFFF

1

Tripping output logic setting of out-of-step protection.

Logic setting ―1‖ - enable, ―0‖ – disable Logic settings of disable(0) or enable(1) 10

En_Alm_Ext_OOS_Gen

0/1

alarm in out-of-step case outside the generator. Logic settings of disable(0) or enable(1)

11

En_Trp_Ext_OOS_Gen

0/1

tripping in out-of-step case outside the generator. Logic settings of disable(0) or enable(1)

12

En_Alm_Int_OOS_Gen

0/1

alarm in out-of-step case inside the generator. Logic settings of disable(0) or enable(1)

13

En_Trp_Int_OOS_Gen

0/1

tripping in out-of-step case inside the generator.



Setting Explanation

Explanation of the settings Out-of-step protection operates only when out-of-step occurs in power system. Then, based on situation at that time, the dispatching center will adopt islanding, generator shutting or restraint and other necessary measures. Only if center of oscillation situates within the generator or near the generator, or the oscillation lasts too long, and phase difference of electro-motive force between two sides of the breaker less than 90°, this protection will trip. Characteristic of this protection comprises three parts: lens part ②, boundary part ① and reactance line part ③. See the following figure.


7-39 Date: 2013-07-04

7 Settings

jx Za

U D

Zc

OL

1



3

IL



IR

0 Zb L R

OR

R 1

2

Figure 7.4-2 Impedance of out-of-step protection

1.

[Za_OOS_Gen]

This is the impedance setting A of out-of-step protection. Refer to Figure 7.4-2, this setting can be set by means of the following formula.

Za  ( X S  X C ) 

2 U gn  na

Equation 7.4-31

S gn  nv

Where:

X C is per unit value of equivalent reactance of transformer connecting to the generator; X S is equivalent reactance of power system network;

U gn and Sgn are rated voltage and rated apparent power of generator; na and nv are CT ratio and VT ratio. 2.

[Zb_OOS_Gen]

This is the impedance setting B of out-of-step protection. Refer to figure 7.3.2, this setting can be set by means of the following formula.

Zb   X  ' d

2 U gn  na

Equation 7.4-32

S gn  nv

Where:

X d' is transient reactance of generator; 3.

[Zc_OOS_Gen]

This is the impedance setting C of out-of-step protection. Reactance line is the dividing line of 7-40


7 Settings

oscillation center. Refer to Figure 7.4-2, this setting can be set by means of the following formula. In practice, 0.9 times of transformer impedance is recommended.

Z c  0.9  X c  4.

2 U gn  na

Equation 7.4-33

S gn  nv

[φ_Reach_OOS_Gen]

This is the reach angle of system impedance.

 = 80°- 85°according to the real angle of system. 5.

[φ_Inner_OOS_Gen]

This is the internal angle of lens characteristic  , 120°is recommended. The following formula is for reference,

  180  2 arctan

Zr 

2Z r Za  Zb

1 RL. min 1.3

Equation 7.4-34

Where RL. min is minimum load impedance of generator. 

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> GenOOSProt Settings

7.4.11 Settings of Overvoltage Protection 

Setting List Table 7.4-11 List of overvoltage protection settings

No.

Symbol

Range

Step

Unit

1

V_OV1_Gen

10.00 – 170.00

0.01

V

2

t_OV1_Gen

0.10 – 10.00

0.01

S

3

TrpLog_OV1_Gen

0000 – 3FFFFFFF

1

4

V_OV2_Gen

10.0 0– 170.00

0.01

V

5

t_OV2_Gen

0.10 – 10.00

0.01

S

6

TrpLog_OV2_Gen

0000 – 3FFFFFFF

1

7

V_UV_Gen

10.00 – 100.00

0.01

Description Voltage setting of overvoltage protection stage 1. Delay of overvoltage protection stage 1. Tripping output logic setting of overvoltage protection stage 1. Voltage setting of overvoltage protection stage 2. Delay of overvoltage protection stage 2. Tripping output logic setting of overvoltage protection stage 2.

V


Voltage setting of undervoltage protection.

7-41 Date: 2013-07-04

7 Settings 8

t_UV_Gen

0.10 – 10.00

0.01

9

TrpLog_UV_Gen

0000 – 3FFFFFFF

1

10

V_Alm_UV_Gen

0.10 – 110.00

0.01

V

11

t_Alm_UV_Gen

0 – 10.00

0.01

S

S

Delay of undervoltage protection. Tripping output logic setting of undervoltage protection. Voltage

alarm

setting

of

undervoltage

of

undervoltage

protection. Delay

alarm

setting

protection.

Logic setting ―1‖ - enable, ―0‖ – disable 12

En_Alm_OV2_Gen

Enable

0/1

alarm

function

of

overvoltage

protection stage 2. Enable stage 2 of overvoltage protection controlled by power network connected

13

En_CB_BlkOV2_Gen

0/1

status of generator, it will be blocked if the generator is connected with the power network.

14

En_Alm_UV_Gen



Setting Explanation

1.

[V_OV1_Gen]

Enable

0/1

alarm

function

of

undervoltage

protection stage.

This is the voltage setting of overvoltage protection stage 1. Setting of overvoltage protection of stator shall base on permissive overvoltage capability provided by the factory or insulation condition of the stator. For turbo-generator with capacity more than 200 MW,

Uop  1.3U gn

Equation 7.4-35

Where:

U gn is the secondary rated phase-to-phase voltage. This is used for islanding and excitation shutting with delay 0.5 s. For hydro-generator,

Uop  1.5U gn

Equation 7.4-36

This is used for islanding and excitation shutting with delay 0.5 s. For hydro-generator with SCR excitation,

Uop  1.3U gn

Equation 7.4-37

This is used for islanding and excitation shutting with delay 0.3 s. 

Access Path

Access path in menu is: 7-42


7 Settings

Main Menu -> Settings -> GenProt Settings -> GenVoltProt Settings

7.4.12 Settings of Overexcitation Protection of Generator 

Setting List Table 7.4-12 List of over excitation protection settings of generator

No.

Symbol

Range

Step

1

k_OvExc1_Gen

1.00 – 2.00

0.01

2

t_OvExc1_Gen

0.10 – 3000.00

0.01

Unit

Description Multiple setting of stage 1 of definite time over excitation protection.

S

Delay of stage 1 of definite time over excitation protection. Tripping output logic setting of stage 1 of definite time over excitation protection. The

3

TrpLog_OvExc1_Gen

0000 – 3FFFFFFF

1

function of this protection is used for islanding,

excitation

shutting

or

programming, excitation reducing etc. Multiple setting of over excitation alarm. 4

k_Alm_OvExc_Gen

1.00 – 2.00

Setting of alarm shall be lower than that of

0.01

over

excitation

protection.

1.1

is

recommended. 5

t_Alm_OvExc_Gen

0.10 – 25.00

0.01

6

k0_InvOvExc_Gen

1.00 – 2.00

0.01

7

t0_InvOvExc_Gen

1.00 – 3000.00

0.01

8

k1_InvOvExc_Gen

1.00 – 2.00

0.01

9

t1_InvOvExc_Gen

1.00 – 3000.00

0.01

10

k2_InvOvExc_Gen

1.00 – 2.00

0.01

11

t2_InvOvExc_Gen

1.00 – 3000.00

0.01

12

k3_InvOvExc_Gen

1.00 – 2.00

0.01

13

t3_InvOvExc_Gen

1.00 – 3000.00

0.0

14

k4_InvOvExc_Gen

1.00 – 2.00

0.01

15

t4_InvOvExc_Gen

1.00 – 3000.00

0.01

16

k5_InvOvExc_Gen

1.00 – 2.00

0.01

17

t5_InvOvExc_Gen

1.00 – 3000.00

0.01

18

k6_InvOvExc_Gen

1.00 – 2.00

0.01

19

t6_InvOvExc_Gen

1.00 – 3000.00

0.01

S

Delay of over excitation alarm. Upper limit of multiple setting of inverse time over excitation protection—n0

S

Delay of upper limit of inverse time over excitation protection. Inverse time over excitation multiple n1.

S

Delay at the point n1 on inverse time over excitation curve—t1 Inverse time over excitation multiple n2.

S


S

Delay at the point n3 on inverse time over excitation curve—t3. Inverse time over excitation multiple n4.

S


S

Delay at the point n5 on inverse time over excitation curve—t5. Inverse time over excitation multiple n6.

S


Delay at the point n6 on inverse time over excitation curve—t6.

7-43 Date: 2013-07-04

7 Settings 20

k7_InvOvExc_Gen

1.00 – 2.00

0.01

21

t7_InvOvExc_Gen

1.00 – 3000.00

0.01

22

TrpLog_InvOvExc_Gen

0000 – 3FFFFFFF



Setting Explanation

Inverse time over excitation multiple n7. Delay at the point n7 on inverse time over

S

excitation curve—t7. Tripping output logic setting of inverse time

1

over excitation protection.

The calculation principle can refer to Section 7.4.6. 

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> GenOvExcProt Settings

7.4.13 Settings of Power Protection of Generator 

Setting List Table 7.4-13 List of power protection settings of generator

No. 1

Symbol P_RevP_Gen

Range 0.50 – 50.00

Step

Unit

0.01

%

Description Power

setting

of

reverse

power

protection. Delay of reverse power alarm. For

2

t_Alm_RevP_Gen

0.10 – 3000.00

0.01

S

reverse power protection without steam valve contact blocking, delay 15 s for alarm.

3

t_Trp_RevP_Gen

0.10 – 3000.00

0.01

4

TrpLog_RevP_Gen

0000–3FFFFFFF

1

5

P_SeqTrpRevP_Gen

0.50 – 10.00

0.01

S

Delay of reverse power protection. Tripping output logic setting of reverse power protection.

%

Power

setting

of

sequent-tripping

reverse power protection. Delay

of

sequent-tripping

reverse

power protection. For sequent-tripping 6

t_SeqTrpRevP_Gen

0.01 – 10.00

0.01

S

reverse power protection with steam valve contact blocking, delay 0.5 s – 1.00 s for islanding. Tripping

7

TrpLog_SeqTrpRevP_Gen

0000–3FFFFFFF

1

output

sequent-tripping

logic

setting

reverse

of

power

protection. Power setting of low power protection. 8

P_UP_Gen

0.50 – 10.00

0.01

%

1%~2% of rated active power is recommended. Power setting of low power protection.

9

t_UP_Gen

0.01 – 10.00

0.01

S

For low power protection controlled by un-emergency shutoff binary input,

7-44


7 Settings delay 0.5 s – 1.5 s is set for islanding. 10

TrpLog_UP_Gen

0000–3FFFFFFF

1

Tripping output logic setting of low power protection.


En_BO_UP_Gen

0/1

reverse power protection controlled by guide blade contact.



Setting Explanation

1.

[P_RevP_Gen]

This is the power setting of reverse power protection.

Pop  K rel ( P1  P2 )

Equation 7.4-38

Where:

K rel is reliability coefficient, 0.5 – 0.8 generally;

P1 is minimum loss of turbine during reverse power operation, 2% - 4% of rated power generally;

P2 is minimum loss of generator during reverse power operation, P2  (1  ) Pgn generally,  is efficiency factor of generator, 98.6% - 98.7%;

Pgn is rated power of generator.

Pop is set as 1% - 2% of rated active power generally, and 1% is recommended. 2.

[t_Trp_RevP_Gen]

This is the delay of reverse power protection. For reverse power protection without guide blade contact blocking, according to permissive operation time of reverse power, delay 1 min – 3 min is set for islanding in general. For program reverse power protection with blade position blocking, delay 0.5 s – 1.5 s is set for islanding. 3.

[En_BO_UP_Gen]

Enable binary output function of generator low power protection. If it is set as ―1‖, the generator low power protection output contact will operate once generator low power protection operates, otherwise the contact will not operate even if generator low power protection operates. 

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> GenPwrProt Settings


7-45 Date: 2013-07-04

7 Settings

7.4.14 Settings of Underfrequency and Overfrequency Protection 

Setting List Table 7.4-14 List of frequency protection settings

No.

Symbol

Range

Step

Unit

1

f_UF1_Gen

0.9fn – 1.02fn

0.01

Hz

2

t_Accu_UF1_Gen

0.10 –300.00

0.01

min

3

f_UF2_Gen

0.9fn – 1.02fn

0.01

Hz

4

t_UF2_Gen

0.10 –300.00

0.01

min

5

f_UF3_Gen

0.9fn – 1.02fn

0.01

Hz

6

t_UF3_Gen

0.10 –300.00

0.01

min

7

TrpLog_UF_Gen

0000 – 3FFFFFFF

8

f_OF1_Gen

1.00fn – 1.02fn

0.01

Hz

9

t_OF1_Gen

0.10 –100.00

0.01

min

10

f_OF2_Gen

1.00fn – 1.02fn

0.01

Hz

11

t_OF2_Gen

0.10 –100.00

0.01

s

12

TrpLog_OF_Gen

0000 – 3FFFFFFF

Frequency

setting

of

under

frequency

protection stage 1. The sum of delay setting of under frequency protection stage 1. Frequency

setting

of

under

frequency

protection stage 2. Delay of under frequency protection stage 2. Frequency

setting

of

under

frequency

protection stage 3. Delay of under frequency protection stage 3. Tripping output logic setting of under frequency

1

1

Description

protection. Frequency setting of over frequency protection stage 1. Delay of over frequency protection stage 1. Frequency setting of over frequency protection stage 2. Delay of over frequency protection stage 2. Tripping output logic setting of over frequency protection.


En_Alm_UF1_Gen

0/1

Logic settings of disable(0) or enable(1) alarm function of under frequency protection stage1. Logic settings of disable(0) or enable(1)

14

En_Trp_UF1_Gen

0/1

tripping function of under frequency protection stage1.

15

En_Alm_UF2_Gen

0/1


16

En_Trp_UF2_Gen

0/1


17

En_Alm_UF3_Gen

0/1


18

En_Trp_UF3_Gen

0/1


19

En_Alm_OF1_Gen

0/1

Logic settings of disable(0) or enable(1) alarm function of over frequency protection stage1.

7-46


7 Settings Logic settings of disable(0) or enable(1) 20

En_Trp_OF1_Gen

0/1

tripping function of over frequency protection stage1.

21

En_Alm_OF2_Gen

Logic settings of disable(0) or enable(1) alarm

0/1

function of over frequency protection stage2. Logic settings of disable(0) or enable(1)

22

En_Trp_OF2_Gen

0/1

tripping function of over frequency protection stage2.



Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> GenFreqProt Settings

7.4.15 Settings of Startup and Shutdown Protection of Generator 

Setting List Table 7.4-15 List of startup and shutdown protection settings of generator

No.

Symbol

Range

Step

Unit

Description Frequency

1

f_UF_StShut_Gen

0.80fn – 1.00fn

0.01

Hz

setting

for

blocking

startup and shutdown protection of generator. Differential current setting for the

2

I_GenDiff_StShut_Gen

0.10 – 10.00

0.01

Ie

differential protection of generator in startup and shutdown condition. Tripping output logic setting of low

3

TrpLog_GenDiff_StShut_Gen

00-3FFFFFFF

frequency differential protection of

1

generator in startup and shutdown condition. Residual voltage setting of stator

4

V_StaROV_StShut_Gen

5.00 – 25.00

0.01

V

earth fault protection in startup and shutdown condition.

5

t_StaROV_StShut_Gen

0.00 – 10.00

0.01

S

Delay of stator earth fault protection in startup and shutdown condition. Tripping output logic setting of

6

TrpLog_StaROV_StShut_Gen

00-3FFFFFFF

1

stator

earth

fault

protection

in

startup and shutdown condition. Current 7

I_OC_StShut_Gen

0.10 – 100.00

0.01

A

setting

of

overcurrent

protection in startup and shutdown condition. 1.1~1.3 times of rated current is recommended.

8

t_OC_StShut_Gen

0.00 – 10.00

9

TrpLog_OC_StShut_Gen

00–3FFFFFFF

0.01 1


S

Time delay of overcurrent protection in startup and shutdown condition. Tripping output logic setting of

7-47 Date: 2013-07-04

7 Settings overcurrent protection in startup and shutdown condition. Logic setting ―1‖ - enable, ―0‖ – disable Logic settings of disable(0) or 10

En_GenDiff_StShut_Gen

enable(1)

0/1

differential

current

protective element of generator in startup and shutdown condition. Logic settings of disable(0) or

11

En_StaROV_StShut_Gen

enable(1) low frequency residual

0/1

voltage protective element of stator in startup and shutdown condition. Logic settings of disable(0) or

12

En_GenCur_StShut_Gen

enable(1)

0/1

low

frequency

overcurrent element in startup and shutdown condition. Logic settings of selecting residual voltage:

13

Opt_U0

0/1

0: residual voltage at generator terminal. 1: residual voltage at neutral point.



Setting Explanation

1.

[f_UF_StShut_Gen]

This is the frequency setting for blocking startup and shutdown protection of generator. Startup and shutdown protection is used for earth fault and phase-to-phase fault of stator during low speed operation of the generator. Its algorithm is insensitive to variation of frequency. This protection is auxiliary protection of generator during low frequency operation. Blocking setting of this protection is 0.8 – 0.9 times of rated frequency. 2.

[I_GenDiff_StShut_Gen]

This is the differential current setting for the differential protection of generator in startup and shutdown condition. Setting of this protection shall be higher than unbalance differential current in full load and rated frequency condition,

I op  Krel Iunb

Equation 7.4-39

Where:

K rel is reliability factor, 1.30 – 1.50 generally;

I unb is the unbalance differential current in full load and rated frequency condition. 3.

[V_StaROV_StShut_Gen]

7-48


7 Settings

This is the residual voltage setting of stator earth fault protection in startup and shutdown condition. For earth fault, residual voltage derived from neutral point is adopted as criterion with setting 10 V in general. 4.

[t_StaROV_StShut_Gen]

This is the delay of stator earth fault protection in startup and shutdown condition. It should be not shorter than delay of fundamental residual voltage earth fault protection for stator. 

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> GenStShutProt Settings

7.4.16 Settings of Inadvertent Energization Protection of Generator 

Setting List Table 7.4-16 List of accidental energaization protection settings of generator

No.

Symbol

Range

Step

Unit

1

f_UF_AccEnerg_Gen

0.80fn – 1.00fn

0.01

Hz

2

I_OC_AccEnerg_Gen

0.10–100.00

0.01

A

3

V_UV_AccEnerg_Gen

6.00-80.00

0.01

V

4

t_AccEnerg_Gen

0.00 – 1.00

0.01

s

5

TrpLog_AccEnerg_Gen

00-3FFFFFFF

1

Description Frequency setting for blocking accident energization protection of generator. Current setting of accident energization overcurrent protection. Voltage setting of accident energization protection. 12V is recommended. Delay

of

accident

energization

overcurrent protection. Tripping output logic setting of accident energization overcurrent protection.


En_CB_Ctrl_AccEnerg_Gen

0/1

breaker

position

auxiliary

contact

blocking function. Logic option of accident energization 7

Opt_Logic_AccEnerg_Gen

protection.

0/1

―0‖, standard edition ―1‖, special edition



Setting Explanation

1.

[I_OC_AccEnerg_Gen]

This is the current setting of accident energization overcurrent protection. Current setting shall be 50% of minimum accidental closing current (generator terminal side) during process of generator starting up but having not been excited. If accidental closing current of


7-49 Date: 2013-07-04

7 Settings

circuit breaker on auxiliary transformer side shall be taken into account, current setting shall base on minimum accidental closing current during this condition. The current used for this setting is derived from the CT at the terminal of generator. In general, this setting shall be in excess of 1.3 times of rated current of generator. 2.

[I_NegOC_Flash_CB_HVS_Tr]

This is the negative sequence current setting of breaker flashover protection. This setting shall be higher than possible unbalance current during normal operation. It must be set according to the secondary current of the CT at the HV side of main transformer. 3.

[TrpLog_Flash11_CB_HVS_Tr]

This is the tripping output logic setting of breaker flashover protection with time delay 1. If impulse current may be higher than capacity of circuit breaker during asynchronous closing, the protection shall shut off the excitation firstly. If current passing through circuit breaker is lower than permissive value, the protection can trip the circuit breaker on outlet. Permissive tripping current of circuit breaker shall be configured as that provided by factory. 4.


This is the setting to enable or disable breaker position auxiliary contact blocking function. If asynchronous unwanted closing is considered, breaker position contact blocking shall be selected. 

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> GenAccEnergProt Settings

7.4.17 Settings of Breaker Failure Protection of Generator 

Setting List Table 7.4-17 List of breaker failure protection settings of generator

No.

Symbol

Range

Step

Unit

1

I_ OC_BFP_GCB

0.10 –20.00

0.01

A

2

I_NegOC_BFP_GCB

0.10 –20.00

0.01

A

Description Phase overcurrent setting of generator breaker failure protection. Negative-sequence current setting of generator breaker failure protection. Time delay 1 of generator breaker

3

t_BFP11_GCB

0.00– 10.00

0.01

s

failure protection. It should be long than tripping time of the breaker, takes 0.3~0.5s.

4

TrpLog_BFP11_GCB

003FFFFFFF

1

7-50

Tripping

output

logic

setting

of

generator breaker failure protection


7 Settings with time delay 1. 5

t_BFP12_GCB

6

0.00– 10.00

s

Time delay 2 of generator breaker failure protection. Tripping

00-

TrpLog_BFP12_GCB

0.01

3FFFFFFF

1

output

logic

setting

of

generator breaker failure protection with time delay 2.

Logic setting ―1‖ – enable, ―0‖ – disable Logic 7

En_NegOC_BFP_GCB

settings

of

disable(0)

or

enable(1) generator breaker failure

0/1

protection

being

blocked

by

negative-sequence current element. Logic 8

En_OC_BFP_GCB

settings

of

disable(0)

or


0/1

protection being blocked by phase current element. Logic

9

En_CB_Ctrl_BFP_GCB

settings

of

disable(0)

or


0/1

protection

being

blocked

by

the

position of circuit breaker.



Setting Explanation

1.

[I_BFP_GCB]

This is phase current setting of generator breaker failure protection. It should be larger than rated current of generator.

I op 

K rel I gn K r na

Equation 7.4-40

Where:

I OP is the setting [I_BFP_GCB].

K rel is reliability factor, takes 1.1~1.3; K r is release factor, takes 0.90~0.95;

I gn is secondary rated current of generator. na is CT ratio. 2.

[I_NegOC_BFP_GCB]

This is the negative-sequence current setting of generator breaker failure protection. It should be larger than maximum unbalance negative sequence current under normal operating condition.


7-51 Date: 2013-07-04

7 Settings

I 2 op  (0.1 ~ 0.2) 

I gn

Equation 7.4-41

na

Access Path

Access path in menu is: Main Menu -> Settings -> GenProt Settings -> BfgGCBProt Settings

7.4.18 Settings of Differential Protection of Excitation Transformer or Exciter 

Setting List Table 7.4-18 List of differential protection settings of excitation transformer or exciter

No.

Symbol

Range

Step

Unit

Description Current

1

I_Pkp_PcntDiff_Exc

0.10 –1.00

0.01

Ie

setting

percentage

of

pickup

differential

value

current

of of

excitation transformer or exciter. 2

I_InstDiff_Exc

4.00 – 14.00

0.01

Ie

3

I_AlmDiff_Exc

0.05 – 1.00

0.01

Ie

4

Slope1_PcntDiff_Exc

0.05– 0.15

0.01

5

Slope2_PcntDiff_Exc

0.40 – 0.80

0.01

6

k_Harm_PcntDiff_Exc

0.10 – 0.35

0.01

Current

setting

of

unrestrained

instantaneous differential protection. Differential

current

alarm

setting

of

excitation transformer or exciter. Restraint coefficient of the first slope of the differential characteristic curve. Maximum value of restraint coefficient of the differential characteristic curve. Restraint coefficient of second harmonics Tripping output logic setting of differential

7

TrpLog_Diff_Exc

00-3FFFFFFF

1

protection of excitation transformer of exciter.


En_InstDiff_Exc

unrestrained instantaneous differential

0/1

protection of excitation transformer or exciter. Logic settings of disable(0) or enable(1)

9

En_PcntDiff_Exc

0/1

percentage

differential

protection

of

excitation transformer or exciter. Logic setting of selecting criterion of Inrush current detection 10

Opt_Inrush_Ident_Exc

―0‖, discrimination by harmonics;

0/1

―1‖, discrimination by waveform distortion criterion

7-52


7 Settings Logic

setting

percentage

of

selecting

differential

whether

protection

is

controlled during CT circuit failure 11

Opt_CTS_Blk_PcntDiff_Exc

―0‖:

0/1

alarm

will

be

issued

but

the

protection will not be blocked ―1‖: the protection will be blocked and alarm will be issued.



Setting Explanation

1.

[I_Pkp_PcntDiff_Exc]

This is the setting of pickup value of percentage differential current of excitation transformer or exciter. In practice, for excitation transformer, characteristic of CT on two sides may differ significantly and the unbalance differential current may be larger than that of main transformer. So for pickup setting, larger than 0.5 Ie is recommended. 2.

[I_AlmDiff_Exc]

This is the differential current alarm setting of excitation transformer or exciter. It shall be higher than normal unbalance differential current and lower than [I_Pkp_PcntDiff_Exc]. 

Access Path

Access path in menu is: Main Menu -> Settings -> ExcProt Settings -> ExcDiffProt Settings

7.4.19 Settings of Backup Protection of Excitation Transformer or Exciter 

Setting List Table 7.4-19 List of backup protection settings of excitation transformer or exciter

No.

Symbol

Range

Step

Unit

1

I_OC1_Exc

0.10 – 100.00

0.01

A

2

t_OC1_Exc

0.00 – 10.00

0.01

S

3

TrpLog_OC1_Exc

00- 3FFFFFFF

1

4

I_OC2_Exc

0.10 – 100.00

0.01

A

5

t_OC2_Exc

0.00 – 25.00

0.01

S

6

TrpLog_OC2_Exc

00 - 3FFFFFFF

1

Description Current

setting

of

definite

time

overcurrent protection stage1. Delay of definite time overcurrent protection stage1. Tripping output logic setting of definite time overcurrent protection. Current

setting

of

definitive

time

overcurrent protection stage2. Delay of definite time overcurrent protection stage2. Tripping output logic setting of definite time overcurrent protection stage2.


Opt_CT_OC_Exc

0/1

Logic setting of CT selection for


7-53 Date: 2013-07-04

7 Settings overcurrent

protection

of excitation

transformer or exciter ―0‖: CT of HV side ―1‖: CT of LV side



Access Path

Access path in menu is: Main Menu -> Settings -> ExcProt Settings -> ExcBakProt Settings

Note! The current used in the overcurrent protection is derived from the CT at the HV side of excitation transformer or the CT at the neutral point of exciter.

7.4.20 Settings of Overload Protection of Excitation Transformer or Exciter 

Setting list Table 7.4-20 List of overload protection settings of exciter

No.

Symbol

Range

Step

Unit

Description

1

I_Alm_OvLd_RotWdg

0.10 –100.00

0.01

A

Current setting of overload alarm.

2

t_Alm_OvLd_RotWdg

0.00 – 25.00

0.01

S

Delay of overload alarm.

3

I_InvOvLd_RotWdg

0.10 – 50.00

0.01

A

4

tmin_InvOvLd_RotWdg

0.10 – 10.00

0.01

S

5

A_Therm_RotWdg

1.00 – 100.00

0.01

6

Ib_InvOvLd_RotWdg

0.10 – 50.00

0.01

7

TrpLog_InvOvLd_RotWdg

0000- 3FFFFFFF

Pickup current of inverse time overload protection. Delay of upper limit of inverse time overload protection. Thermal capacity parameter of excitation winding.

A

1

Reference

current

setting

of

inverse time overload. Tripping output logic setting of inverse time overload protection.

Logic setting ―1‖ - enable, ―0‖ – disable Logic setting of CT selection for overload protection of excitation 8

Opt_CT_OvLd_RotWdg

0/1

transformer or exciter. ―0‖: CT of side 1. ―1‖: CT of side 2.



Setting Explanation

1.

[I_Alm_OvLd_RotWdg]

This is the current setting of overload alarm.

7-54


7 Settings

It should make inverse time overload protection dropoff reliably under normal rated excitation current. If the protection is configured at AC side, the current setting will be (rated excitation current I fd should be converted into RMS value of AC side, if bridge-type uncontrollable rectifier is adopted, I grn  0.816 I fd ):

I op 

I grn Kr

 K rel

Equation 7.4-42

Where:

K rel is reliability factor, takes 1.05; K r is release factor, takes 0.85~0.95;

I grn is secondary rated excitation current of generator. 2.

[I_InvOvLd_RotWdg]

Pickup current of inverse time overload protection. It should coordinate with definite time overload protection.

I OP. min  K c 0 K rel

I grn Kr

Where:

K co is coordination factor, takes 1.05. 

Access Path

Access path in menu is: Main Menu -> Settings -> ExcProt Settings -> RotWdgOvLdProt Settings

7.4.21 Settings of Mechanical Protection 

Setting List Table 7.4-21 List of mechanical protection settings

No.

Symbol

Range

1

t_MR1

0.00 – 300.0

2

TrpLog_MR1

0000 - 3FFFFFFF

3

t_MR2

0.00 – 300.0

4

TrpLog_MR2

0000 - 3FFFFFFF

Step

Unit

0.01

S

1

Time delay of output contact of external mechanical contact input1 repeater. Tripping output logic setting of output contact of

1

0.01

Description

mechanical contact input1. S



7-55 Date: 2013-07-04

7 Settings mechanical contact input2. 5

t_MR3

0.00 – 300.0

6

TrpLog_MR3

0000 - 3FFFFFFF

7

t_MR4

0.00 – 6000.0

8

TrpLog_MR4

0000 - 3FFFFFFF

9

t_MR5

0.00 – 300.0

10

TrpLog_MR5

0000 - 3FFFFFFF

11

t_MR6

0.00 – 300.0

12

TrpLog_MR6

0000 - 3FFFFFFF

13

t_MR7

0.00 – 300.0

14

TrpLog_MR7

0000 - 3FFFFFFF

15

t_MR8

0.00 – 6000.0

16

TrpLog_MR8

0000 - 3FFFFFFF



Access Path

0.01

S

mechanical contact input3 repeater. Tripping output logic setting of output contact of

1

mechanical contact input3.

0.1

S


1


0.01

S


1


0.01

S


1


0.01

S


1


0.1

1

Time delay of output contact of external

S

Time delay of output contact of external mechanical contact input8 repeater. Tripping output logic setting of output contact of mechanical contact input8.

Access path in menu is: Main Menu -> Settings -> MechRlyProt Settings -> MechRlyProt Settings

7.5 Calculated Parameters The settings listed in the following tables calculated by the RCS-985A itself automatically, they need not to be set by user. The settings are calculated according to the system parameters that user input, include primary rated currents, secondary rated currents, secondary rated voltages and correction coefficients used in all kinds of differential protection relays. Listing of the calculated settings is only for reference of setting check or commission.

7.5.1 Calculated Parameters of Secondary Rated Current 

Parameters List

7-56


7 Settings Table 7.5-1 List of calculated parameters of secondary rated current No.

Symbol

Range

1

I2b_SnGen_CT_Term_Gen

0-600 A

2

I2b_SnGen_CT_NP_Gen

0-600 A

3

I2b_SnExc_CT_S1_Exc

0-600 A

4

I2b_SnExc_CT_S2_Exc

0-600 A



Description Secondary rated current at terminal of generator. Secondary rated current at neutral point 1 of generator. Secondary rated current at HV side of excitation transformer or terminal side of exciter. Secondary rated current at LV side of excitation transformer or neutral point side of exciter.

Access Path

Access path in menu is: Main Menu -> Measurement -> Measurement2 -> Cal Settings -> Sec Rated Curr Values

7.5.2 Calculated Parameters of Secondary Rated Voltage 

Parameters List Table 7.5-2 List of calculated parameters of secondary rated voltage No.

Symbol

Range

1

U2b_VT_Term_Gen

0-600 V

2

U2b_DeltVT_Term_Gen

0-600 V

3

U2b_NP_Gen

0-600 V

Description Secondary rated voltage at terminal VT of generator. Secondary rated voltage of delta VT at terminal of generator. Secondary rated voltage at neutral point VT of generator. The ratio of residual voltage between terminal and

4

k_DeltVT_Gen

0-600 V

neutral point of generator. That is the ratio between [U2b_DeltVT_Term_Gen] to [U2b_NP_Gen].



Access Path

Access path in menu is: Main Menu -> Measurement -> Measurement2 -> Cal Settings -> Sec Rated Volt Values

7.5.3 Calculated Parameters of Differential Coefficient 

Parameters List Table 7.5-3 List of calculated parameters of differential coefficient

No.

Symbol

Range

1

k_Term_Diff_Gen

0-60

2

k_NP_Diff_Gen

0-60

3

k_S1_Diff_Exc

0-60

Description Differential coefficient of terminal of generator for differential protection of generator. Differential coefficient of neutral point side of generator for differential protection of generator. Differential coefficient of side 1 of exciter for


7-57 Date: 2013-07-04

7 Settings differential protection of exciter. 4



k_S2_Diff_Exc

0-60

Differential coefficient of side 2 of exciter for differential protection of exciter.

Access Path

Access path in menu is: Main Menu -> Measurement -> Measurement2 -> Cal Settings -> Diff Corr Coef

7-58


8 Human Machine Interface

8 Human Machine Interface Table of Contents 8 Human Machine Interface .............................................................. 8-a 8.1 Overview .......................................................................................................... 8-1 8.1.1 Keypad Operation ................................................................................................................ 8-2 8.1.2 LED Indications.................................................................................................................... 8-3 8.1.3 Front Communication Port................................................................................................... 8-4 8.1.4 Ethernet Port Setup ............................................................................................................. 8-4

8.2 Menu Tree ........................................................................................................ 8-5 8.2.1 Overview .............................................................................................................................. 8-5 8.2.2 Main Menus ......................................................................................................................... 8-6 8.2.3 Sub Menus........................................................................................................................... 8-8

8.3 LCD Display ................................................................................................... 8-18 8.3.1 Overview ............................................................................................................................ 8-18 8.3.2 Normal Display .................................................................................................................. 8-18 8.3.3 Display Disturbance Records ............................................................................................ 8-19 8.3.4 Display Supervision Event ................................................................................................. 8-21 8.3.5 Display IO Events .............................................................................................................. 8-21 8.3.6 Display Device Logs .......................................................................................................... 8-22

8.4 Keypad Operation ......................................................................................... 8-23 8.4.1 View Device Measurements .............................................................................................. 8-23 8.4.2 View Device Status ............................................................................................................ 8-23 8.4.3 View Device Records......................................................................................................... 8-24 8.4.4 Print Device Report ........................................................................................................... 8-24 8.4.5 View Device Setting ........................................................................................................... 8-25 8.4.6 Modify Device Setting ........................................................................................................ 8-26 8.4.7 Copy Device Setting .......................................................................................................... 8-28


8-a Date: 2013-06-29


8.4.8 Switch Setting Group ......................................................................................................... 8-29 8.4.9 Delete Device Records ...................................................................................................... 8-29 8.4.10 Modify Device Clock ........................................................................................................ 8-30 8.4.11 View Module Information ................................................................................................. 8-31 8.4.12 Check Software Version .................................................................................................. 8-31 8.4.13 Select Language .............................................................................................................. 8-31

List of Figures Figure 8.1-1 Front panel .............................................................................................................. 8-1 Figure 8.1-2 Keypad buttons ...................................................................................................... 8-2 Figure 8.1-3 LED indications ...................................................................................................... 8-3 Figure 8.1-4 Corresponding cable of the RJ45 port in the front panel .................................. 8-4 Figure 8.1-5 Rear view and terminal definition of NR1102C ................................................... 8-5 Figure 8.2-1 Menu tree ................................................................................................................ 8-7

List of Tables Table 8.1-1 Definition of the 8-core cable ................................................................................. 8-4 Table 8.3-1 User Operating event list ...................................................................................... 8-23

8-b



The operator can access the protective device from the front panel. Local communication with the protective device is possible using a computer via a multiplex RJ45 port on the front panel. Furthermore, remote communication is also possible using a PC with the substation automation system via rear RS485 port or rear Ethernet port. The operator is able to check the protective device status at any time. This chapter describes human machine interface (HMI), and give operator an instruction about how to display or print event report, setting and so on through HMI menu tree and display metering value, including R.M.S. current, voltage, etc. through LCD. Procedures to change active setting group or a settable parameter value through keypad are also described in details.

8.1 Overview The human-machine interface consists of a human-machine interface (HMI) module which allows a communication to be as simple as possible for the user. The HMI module helps to draw your attention to something that has occurred which may activate a LED or a report displayed on the LCD. Operator can locate the data of interest by navigating the keypad.

5 11 12

3

13

4

14

5

15

ENT

17

8

18

9

19

10

20

C

16

7

ES

6

PCS-985 GENERATOR RELAY GR P

1 2

1

3

4

2

Figure 8.1-1 Front panel

The function of HMI module: No.

Item

Description A 320×240 dot matrix backlight LCD display is visible in dim lighting

1

LCD

conditions. The corresponding messages are displayed when there is operation implemented.


8-1 Date: 2013-06-29

8 Human Machine Interface 2

LED

20 status indication LEDs, 7 LEDs are used

3

Keypad

Navigation keypad and command keys for full access to device

4

Communication port

a multiplex RJ45 port for local communication with a PC

5

Logo

Type and designation and manufacturer of device

8.1.1 Keypad Operation

GR P ENT

ESC

Figure 8.1-2 Keypad buttons

1.

2.

3.

“ESC”: 

Cancel the operation



Quit the current menu

“ENT”: 

Execute the operation



Confirm the interface

“GRP” 

4.

5.

6.

Activate the switching interface of setting group

leftward and rightward direction keys (“◄” and “►”): 

Move the cursor horizontally



Enter the next menu or return to the previous menu

upward and downward direction keys (“▲” and “▼”) 

Move the cursor vertically



Select command menu within the same level of menu

plus and minus sign keys (“＋” and “－”) 

Modify the value



Modify and display the message number



Page up/down

8-2



8.1.2 LED Indications HEALTHY ALARM TRIP VT ALARM CT ALARM STA EF ALARM ROT EF ALARM

Figure 8.1-3 LED indications

A brief explanation has been made as bellow. LED

Display Off

HEALTHY Steady Green Off

Description When the equipment is out of service or any hardware error is defected during self-check. Lit when the equipment is in service and ready for operation. When equipment in normal operating condition.

ALARM Steady Yellow Off

Lit when other abnormal alarm is issued. When equipment in normal operating condition.

TRIP Steady Red Off

VT ALARM

Steady Yellow Off

CT ALARM

Steady Yellow

STA EF

Off

ALARM

Steady Yellow

ROT EF

Off

ALARM

Steady Yellow

Lit when the relay operates to trip When equipment in normal operating condition. Lit when VT circuit fails When equipment in normal operating condition. Lit when CT circuit fails When equipment in normal operating condition. Lit when stator earth-fault happens When equipment in normal operating condition. Lit when rotor earth-fault happens

Note!

“HEALTHY” LED can only be turned on by energizing the device and no abnormality detected.


8-3 Date: 2013-06-29


8.1.3 Front Communication Port There is a multiplex RJ45 port on the front panel. This port can be used as an RS-232 serial port as well as a twisted-pair ethernet port. As shown in the following figure, a customized cable is applied for debugging via this multiplex RJ45 port.

Figure 8.1-4 Corresponding cable of the RJ45 port in the front panel

In the above figure and the following table: P1: To connect the multiplex RJ45 port. An 8-core cable is applied here. P2: To connect the twisted-pair ethernet port of the computer. P3: To connect the RS-232 serial port of the computer. The definition of the 8-core cable in the above figure is introduced in the following table. Table 8.1-1 Definition of the 8-core cable Terminal No.

Core color

Function

Device side

Computer side

(Left)

(Right)

1

Orange

TX+ of the ethernet port

P1-1

P2-1

2

Orange & white

TX- of the ethernet port

P1-2

P2-2

3

Green & white

RX+ of the ethernet port

P1-3

P2-3

4

Blue

TXD of the RS-232 serial port

P1-4

P3-2

5

Brown & white

RTS of the RS-232 serial port

P1-5

P3-3

6

Green

RX- for the ethernet port

P1-6

P2-6

7

Blue & white

The ground connection of the RS-232 port.

P1-7

P3-5

8.1.4 Ethernet Port Setup MON plug-in module is equipped with two or four 100Base-TX Ethernet interface, take NR1102C as an example, as shown in Figure 8.1-5. Its rear view and the definition of terminals. The Ethernet port can be used to communication with PC via auxiliary software (PCS-PC) after connecting the protection device with PC, so as to fulfill on-line function (please refer to the instruction manual of PCS-PC). At first, the connection between the protection device and PC must be established. Through setting the IP address and subnet mask of corresponding Ethernet interface in the menu “Settings→Device Setup→Comm Settings”, it should be ensured that the 8-4



protection device and PC are in the same network segment. For example, setting the IP address and subnet mask of network A. (using network A to connect with PC) PC: IP address is set as “198.87.96.102”, subnet mask is set as “255.255.255.0” The IP address and subnet mask of protection device should be [IP_LAN1]= 198.87.96.XXX, [Mask_LAN1]=255.255.255.0, [En_LAN1]=1. (XXX can be any value from 0 to 255 except 102) If the logic setting [En_LAN1] is non-available, it means that network A is always enabled.

NR1102C

ETHERNET

Network A

Network B

SYN+ SYNSGND RTS TXD SGND

Figure 8.1-5 Rear view and terminal definition of NR1102C

Note! If using other Ethernet port, for example, Ethernet B, the logic setting [En_LAN2] must be set as “1”.

8.2 Menu Tree 8.2.1 Overview Press “▲” of any running interface and enter the main menu. Select different submenu by “▲” and “▼”. Enter the selected submenu by pressing “ENT” or “►”. Press “◄” and return to the previous menu. Press “ESC” back to main menu directly. For sake of entering the command menu again, a command menu will be recorded in the quick menu after its execution. Five latest command menus can be recorded in the quick menu. When five command menus are recorded, the latest command menu will cover the earliest one, adopting the “first in first out” principle. It is arranged from top to bottom and in accordance with the execution order of command menus. PCS-985G Generator Relay

8-5 Date: 2013-06-29


Press “▲” to enter the main menu with the interface as shown in the following diagram:

MainMenu

Language Clock Quick Menu

For the first powered protective device, there is no record in quick menu. Press “▲” to enter the main menu with the interface as shown in the following diagram:

Measurements Status Records Print Settings Local Cmd Information Test Clock Language

The descriptions about menu is based on the maximized configuration, for a specific project, if some function is not available, the corresponding submenu will hidden.

8.2.2 Main Menus The menu of the PCS-985 is organized into main menu and submenus, much like a PC directory structure. The menu of the PCS-985 is divided into 10 sections:

8-6


8 Human Machine Interface Main Menu Measurements Status Records Print Settings Local Cmd Information Test Clock Language

Figure 8.2-1 Menu tree

Under the main interface, press “▲” to enter the main menu, and select submenu by pressing “▲”, “▼” and “ENT”. The command menu adopts a tree shaped content structure. The above diagram provides the integral structure and all main menus under menu tree of the protection device.


8-7 Date: 2013-06-29


8.2.3 Sub Menus 8.2.3.1 Measurements Main Menu

Measurements

Measurements1

Gen Values1 Exc Values1 Measurements2 Gen Values2 Exc Values2 Phase Angle Prot Status Cal Settings

This menu is used to display real-time measured values, including AC voltage, AC current, phase angle and calculated quantities. These data can help users to acquaint the device′s status. This menu comprises following submenus. Please refer to Chapter 5 about the detailed measured values. No.

Item

Function description

1

Measurement1

Display measured values from protection calculation DSP

2

Measurement2

Display sampled values from fault detector DSP

The submenu “Measurement1” comprises the following command menus. No.

Item


1

Gen Values

Display measured values of generator

2

Exc Values

Display measured values of excitation transformer or exciter

The submenu “Gen Values” comprises the following command menus.

1)

No.

Item


1

Gen Diff Values

Display measured differential current values of generator

2

Gen Volt Values

Display measured voltage values of generator

3

Gen Misc Values

Display measured miscellaneous values of generator

The submenu “Measurement2” comprises the following command menus. 8-8


8 Human Machine Interface No.

Item


1

Gen Values

Display measured values of generator

2

Exc Values

Display measured values of excitation transformer or exciter

3

Phase Angle

Display measured phase angle

4

Prot Status

Display status related to each protection element

5

Cal Settings

Display calculated settings

The submenu “Gen Values” comprises the following command menus.

1)

No.

Item


1

Gen Diff Values

Display measured differential current values of generator

2

Gen Volt Values

Display measured voltage values of generator

3

Gen Misc Values

Display measured miscellaneous values of generator

The submenu “Phase Angle” comprises the following command menus.

2)

No.

Item

1

Gen PhaseAngle Values

2

Exc PhaseAngle Values

Function description Display measured phase angle related to generator Display measured phase angle related to excitation transformer or exciter

The submenu “Prot Status” comprises the following command menus.

3)

No.

Item

Function description Display

status

of

some

elements

which

are

enabled/disabled

1

Prot On/Off Status Values

2

Gen Prot CalValues

Display calculated values related to generator

3

Exc Prot CalValues

Display calculated values related to excitation transformer or exciter

automatically

The submenu “Cal Settings” comprises the following command menus.

4)

No.

Item


1

Sec Rated Curr Values

Display calculated settings of secondary rated current

2

Sec Rated Volt Values

Display calculated settings of secondary rated voltage

3

Diff Corr Coef Values

Display calculated settings of differential coefficient


8-9 Date: 2013-06-29


8.2.3.2 Status Main Menu

Status

Prot BI

Gen Prot BI Exc Prot BI MR Prot BI Misc BI Pwr Superv BI Outputs

Contact Outputs Prot FD

This menu is used to display real time input signals and output signals of the device. These data can help users to acquaint the device′s status. This menu comprises following submenus. Please refer to “section 5.3” about the detailed input and output signals. No.

Item


1

Prot BI

Display all input signal states

2

Outputs

Display all output signal states

The submenu “Prot BI” comprises the following command menus. No.

Item


1

Gen Prot BI

Display states of binary inputs related to generator

2

Exc Prot BI

Display states of binary inputs related to excitation transformer or exciter

3

MR Prot BI

Display states of binary inputs related to mechanical protection

4

Misc BI

Display states of binary inputs related to miscellaneous protection

5

Pwr Superv BI

Display states of binary inputs of power supply supervision

The submenu “Outputs” comprises the following command menus. No.

Item


1

Contact Outputs

Display states of contact binary outputs

2

Prot FD

Display states of fault detectors

8-10



8.2.3.3 Records Main Menu

Records

Disturb Records Superv Events IO Events Device Logs

This menu is used to display all kinds of records, including the disturbance records, supervision events, binary events and device logs, so that the operator can load to view and use as the reference of analyzing accidents and repairing the device. All records are stored in non-volatile memory, it can still record them even if it loses its power. This menu comprises the following submenus. No.

Item


1

Disturb Records

Display disturbance records of the device

2

Superv Events

Display supervision events of the device

3

IO Events

Display binary events of the device

4

Device Logs

Display device logs of the device


8-11 Date: 2013-06-29


8.2.3.4 Print Main Menu

Print

Device Info Settings

General Settings GenProt Settings ExcProt Settings MiscProt Settings Logic Links Device Setup All Settings Latest Chgd Settings Disturb Records Superv Events IO Events Device Status Waveforms IEC103 Info Cancel Print

This menu is used to print device description, settings, all kinds of records, waveform, and information related to IEC60870-5-103 protocol. This menu comprises the following submenus. No.

Item

1

Device Info

2

Settings

Function description Print the description information of the device, including software version. Print device setup, general settings, logic links and protection settings. It can print by different classifications as well as printing all settings of the device. Besides, it can also print the latest modified settings.

3

Disturb Records

Print the disturbance records

4

Superv Events

Print the supervision events

5

IO Events

Print the binary events

8-12



Device Status

7

Waveforms

Print the current state of the device, including the sampled value of voltage and current, the state of binary inputs, setting and so on Print the recorded waveform Print 103 Protocol information,

8

IEC103 Info

including function type

(FUN),

information serial number (INF), general classification service group number, and channel number (ACC)

9

Cancel Print

Cancel the print command

The submenu “Settings” comprises the following submenus. No.

Item


1

General Settings

Print the general settings

2

GenProt Settings

Print generator protection settings

3

ExcProt Settings

Print settings related to excitation transformer or exciter

4

MiscProt Settings

Print misc protection settings

5

Logic Links

Print logic links

6

Device Setup

Print the settings related to device setup

7

All Settings

8

Latest Modified

Print all settings including device setup, system settings and protection settings Print the setting latest modified

The submenu “General Settings” comprises the following command menus.

1)

No.

Item


1

System Settings

Print system settings

2

Enable Settings

Print logic settings of configuring functions

3

TrSys Settings

Print system settings related to main transformer

4

GenSys Settings

Print system settings related to generator

5

ExcSys Settings

Print system settings related to excitation transformer or exciter

6

Config Settings

Print configuration settings

The submenu “GenProt Settings” comprises the following command menus.

2)

No.

Item


1

GenDiffProt Settings

Print settings of differential protection of generator

2

GenIntTurnProt Settings

Print settings of turn-to-turn fault protection of generator

3

GenPPFBakProt Settings

Print settings of backup protection of generator

4

StaEFProt Settings

Print settings of earth fault protection of stator windings

5

RotWdgEFProt Settings

Print settings of earth fault protection of rotor

6

StaOvLdProt Settings

Print settings of thermal overload protection of stator

7

GenNegOCProt Settings

Print settings of negative sequence overcurrent protection of generator


8-13 Date: 2013-06-29


LossExcProt Settings

Print settings of Loss-of-Excitation protection

9

GenOOSProt Settings

Print settings of out-of-step protection

10

GenVoltProt Settings

Print settings of voltage protection of generator

11

GenOvExcProt Settings

Print settings of overexcitation protection of generator

12

GenPwrProt Settings

Print settings of power protection of generator

13

GenFreqProt Settings

14

StShutProt Settings

Print settings of startup and shutdown protection of generator

15

AccEnergProt Settings

Print settings of inadvertent energization protection of generator

16

BFPGCBProt Settings

Print settings of breaker failure protection of generator

Print settings of underfrequency and overfrequency protection of generator

The submenu “ExcProt Settings” comprises the following command menus.

3)

No.

Item


1

ExcDiffProt Settings

Print settings of differential protection of excitation transformer or exciter

2

ExcBakProt Settings

Print settings of backup protection of excitation transformer or exciter

3

RotWdgOvLdProt Settings

Print settings of overload protection of excitation transformer or exciter

The submenu “MiscProt Settings” comprises the following command menus.

4)

No. 1

Item MechRlyProt Settings

Function description Print mechanical protection settings

The submenu “Logic Links” comprises the following command menus. No. 1

Item Function Links

Function description Print function links

The submenu “Device Setup” comprises the following command menus. No.

Item


1

Device Settings

Print the device settings.

2

Comm Settings

Print the communication settings.

The submenu “Waveforms” comprises the following command menus. No.

Item


1

Gen Diff Wave

Print differential current waveforms of generator

2

Gen Volt Wave

Print voltage waveforms of generator

3

Gen Misc Wave

Print miscellaneous waveforms of generator

4

Exc Curr Wave

Print current waveforms of excitation

8-14



8.2.3.5 Settings Main Menu

Settings

General Settings GenProt Settings ExcProt Settings MiscProt Settings Logic Links Device Setup Copy Settings

This menu is used to check the device setup, general settings, logic links and protection settings, as well as modifying any of the above setting items. Moreover, it can also execute the setting copy between different setting groups. This menu comprises the following submenus. No.

Item


1

General Settings

Check or modify the general settings

2

GenProt Settings

Check or modify generator protection settings

3

ExcProt Settings

Check or modify settings related to excitation transformer or exciter

4

MiscProt Settings

Check or modify misc protection settings

5

Logic Links

Check or modify logic links

6

Device Setup

Check or modify settings related to device setup

7

Copy Settings

Copy setting between different setting groups

The submenu “General Settings” comprises the following command menus. No.

Item


1

System Settings

Check or modify system settings

2

Enable Settings

Check or modify logic settings of configuring functions

3

TrSys Settings

Check or modify system settings related to main transformer

4

GenSys Settings

Check or modify system settings related to generator

5

ExcSys Settings

6

Config Settings

Check or modify system settings related to excitation transformer or exciter Check or modify configuration settings

The submenu “GenProt Settings” comprises the following command menus. PCS-985G Generator Relay

8-15 Date: 2013-06-29


Item


1

GenDiffProt Settings

Check or modify settings of differential protection of generator

2

GenIntTurnProt Settings

Check or modify settings of turn-to-turn fault protection of generator

3

GenPPFBakProt Settings

Check or modify settings of backup protection of generator

4

StaEFProt Settings

Check or modify settings of earth fault protection of stator windings

5

RotWdgEFProt Settings

Check or modify settings of earth fault protection of rotor

6

StaOvLdProt Settings

Check or modify settings of thermal overload protection of stator

7

GenNegOCProt Settings

8

LossExcProt Settings

Check or modify settings of Loss-of-Excitation protection

9

GenOOSProt Settings

Check or modify settings of out-of-step protection

10

GenVoltProt Settings

Check or modify settings of voltage protection of generator

11

GenOvExcProt Settings

Check or modify settings of overexcitation protection of generator

12

GenPwrProt Settings

Check or modify settings of power protection of generator

13

GenFreqProt Settings

14

StShutProt Settings

15

AccEnergProt Settings

16

BFPGCBProt Settings

Check or modify settings of negative sequence overcurrent protection of generator

Check or modify settings of underfrequency and overfrequency protection of generator Check or modify settings of startup and shutdown protection of generator Check or modify settings of inadvertent energization protection of generator Check or modify settings of breaker failure protection of generator

The submenu “ExcProt Settings” comprises the following command menus. No.

Item

1

ExcDiffProt Settings

2

ExcBakProt Settings

3

RotWdgOvLdProt Settings

Function description Check or modify settings of differential protection of excitation transformer or exciter Check or modify settings of backup protection of excitation transformer or exciter Check or modify settings of overload protection of excitation transformer or exciter

The submenu “MiscProt Settings” comprises the following command menus. No. 1

Item MechRlyProt Settings

Function description Check or modify mechanical protection settings

The submenu “Logic Links” comprises the following command menus. No. 1

Item Function Links

Function description Check or modify function links

The submenu “Device Setup” comprises the following command menus. 8-16



Item


1

Device Settings

Check or modify the device settings.

2

Comm Settings

Check or modify the communication settings.

8.2.3.6 Local Cmd Main Menu

Local Cmd

Reset Target Trig Oscillograph Download

This menu is used to reset the tripping relay with latch, indicator LED, LCD display, and as same as the resetting function of binary inputs. This menu provides a method of manually recording the current waveform data of the device under normal condition for printing and uploading SAS. Besides, it can send out the request of program download. This menu comprises the following submenus. No.

Item


1

Reset Target

Reset the local signal, indicator LED, LCD display and so on

2

Trig Oscillograph

Trigger waveform recording

3

Download

Send out the request of downloading program

8.2.3.7 Information Main Menu

Information

Version Info Board Info

In this menu, the LCD displays software information of all kinds of intelligent plug-in modules, which consists of version, creating time of software, CRC codes and management sequence number. Besides, plug-in module information can also be viewed. This menu comprises the following command menus. No.

Item

Function description Display software information of DSP module, MON module and HMI module,

1

Version Info

which consists of version, creating time of software, CRC codes and management sequence number.


8-17 Date: 2013-06-29


Board Info

Monitor the current working state of each intelligent module.

8.2.3.8 Test Main Menu

Test

Disturb Record Items DC Zero Adjust DC Zero Adjust

This menu comprises the following submenus. No.

Item


1

Disturb Record Items

Check the fault report one by one.

2

DC Zero Adjust

DC component zero drift adjustment

3

SetLCD

Detect the LCD and LED of the device

8.2.3.9 Clock The current time of internal clock can be viewed here. The time is displayed in the form YY-MM-DD and hh:mm:ss. All values are presented with digits and can be modified. 8.2.3.10 Language This menu is mainly used to set LCD display language.

8.3 LCD Display 8.3.1 Overview There are five kinds of LCD display, SLD (single line diagram) display, tripping reports, alarm reports, binary input changing reports and control reports. Tripping reports and alarm reports will not disappear until these reports are acknowledged by pressing the “RESET” button in the protection panel (i.e. energizing the binary input [BI_RstTarg]). User can press both “ENT” and “ESC” at the same time to switch the display among trip reports, alarm reports and the SLD display. IO events will be displayed for 5s and then it will return to the previous display interface automatically. Device logs will not pop up and can only be viewed by navigating the corresponding menu.

8.3.2 Normal Display After the protection device is powered and entered into the initiating interface, it takes 30 seconds to complete the initialization of protection device. During the initialization of protection device, the “HEALTHY” indicator lamp of the protection device goes out.

8-18



Under normal condition, the LCD will display the following. The LCD adopts white color as its backlight that is activated if once there is any keyboard operation, and is extinguished automatically after 60 seconds of no operation.

Addr100

2011-06-25 10:28:03

Group01

0.00A DIF: 0.00Ie DIE: 0.00Ie

0.00A 0.00V

0.00V 0.00A

0.00A

0.00A

F: 0.00 Hz P: +0.00 % Q: +0.00 % Ur: 0.0 V Rg: 300.00kΩ

0.00V

The content displayed on the screen contains: the current date and time of the protection device (with a format of yyyy-mm-dd hh:mm:ss:), the active setting group number, the three-phase current sampling value, the neutral current sampling value, the three-phase voltage sampling value, the neutral voltage sampling value, the synchronism voltage sampling value, line frequency and the address relevant to IP address of Ethernet A. If all the sampling values of the voltage and the current can’t be fully displayed within one screen, they will be scrolling-displayed automatically from the top to the bottom. If the device has detected any abnormal state, it will display the self-check alarm information.

8.3.3 Display Disturbance Records This device can store 64 disturbance records and 64 disturbance records with fault waveform. When there is protection element operating, the LCD will automatically display the latest disturbance record, and two kinds of LCD display interfaces will be available depending on whether there are supervision events at present. For the situation that the disturbance records and the supervision events coexist, the upper half part is the disturbance record, and the lower half part is the supervision event. As to the upper half part, it displays separately the record number of the disturbance record, fault name, generating time of the disturbance record (with a format of yyyy-mm-dd hh:mm:ss), protection element and tripping element. If there is protection element operation, faulty phase and relative operation time with reference to fault detector element are displayed. At the same time, if displayed rows of protection element and tripping element are more than 3, a scroll bar will appear at the right. The height of the black part of the scroll bar basically indicates the total lines of protection element and tripping element, and its position suggests the position of the currently displayed line of the total PCS-985G Generator Relay

8-19 Date: 2013-06-29


lines. The scroll bar of protection element and tripping element will roll up at the speed of one line per time. When it rolls to the last three lines, it will roll from the earliest protection element and tripping element again. The displayed content of the lower half part is similar to that of the upper half part. If the device has no the supervision event, the display interface will only show the disturbance record. Disturb Records NO.2 2011-06-25 07:10:00:200 0 ms FD_BFP_GCB 24 ms

Op_BFP_GCB

If the device has the supervision event, the display interface will show the disturbance record and the supervision event at the same time. Disturb Records NO.2 2011-06-25 07:10:00:200 0 ms FD_BFP_GCB 24 ms

Op_BFP_GCB

Superv Events NO.3 2011-06-25 07:09:00:200 Alm_BI

Disturb Records NO.2

shows the title and SOE number of the disturbance record.

2011-06-25 07:10:00:200

shows the time when fault detector picks up, the format is year–month-date and hour:minute:second:millisecond.

0ms FD_BFP_GCB

shows fault detector element and its operating time (set as 0ms

8-20



fixedly). 24ms Op_BFP_GCB

shows operation element and its relative operation time

8.3.4 Display Supervision Event This device can store 1024 pieces of supervision events. During the running of the device, the supervision event of hardware self-check errors or system running abnormity will be displayed immediately. Superv Events NO.4 2011-06-25 9:18:47:500ms Alm_BI

0

1

Superv Events NO.4

shows the SOE number and title of the supervision event

2011-06-25 09:18:47:500

shows the real time of the report: year–month-date and hour:minute:second:millisecond

Alm_BI 0→1

shows the content of abnormality alarm

8.3.5 Display IO Events This device can store 1024 pieces of binary events. During the running of the device, the binary input will be displayed once its state has changed, i.e. from “0” to “1” or from “1” to “0”.


8-21 Date: 2013-06-29


IO Events NO.4 2011-06-25 09:18:47:500ms BI_Pwr_Superv

0

1

IO Events NO.4

shows the number and title of the binary event

2011-06-25 09:18:47:500

shows date and time when the report occurred, the format is year–month-date and hour:minute:second:millisecond

BI_Pwr_Superv 0→1

shows the state change of binary input, including binary input name, original state and final state

8.3.6 Display Device Logs This device can store 1024 pieces of device logs. During the running of the device, the device log will be displayed after any operation of it is conducted. Device Logs NO.4 2011-06-25 10:18:47:569ms Reboot

Device Logs NO. 4

shows the title and the number of the device log

2011-06-25 10:18:47:569

shows date and time when the report occurred, the format is year–month-date and hour:minute:second:millisecond

8-22



Reboot

shows the manipulation content of the device log

User operating information listed below may be displayed. Table 8.3-1 User Operating event list No.

Message

Description

1

Reboot

The device has been reboot.

2

Settings_Chgd

The device′s settings have been changed.

3

ActiveGrp_Chgd

Active setting group has been changed.

4

Report_Cleared

All reports have been deleted. (Device logs can not be deleted)

5

Waveform_Cleared

All waveforms have been deleted.

6

SubProcess_Exit

A Subprocess has exited.

It will be displayed on the LCD before the fault report and self-check report are confirmed. Only pressing the restore button on the protection screen or pressing both “ENT” and “ESC” at the same time can switch among the fault report, the self-check report and the normal running state of protection device to display it. The binary input change report will be displayed for 5s and then it will return to the previous display interface automatically.

8.4 Keypad Operation 8.4.1 View Device Measurements The operation is as follows: 1.

Press the “▲” to enter the main menu;

2.

Press the “▲” or “▼” to move the cursor to the “Measurements” menu, and then press the “ENT” or “►” to enter the menu;

3.

Press the “▲” or “▼” to move the cursor to any command menu, and then press the “ENT” to enter the menu;

4.

Press the “▲” or “▼” to page up/down (if all information cannot be displayed in one display screen, one screen can display 14 lines of information at most);

5.

Press the “◄” or “►” to select pervious or next command menu;

6.

Press the “ENT” or “ESC” to exit this menu (returning to the “Measurements” menu);

8.4.2 View Device Status The operation is as follows: 1.

Press the key “▲” to enter the main menu.

2.

Press the key “▲” or “▼” to move the cursor to the “Status” menu, and then press the “ENT” or “►” to enter the menu.

3.

Press the key “▲” or “▼” to move the cursor to any command menu item, and then press the key “ENT” to enter the submenu.


8-23 Date: 2013-06-29


4.

Press the “▲” or “▼” to page up/down (if all information cannot be displayed in one display screen, one screen can display 14 lines of information at most).

5.

Press the key “◄” or “►” to select pervious or next command menu.

6.

Press the key “ENT” or “ESC” to exit this menu (returning to the “Status” menu).

8.4.3 View Device Records The operation is as follows: 1.


2.

Press the “▲” or “▼” to move the cursor to the “Records” menu, and then press the “ENT” or “►” to enter the menu;

3.


4.

Press the “▲” or “▼” to page up/down;

5.

Press the “＋” or “－” to select pervious or next record;

6.


7.

Press the “ENT” or “ESC” to exit this menu (returning to the “Records” menu);

8.4.4 Print Device Report The operation is as follows: 1.


2.

Press the “▲” or “▼” to move the cursor to the “Print” menu, and then press the “ENT” or “►” to enter the menu;

3.


4.



Selecting the “Disturb Records”, and then press the “＋” or “－” to select pervious or next record. After pressing the key “ENT”, the LCD will display “Start Printing... ”, and then automatically exit this menu (returning to the menu “Print”). If the printer doesn’t complete its current print task and re-start it for printing, and the LCD will display “Printer Busy…”. Press the key “ESC” to exit this menu (returning to the menu “Print”).



Selecting the command menu “Superv Events” or “IO Events”, and then press the key “▲” or “▼” to move the cursor. Press the “＋” or “－” to select the starting and ending numbers of printing message. After pressing the key “ENT”, the LCD will display “Start Printing…”, and then automatically exit this menu (returning to the menu “Print”). Press the key “ESC” to exit this menu (returning to the menu “Print”).

If selecting the command menu “Device Info”, “Device Status“ or “IEC103 Info”, press the key “ENT”, the LCD will display “Start printing..”, and then automatically exit this menu

8-24



(returning to the menu “Print”). 5.

If selecting the “Settings”, press the key “ENT” or “►” to enter the next level of menu.

6.

After entering the submenu “Settings”, press the key “▲” or “▼” to move the cursor, and then press the key “ENT” to print the corresponding default value. If selecting any item to printing: Press the key “＋” or “－” to select the setting group to be printed. After pressing the key “ENT”, the LCD will display “Start Printing…”, and then automatically exit this menu (returning to the menu “Settings”). Press the key “ESC” to exit this menu (returning to the menu “Settings”).

7.

After entering the submenu “Waveforms”, press the “＋” or “－” to select the waveform item to be printed and press ”ENT” to enter. If there is no any waveform data, the LCD will display “No Waveform Data!” (Before executing the command menu “Waveforms”, it is necessary to execute the command menu “Trig Oscillograph” in the menu “Local Cmd”, otherwise the LCD will display “No Waveform Data!”). With waveform data existing:

Press the key “＋” or “－” to select pervious or next record. After pressing the key “ENT”, the LCD will display “Start Printing…”, and then automatically exit this menu (returning to the menu “Waveforms”). If the printer does not complete its current print task and re-start it for printing, and the LCD will display “Printer Busy…”. Press the key “ESC” to exit this menu (returning to the menu “Waveforms”).

8.4.5 View Device Setting The operation is as follows: 1.


2.

Press the “▲” or “▼” to move the cursor to the “Settings” menu, and then press the “ENT” or “►” to enter the menu;

3.


4.

Press the “▲” or “▼” to move the cursor;

5.

Press the “+” or “-” to page up/down;

6.


7.

Press the “ESC” to exit this menu (returning to the menu “Settings”). Note! If the displayed information exceeds 14 lines, the scroll bar will appear on the right side of the LCD to indicate the quantity of all displayed information of the command menu and the relative location of information where the current cursor points at.


8-25 Date: 2013-06-29


8.4.6 Modify Device Setting The operation is as follows: 1.


2.


3.


4.

Press the “▲” or “▼” to move the cursor;

5.


6.

Press the “ESC” to exit this menu (returning to the menu “Settings” );

7.

If selecting the submenu “GenProt Settings”, and press “ENT” to enter. After selecting different command menu, the LCD will display the following interface: (take “GenDiffProt Settings” as an example) GenDiffProt Settings Please Select Group for Config Active Group:

01

Selected Group:

02

Press the “＋” or “－” to modify the value, and then press the “ENT” to enter it. Move the cursor to the setting item to be modified, press the “ENT” to enter. Take the setting [I_Pkp_PcntDiff_Gen] as an example is selected to modify, then press the “ENT” to enter and the LCD will display the following interface. is shown the “＋” or “－” to modify the value and then press the “ENT” to confirm.

8-26



I_Pkp_PcntDiff_Gen Current Value

0.30

Modified Value

0.32

Min Value

0.10

Max Value

1.50

Press the “＋” or “－” to modify the value (if the modified value is of multi-bit, press the “◄” or “►” to move the cursor to the digit bit, and then press the “＋” or “－” to modify the value), press the “ESC” to cancel the modification and return to the displayed interface of the command menu “GenDiffProt Settings”. Press the “ENT” to automatically exit this menu (returning to the displayed interface of the command menu “GenDiffProt Settings”). Move the cursor to continue modifying other setting items. After all setting values are modified, press the “◄”, “►” or “ESC”, and the LCD will display “Save or Not?”. Directly press the “ESC” or press the “◄” or “►” to move the cursor. Select the “Cancel”, and then press the “ENT” to automatically exit this menu (returning to the displayed interface of the command menu “GenDiffProt Settings”). Press the “◄” or “►” to move the cursor. Select “No” and press the “ENT”, all modified setting item will restore to its original value, exit this menu (returning to the menu “GenProt Settings”). Press the “◄” or “►” to move the cursor to select “Yes”, and then press the “ENT”, the LCD will display password input interface.

Password:

____


8-27 Date: 2013-06-29


Input a 4-bit password (“＋”, “◄”, “▲” or “－”). If the password is incorrect, continue inputting it, and then press the “ESC” to exit the password input interface and return to the displayed interface of the command menu “GenDiffProt Settings”. If the password is correct, LCD will display “Save Setting Now…”, and then exit this menu (returning to the displayed interface of the command menu “GenDiffProt Settings”), with all modified setting items as modified values. Note! For different setting items, their displayed interfaces are different but their modification methods are the same. Note! After modifying protection settings in current active setting group or system settings of the device, the “HEALTHY” indicator lamp of the device will go out, and the device will automatically restart and re-check them. If the check doesn’t pass, the device will be blocked.

8.4.7 Copy Device Setting The operation is as follows: 1.


2.


3.

Press the “▲” or “▼” to move the cursor to the command menu “Copy Settings”, and then press the “ENT” to enter the menu.

Copy Settings Active Group:

01

Copy To Group:

02

Press the “＋” or “－” to modify the value. Press the “ESC”, and return to the menu “Settings”. Press the “ENT”, the LCD will display the interface for password input, if the password is incorrect, continue inputting it, press the “ESC” to exit the password input interface and return to the menu 8-28



“Settings”. If the password is correct, the LCD will display “copy setting OK!”, and exit this menu (returning to the menu “Settings”).

8.4.8 Switch Setting Group The operation is as follows: 1.

Exit the main menu;

2.

Press the “GRP” Change Active Group

Active Group:

01

Change To Group:

02

Press the “＋” or “－” to modify the value, and then press the “ESC” to exit this menu (returning to the main menu). After pressing the “ENT”, the LCD will display the password input interface. If the password is incorrect, continue inputting it, and then press the “ESC” to exit the password input interface and return to its original state. If the password is correct, the “HEALTHY” indicator lamp of the protection device will go out, and the protection device will re-check the protection setting. If the check doesn’t pass, the protection device will be blocked. If the check is successful, the LCD will return to its original state.

8.4.9 Delete Device Records The operation is as follows: 1.

Exit the main menu;

2.

Press the “＋”, “－”, “＋”, “－” and “ENT”; Press the “ESC” to exit this menu (returning to the original state). Press the “ENT” to carry out the deletion.


8-29 Date: 2013-06-29


Press To Clear Press To Exit

Note! The operation of deleting device message will delete all messages saved by the protection device, including disturbance records, supervision events, binary events, but not including device logs. Furthermore, the message is irrecoverable after deletion, so the application of the function shall be cautious.

8.4.10 Modify Device Clock The operation is as follows: 1.


2.

Press the “▲” or “▼” to move the cursor to the “Clock” menu, and then press the “ENT” to enter clock display

3.

Press the “▲” or “▼” to move the cursor to the date or time to be modified;

4.

Press the “+” or “-” to modify value, and then press the “ENT” to save the modification and return to the main menu;

5.

Press the “ESC” to cancel the modification and return to the main menu.

8-30



Clock Year

2008

Month

11

Day

28

Hour

20

Minute

59

Second

14

8.4.11 View Module Information The operation is as follows: 1.


2.

Press the “▲” or “▼” to move the cursor to the “Information” menu, and then press the “ENT” or “►” to enter the menu;

3.

Press the “▲” or “▼” to move the cursor to the command menu “Board Info”, and then press the “ENT” to enter the menu;

4.

Press the “▲” or “▼” to move the scroll bar;

5.

Press the “ENT” or “ESC” to exit this menu (returning to the “Information” menu).

8.4.12 Check Software Version The operation is as follows: 1.

Press the “▲” to enter the main menu.

2.

Press the “▲” or “▼” to move the cursor to the “Information” menu, and then press the “ENT” to enter the submenu.

3.

Press the key “▲” or “▼” to move the cursor to the command menu “Version Info”, and then press the key “ENT” to display the software version.

4.

Press the “ESC” to return to the main menu.

8.4.13 Select Language The operation is as follows: 1.

Press the key “▲” to enter the main menu.

2.

Press the key “▲” or “▼” to move the cursor to the command menu “Language”, and


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then press the key “ENT” to enter the menu and the following display will be shown on LCD.

Please Select Language:

3.

1

中文

2

English

Press the key “▲” or “▼” to move the cursor to the language user preferred and press the key “ENT” to execute language switching. After language switching is finished, LCD will return to the menu “Language”, and the display language is changed. Otherwise, press the key “ESC” to cancel language switching and return to the menu “Language”. Note! LCD interface provided in this chapter is only a reference and available for explaining specific definition of LCD. The displayed interface of the actual device may be some different from it, so you shall be subject to the actual protection device.

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9 Communication

9 Communication Table of Contents 9.1 Overview........................................................................................................... 9-1 9.2 Rear Communication Port Information .......................................................... 9-1 9.2.1 RS-485 Interface .................................................................................................................. 9-1 9.2.2 Ethernet Interface ................................................................................................................. 9-3 9.2.3 IEC60870-5-103 Communication ......................................................................................... 9-4

9.3 IEC60870-5-103 Interface over Serial Port ..................................................... 9-4 9.3.1 Physical Connection and Link Layer .................................................................................... 9-5 9.3.2 Initialization ........................................................................................................................... 9-5 9.3.3 Time Synchronization ........................................................................................................... 9-5 9.3.4 Spontaneous Events ............................................................................................................ 9-5 9.3.5 General Interrogation ........................................................................................................... 9-6 9.3.6 General Functions ................................................................................................................ 9-6 9.3.7 Disturbance Records ............................................................................................................ 9-6

9.4 Messages Description for IEC61850 Protocol ............................................... 9-6 9.4.1 Overview............................................................................................................................... 9-6 9.4.2 Communication Profiles ....................................................................................................... 9-7 9.4.3 MMS Communication Network Deployment ........................................................................ 9-8 9.4.4 Server Data Organization ................................................................................................... 9-11 9.4.5 Server Features and Configuration .................................................................................... 9-14 9.4.6 ACSI Conformance............................................................................................................. 9-16 9.4.7 Logical Nodes..................................................................................................................... 9-20

9.5 DNP3.0 Interface ............................................................................................ 9-22 9.5.1 Overview............................................................................................................................. 9-22 9.5.2 Link Layer Functions .......................................................................................................... 9-23 9.5.3 Transport Functions............................................................................................................ 9-23


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9 Communication

9.5.4 Application Layer Functions ............................................................................................... 9-23

List of Figures Figure 9.2-1 EIA RS-485 bus connection arrangements ......................................................... 9-2 Figure 9.2-2 Ethernet communication cable ............................................................................ 9-3 Figure 9.2-3 Ethernet communication structure ...................................................................... 9-4 Figure 9.4-1 Dual-net full duplex mode sharing the RCB block instance ............................. 9-9 Figure 9.4-2 Dual-net hot-standby mode sharing the same RCB instance ........................ 9-10 Figure 9.4-3 Dual-net full duplex mode with 2 independent RCB instances ...................... 9-11


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9 Communication

9.1 Overview This section outlines the remote communications interfaces of NR equipment. The protective device supports a choice of three protocols via the rear communication interface (RS-485 or Ethernet), selected via the model number by setting. The protocol provided by the protective device is indicated in the menu “Settings→Device Setup→Comm Settings”. Using the keypad and LCD, set the parameter [Protocol_RS485A] and [Protocol_RS485B], the corresponding protocol will be selected. The rear EIA RS-485 interface is isolated and is suitable for permanent connection of whichever protocol is selected. The advantage of this type of connection is that up to 32 protective devices can be “daisy chained” together using a simple twisted pair electrical connection. It should be noted that the descriptions contained within this section do not aim to fully detail the protocol itself. The relevant documentation for the protocol should be referred to for this information. This section serves to describe the specific implementation of the protocol in the relay.

9.2 Rear Communication Port Information 9.2.1 RS-485 Interface This protective device provides two rear RS-485 communication ports, and each port has three terminals in the 12-terminal screw connector located on the back of the relay and each port has a ground terminal for the earth shield of the communication cable. Please refer to the section of “Communication Interface module” for details of the connection terminals. The rear ports provide RS-485 serial data communication and are intended for use with a permanently wired connection to a remote control center. 9.2.1.1 EIA RS-485 Standardized Bus The EIA RS-485 two-wire connection provides a half-duplex fully isolated serial connection to the product. The connection is polarized and whilst the product’s connection diagrams indicate the polarization of the connection terminals it should be borne in mind that there is no agreed definition of which terminal is which. If the master is unable to communicate with the product, and the communication parameters match, then it is possible that the two-wire connection is reversed. 9.2.1.2 Bus Termination The EIA RS-485 bus must have 120Ω (Ohm) ½ Watt terminating resistors fitted at either end across the signal wires (refer to Figure 9.2-1). Some devices may be able to provide the bus terminating resistors by different connection or configuration arrangements, in which case separate external components will not be required. However, this product does not provide such a facility, so if it is located at the bus terminus then an external termination resistor will be required.


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Master

EIA RS-485

9 Communication

120 Ohm

120 Ohm

Slave

Slave

Slave

Figure 9.2-1 EIA RS-485 bus connection arrangements

9.2.1.3 Bus Connections & Topologies The EIA RS-485 standard requires that each device is directly connected to the physical cable that is the communications bus. Stubs and tees are expressly forbidden, such as star topologies. Loop bus topologies are not part of the EIA RS-485 standard and are forbidden by it also. Two-core screened cable is recommended. The specification of the cable will be dependent on the application, although a multi-strand 0.5mm2 per core is normally adequate. Total cable length must not exceed 500m. The screen must be continuous and connected to ground at one end, normally at the master connection point; it is important to avoid circulating currents, especially when the cable runs between buildings, for both safety and noise reasons. This product does not provide a signal ground connection. If a signal ground connection is present in the bus cable then it must be ignored, although it must have continuity for the benefit of other devices connected to the bus. At no stage must the signal ground be connected to the cables screen or to the product’s chassis. This is for both safety and noise reasons. 9.2.1.4 Biasing It may also be necessary to bias the signal wires to prevent jabber. Jabber occurs when the signal level has an indeterminate state because the bus is not being actively driven. This can occur when all the slaves are in receive mode and the master is slow to turn from receive mode to transmit mode. This may be because the master purposefully waits in receive mode, or even in a high impedance state, until it has something to transmit. Jabber causes the receiving device(s) to miss the first bits of the first character in the packet, which results in the slave rejecting the message and consequentially not responding. Symptoms of these are poor response times (due to retries), increasing message error counters, erratic communications, and even a complete failure to communicate. Biasing requires that the signal lines be weakly pulled to a defined voltage level of about 1V. There should only be one bias point on the bus, which is best situated at the master connection point. The DC source used for the bias must be clean; otherwise noise will be injected. Note that some devices may (optionally) be able to provide the bus bias, in which case external components will not be required.


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9 Communication

NOTE! 

It is extremely important that the 120Ω termination resistors are fitted. Failure to do so will result in an excessive bias voltage that may damage the devices connected to the bus.



As the field voltage is much higher than that required, NR cannot assume responsibility for any damage that may occur to a device connected to the network as a result of incorrect application of this voltage.



Ensure that the field voltage is not being used for other purposes (i.e. powering logic inputs) as this may cause noise to be passed to the communication network.

9.2.2 Ethernet Interface This protective device can provide four rear Ethernet interfaces (optional) and they are unattached each other. Parameters of each Ethernet port can be configured in the submenu in the menu “Settings→Device Setup→Comm Settings”. 9.2.2.1 Ethernet Standardized Communication Cable It is recommended to use twisted screened eight-core cable as the communication cable. A picture is shown bellow.

Figure 9.2-2 Ethernet communication cable

9.2.2.2 Connections and Topologies Each device is connected with an exchanger via communication cable, and thereby it forms a star structure network. Dual-network is recommended in order to increase reliability. SCADA is also connected to the exchanger and will play a role of master station, so the every equipment which has been connected to the exchanger will play a role of slave unit.


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9 Communication

SCADA

Switch: Net A Switch: Net B

……

Figure 9.2-3 Ethernet communication structure

9.2.3 IEC60870-5-103 Communication The IEC specification IEC60870-5-103: Telecontrol Equipment and Systems, Part 5: Transmission Protocols Section 103 defines the use of standards IEC60870-5-1 to IEC60870-5-5 to perform communication with protective device. The standard configuration for the IEC60870-5-103 protocol is to use a twisted pair EIA RS-485 connection over distances up to 500m. It also supports to use an Ethernet connection. The relay operates as a slave in the system, responding to commands from a master station. To use the rear port with IEC60870-5-103 communication, the relevant settings of the protective device must be configured. To do this use the keypad and LCD user interface. In the menu “Settings→Device Setup→Comm Settings”, set the parameters [Protocol_RS485A], [Protocol_RS485B], [Baud_RS485A] and [Baud_RS485B]. For using the Ethernet port with IEC60870-5-103 communication, the IP address and submask of each Ethernet port can be set in the same submenu. Please refer to the corresponding section in Chapter “Settings” for further details.

9.3 IEC60870-5-103 Interface over Serial Port The IEC60870-5-103 interface over serial port (RS-485) is a master/slave interface with the protective device as the slave device. It is properly developed by NR. The protective device conforms to compatibility level 3. The following IEC60870-5-103 facilities are supported by this interface: 

Initialization (reset)



Time synchronization



Event record extraction PCS-985G Generator Relay

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9 Communication



General interrogation



General functions



Disturbance records

9.3.1 Physical Connection and Link Layer Two EIA RS-485 standardized ports are available for IEC60870-5-103 in this protective device. The transmission speed is optional: 4800 bit/s, 9600 bit/s, 19200 bit/s or 38400 bit/s. The link layer strictly abides by the rules defined in the IEC60870-5-103.

9.3.2 Initialization Whenever the protective device has been powered up, or if the communication parameters have been changed, a reset command is required to initialize the communications. The protective device will respond to either of the two reset commands (Reset CU or Reset FCB), the difference is that the Reset CU will clear any unsent messages in the transmit buffer. The protective device will respond to the reset command with an identification message ASDU 5, the COT (Cause Of Transmission) of this response will be either Reset CU or Reset FCB depending on the nature of the reset command.

9.3.3 Time Synchronization The protective device time and date can be set using the time synchronization feature of the IEC60870-5-103 protocol. The protective device will correct for the transmission delay as specified in IEC60870-5-103. If the time synchronization message is sent as a send/confirm message then the protective device will respond with a confirmation. Whether the time-synchronization message is sent as a send confirmation or a broadcast (send/no reply) message, a time synchronization class 1 event will be generated/produced. If the protective device clock is synchronized using the IRIG-B input then it will not be possible to set the protective device time using the IEC60870-5-103 interface. An attempt to set the time via the interface will cause the protective device to create an event with the current date and time taken from the IRIG-B synchronized internal clock.

9.3.4 Spontaneous Events Events are categorized using the following information: 

Type identification (TYP)



Function type (FUN)



Information number (INF)

Messages sent to substation automation system are grouped according to IEC60870-5-103 protocol. Operation elements are sent by ASDU2 (time-tagged message with relative time), and status of binary Input and alarm element are sent by ASDU1 (time-tagged message). The cause of transmission (COT) of these responses is 1. PCS-985G Generator Relay

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9 Communication

1.

Operation elements sent by ASDU2

2.

Alarm element sent by ASDU1

3.

Binary input sent by ASDU1

Please print the IEC103 information by the menu “Print->IEC103 Info” for each specific project.

9.3.5 General Interrogation The GI can be used to read the status of the relay, the function numbers, and information numbers that will be returned during the GI cycle. The GI cycle strictly abides by the rules defined in the IEC60870-5-103. Refer the IEC60870-5-103 standard can get the enough details about general interrogation.

9.3.6 General Functions The generic functions can be used to read the setting and protection measurement of the relay, and modify the setting. Two supported type identifications are ASDU 21 and ASDU 10. For more details about generic functions, see the IEC60870-5-103 standard.

9.3.7 Disturbance Records This protective device can store up to 64 disturbance records in its memory. A pickup of the fault detector or an operation of the relay can make the protective device store the disturbance records. The disturbance records are stored in uncompressed format and can be extracted by using the standard mechanisms described in IEC60870-5-103.

9.4 Messages Description for IEC61850 Protocol 9.4.1 Overview The IEC 61850 standard is the result of years of work by electric utilities and vendors of electronic equipment to produce standardized communications systems. IEC 61850 is a series of standards describing client/server and peer-to-peer communications, substation design and configuration, testing, environmental and project standards. The complete set includes: 

IEC 61850-1: Introduction and overview



IEC 61850-2: Glossary



IEC 61850-3: General requirements



IEC 61850-4: System and project management



IEC 61850-5: Communications and requirements for functions and device models

 IEC 61850-6: Configuration description language for communication in electrical substations related to IEDs  IEC 61850-7-1: Basic communication structure for substation and feeder equipment Principles and models PCS-985G Generator Relay

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9 Communication

 IEC 61850-7-2: Basic communication structure for substation and feeder equipment - Abstract communication service interface (ACSI)  IEC 61850-7-3: Basic communication structure for substation and feeder equipment – Common data classes  IEC 61850-7-4: Basic communication structure for substation and feeder equipment – Compatible logical node classes and data classes  IEC 61850-8-1: Specific Communication Service Mapping (SCSM) – Mappings to MMS (ISO 9506-1 and ISO 9506-2) and to ISO/IEC 8802-3  IEC 61850-9-1: Specific Communication Service Mapping (SCSM) – Sampled values over serial unidirectional multidrop point to point link  IEC 61850-9-2: Specific Communication Service Mapping (SCSM) – Sampled values over ISO/IEC 8802-3 

IEC 61850-10: Conformance testing

These documents can be obtained from the IEC (http://www.iec.ch). It is strongly recommended that all those involved with any IEC 61850 implementation obtain this document set.

9.4.2 Communication Profiles The PCS-985G series relays supports IEC 61850 server services over TCP/IP communication protocol stacks. The TCP/IP profile requires the PCS-985G series relays to have an IP address to establish communications. These addresses are located in the submenu “Settings->Device Setup->Comm Settings”. 1.

MMS protocol

IEC 61850 specifies the use of the Manufacturing Message Specification (MMS) at the upper (application) layer for transfer of real-time data. This protocol has been in existence for a number of years and provides a set of services suitable for the transfer of data within a substation LAN environment. IEC 61850-7-2 abstract services and objects are mapped to actual MMS protocol services in IEC61850-8-1. 2.

Client/server

This is a connection-oriented type of communication. The connection and communication activity is initiated and controlled by the client. Substation computers running HMI programs or SOE logging software are considered as IEC61850 clients. Substation equipment such as protection relays, meters, RTUs, instrument transformer, tap changers, or bay control units are considered as servers. Please note that gateways can be considered as clients and servers subject to the communication object. When retrieving data from IEDs within the substation, the gateways are considered as servers whereas transmitting data to control centers, the gateways are considered as clients. 3.

Peer-to-peer


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9 Communication

This is a non-connection-oriented, high speed type of communication usually between substation equipment, such as protection relays. GOOSE is the method of peer-to-peer communication. 4.

Substation configuration language (SCL)

A substation configuration language is a number of files used to describe IED configurations and communication systems according to IEC 61850-5 and IEC 61850-7. Each configured device has an IED Capability Description (ICD) file and a Configured IED Description (CID) file. The substation single line information is stored in a System Specification Description (SSD) file. The entire substation configuration is stored in a Substation Configuration Description (SCD) file. The SCD file is the combination of the following items: individual ICD files, SSD file, communication system parameters (MMS, GOOSE control block, SV control block), as well as GOOSE/SV connection relationship amongst IEDs.

9.4.3 MMS Communication Network Deployment To enhance the stability and reliability of SAS, dual-MMS Ethernet is widely adopted. This section is applied to introduce the details of dual-MMS Ethernet technology. Generally, single-MMS Ethernet is recommended to be adopted in the SAS of 110kV and lower voltage levels, while dual-MMS Ethernet is recommended to be adopted in the SAS of voltage levels above 110kV. Client-server mode is adopted: clients (SCADA, control center and etc.) communicate with the IEDs via MMS communication network, and the IEDs operate as the servers. IEDs are connected to clients passively, and they can interact with the clients according to the configuration and the issued command of the clients. Three modes for dual-MMS Ethernet (abbreviated as dual-net) are provided as below. Note! Hereinafter, the normal operation status of net means the physical link and TCP link are both ok. The abnormal operation status of net means physical link or TCP link is broken. 1)

Mode 1: Dual-net full duplex mode sharing the same RCB instance


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9 Communication

Client

Client

Net B

Net A

Net B

Net A

Report Instance 1

Report Instance 1

RptEna = true

RptEna = true

Report Control Block


IED (Server)

IED (Server)

Normal operation status

Abnormal operation status TCP Link MMS Link

Figure 9.4-1 Dual-net full duplex mode sharing the RCB block instance

Net A and Net B share the same report control block (abbreviated as RCB) enabled by the client. IED sends undifferentiated date through dual-net to the clients. If one net is physically disconnected, the flag of RCB instance (i.e.: “RptEna” in above figure) is still “true”. Only when both Net A and Net B are disconnected, the flag of the RCB instance will automatically change to “false”. In normal operation status of mode 1, IED provides the same MMS service for Net A and Net B. If one net is physically disconnected (i.e.: “Abnormal operation status” in above figure), the working mode will switch to single-net mode seamlessly and immediately. Network communication supervision is unnecessary here, and Buffered Report Control Block (abbreviated as BRCB) need not to be used. On the other net, date alternation works normally. Therefore, MMS service can interact normally without interruption. This mode ensures no data loss during one net is in abnormal operation status. In mode 1, one report will be transmitted twice via dual nets for the same report instance, so the client needs to distinguish whether two reports are same according to corresponding EntryIDs. 2)

Mode 2: Dual-net hot-standby mode sharing the same RCB instance


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9 Communication

Client

Client

Net B

Net A

Net B

Net A

Report Instance 1

Report Instance 1

RptEna = true

RptEna = true



IED (Server)

IED (Server)

Normal operation status

Abnormal operation status TCP Link Main MMS Link Standby MMS Link

Figure 9.4-2 Dual-net hot-standby mode sharing the same RCB instance

In mode 2, the MMS service is provided on main MMS link, no MMS service interacts on the standby MMS link. The definitions of two links are as follows: 

Main MMS Link: Physically connected, TCP level connected, MMS report service available.



Standby MMS Link: Physically connected, TCP level connected, MMS report service not available.

If the main net fails to operate (i.e.: “Abnormal operation status” in the above figure), the IED will set “RptEna” to “false”. Meanwhile the client will detect the failure by heartbeat message or “keep-alive”, it will automatically enable the RCB instance by setting “RptEna” back to “true” through standby MMS link. By the buffer function of BRCB, the IED can provide uninterrupted MMS service on the standby net. However, the differences of BRCB standards among different manufacturers may cause data loss. Moreover, if duration of net switch is too long, the data loss is positively as the capacity of BRCB’s buffer function is limited. Note! In mode 1 and mode 2, Net A IED host address and Net B IED host address must be the same. E.g.: if the subnet mask is 255.255.0.0, network prefix of Net A is 198.120.0.0, network prefix of Net B is 198.121.0.0, Net A IP address of the IED is 198.120.1.2, and then Net B IP address of the IED must be configured as 198.121.1.2, i.e.: Net A IED host address =1x256+2=258, Net B IED host address =1x256+2=258, Net A IED host address equals to Net B IED host address. 3)

Mode 3: Dual-net full duplex mode with 2 independent RCB instances PCS-985G Generator Relay

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9 Communication Client

Client

Net B

Net A

Net B

Net A

Report Instance 1

Report Instance 2

Report Instance 1

Report Instance 2

RptEna = true

RptEna = true

RptEna = false

RptEna = true



IED (Server)

IED (Server)

TCP Link MMS Link

Figure 9.4-3 Dual-net full duplex mode with 2 independent RCB instances

In mode 3, IED provides 2 report instances for each RCB, Net A and Net B work independently from each other, failures of one net will not affect the other net at all. In this mode, 2 report instances are required for each client. Therefore, the IED may be unable to provide enough report instances if there are too many clients. Net A and Net B send the same report separately when they operates normally, To ensure no repeated data is saved into database, massive calculation is required for the client. Moreover, accurate clock synchronization of the IED is required to distinguish whether 2 reports are the same report according to the timestamps. Clock synchronization error of the IED may lead to report loss/redundancy. As a conclusion: In mode 2, it’s difficult to realize seamless switchover between dual nets; In mode 3, the IED may be unable to provide enough report instances if too many clients are applied on site. For the consideration of client treatment and IED implementation, mode 1 (Dual-net full duplex mode sharing the same report instance) is recommended for MMS communication network deployment.

9.4.4 Server Data Organization IEC61850 defines an object-oriented approach to data and services. An IEC61850 physical device can contain one or more logical device(s) (for proxy). Each logical device can contain many logical nodes. Each logical node can contain many data objects. Each data object is composed of data attributes and data attribute components. Services are available at each level for performing various functions, such as reading, writing, control commands, and reporting.


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9 Communication

Each IED represents one IEC61850 physical device. The physical device contains one or more logical device(s), and the logical device contains many logical nodes. The logical node LPHD contains information about the IED physical device. The logical node LLN0 contains common information about the IED logical device. 9.4.4.1 Digital Status Values The GGIO logical node is available in the PCS-985G series relays to provide access to digital status points (including general I/O inputs and warnings) and associated timestamps and quality flags. The data content must be configured before the data can be used. GGIO provides digital status points for access by clients. It is intended that clients use GGIO in order to access digital status values from the PCS-985G series relays. Clients can utilize the IEC61850 buffered reporting features available from GGIO in order to build sequence of events (SOE) logs and HMI display screens. Buffered reporting should generally be used for SOE logs since the buffering capability reduces the chances of missing data state changes. All needed status data objects are transmitted to HMI clients via buffered reporting, and the corresponding buffered reporting control block (BRCB) is defined in LLN0. 9.4.4.2 Analog Values Most of analog measured values are available through the MMXU logical nodes, and metering values in MMTR, the others in MMXN, MSQI and so on. Each MMXU logical node provides data from an IED current/voltage “source”. There is one MMXU available for each configurable source. MMXU1 provides data from CT/VT source 1(usually for protection purpose), and MMXU2 provides data from CT/VT source 2 (usually for monitor and display purpose). All these analog data objects are transmitted to HMI clients via unbuffered reporting periodically, and the corresponding unbuffered reporting control block (URCB) is defined in LLN0. MMXUx logical nodes provide the following data for each source: 

MMXU.MX.Hz: frequency



MMXU.MX.PPV.phsAB: phase AB voltage magnitude and angle



MMXU.MX.PPV.phsBC: phase BC voltage magnitude and angle



MMXU.MX.PPV.phsCA: Phase CA voltage magnitude and angle



MMXU.MX.PhV.phsA: phase AG voltage magnitude and angle



MMXU.MX.PhV.phsB: phase BG voltage magnitude and angle



MMXU.MX.PhV.phsC: phase CG voltage magnitude and angle



MMXU.MX.A.phsA: phase A current magnitude and angle



MMXU.MX.A.phsB: phase B current magnitude and angle



MMXU.MX.A.phsC: phase C current magnitude and angle

9.4.4.3 Protection Logical Nodes The following list describes the protection elements for all PCS-985G relays. The specified relay


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9 Communication

will contain a subset of protection elements from this list. 

PDIS: Phase-to-phase distance, phase-to-ground distance and SOTF distance



PTUC: Undercurrent



PTOC: Phase overcurrent, zero-sequence overcurrent and overcurrent when VT circuit failure



PTTR: Thermal overload



PTUV: Undervoltage



PTOV: Overvoltage and auxiliary overvoltage



PTOF: Overfrequency



PTUF: Underfrequency



PSCH: Protection scheme



RBRF:Breaker failure



RPSB: Power swing detection/blocking



RREC: Automatic reclosing



RSYN: Synchronism-check



RFLO: Fault location

The protection elements listed above contain start (pickup) and operate flags, instead of any element has its own start (pickup) flag separately, all the elements share a common start (pickup) flags “PTRC.ST.Str.general”. The operate flag for PTOC1 is “PTOC1.ST.Op.general”. For the PCS-985G relays protection elements, these flags take their values from related module for the corresponding element. Similar to digital status values, the protection trip information is reported via BRCB, and it also locates in LLN0. 9.4.4.4 LLN0 and Other Logical Nodes Logical node LLN0 is essential for an IEC61850 based IED. This LN shall be used to address common issues for Logical Devices. Most of the public services, the common settings, control values and some device oriented data objects are available here. The public services may be BRCB, URCB and GSE control blocks and similar global defines for the whole device; the common settings include all the setting items of communication settings, system settings and some of the protection setting items, which can be configured to two or more protection elements (logical nodes). In LLN0, the item Loc is a device control object, this Do item indicates the local operation for complete logical device, when it is true, all the remote control commands to the IED will be blocked and those commands make effective until the item Loc is changed to false. In PCS-985G relays, besides the logical nodes we describe above, there are some other logical nodes below in the IEDs:  MMXU: This LN shall be used to acquire values from CTs and VTs and calculate measurands such as r.m.s. values for current and voltage or power flows out of the acquired voltage and


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9 Communication

current samples. These values are normally used for operational purposes such as power flow supervision and management, screen displays, state estimation, etc. The requested accuracy for these functions has to be provided.  LPHD: Physical device information, the logical node to model common issues for physical device.  PTRC: Protection trip conditioning, it shall be used to connect the “operate” outputs of one or more protection functions to a common “trip” to be transmitted to XCBR. In addition or alternatively, any combination of “operate” outputs of protection functions may be combined to a new “operate” of PTRC.  RDRE: Disturbance recorder function. It triggers the fault wave recorder and its output refers to the “IEEE Standard Format for Transient Data Exchange (COMTRADE) for Power System” (IEC 60255-24). All enabled channels are included in the recording, independently of the trigger mode.

9.4.5 Server Features and Configuration 9.4.5.1 Buffered/unbuffered Reporting IEC61850 buffered and unbuffered reporting control blocks locate in LLN0, they can be configured to transmit information of protection trip information (in the Protection logical nodes), binary status values (in GGIO) and analog measured/calculated values (in MMXU, MMTR and MSQI). The reporting control blocks can be configured in CID files, and then be sent to the IED via an IEC61850 client. The following items can be configured. 

TrgOps: Trigger options. The following bits are supported by the PCS-985G relays: － Bit 1: Data-change － Bit 4: Integrity － Bit 5: General interrogation



OptFlds: Option Fields. The following bits are supported by the PCS-985G relays: － Bit 1: Sequence-number － Bit 2: Report-time-stamp － Bit 3: Reason-for-inclusion － Bit 4: Data-set-name － Bit 5: Data-reference － Bit 6: Buffer-overflow (for buffered reports only) － Bit 7: EntryID (for buffered reports only) － Bit 8: Conf-revision － Bit 9: Segmentation



IntgPd: Integrity period. PCS-985G Generator Relay

9-14 Date: 2013-06-29

9 Communication



BufTm: Buffer time.

9.4.5.2 File Transfer MMS file services are supported to allow transfer of oscillography, event record or other files from a PCS-985G device. 9.4.5.3 Timestamps The Universal Time Coordinated (UTC for short) timestamp associated with all IEC61850 data items represents the latest change time of either the value or quality flags of the data item 9.4.5.4 Logical Node Name Prefixes IEC61850 specifies that each logical node can have a name with a total length of 11 characters. The name is composed of: 

A five or six-character name prefix.



A four-character standard name (for example, MMXU, GGIO, PIOC, etc.).



A one or two-character instantiation index.

Complete names are of the form xxxxxxPTOC1, where the xxxxxx character string is configurable. Details regarding the logical node naming rules are given in IEC61850 parts 6 and 7-2. It is recommended that a consistent naming convention be used for an entire substation project. 9.4.5.5 GOOSE Services IEC61850 specifies the type of broadcast data transfer services: Generic Object Oriented Substation Events (GOOSE). IEC61850 GOOSE services provide virtual LAN (VLAN) support, Ethernet priority tagging, and Ether-type Application ID configuration. The support for VLANs and priority tagging allows for the optimization of Ethernet network traffic. GOOSE messages can be given a higher priority than standard Ethernet traffic, and they can be separated onto specific VLANs. Devices that transmit GOOSE messages also function as servers. Each GOOSE publisher contains a “GOOSE control block” to configure and control the transmission. The GOOSE transmission (including subscribing and publishing) is controlled by GOOSE logic link settings in device. The PCS-985G relays support IEC61850 Generic Object Oriented Substation Event (GOOSE) communication. All GOOSE messages contain IEC61850 data collected into a dataset. It is this dataset that is transferred using GOOSE message services. The GOOSE related dataset is configured in the CID file and it is recommended that the fixed GOOSE be used for implementations that require GOOSE data transfer between PCS-985G relays. IEC61850 GOOSE messaging contains a number of configurable parameters, all of which must be correct to achieve the successful transfer of data. It is critical that the configured datasets at the transmission and reception devices are an exact match in terms of data structure, and that the GOOSE addresses and name strings match exactly.


9-15 Date: 2013-06-29

9 Communication

9.4.6 ACSI Conformance 9.4.6.1 ACSI Basic Conformance Statement Services

Client

Server

PCS-985G

Client-Server Roles B11

Server side (of Two-party Application-Association)

－

C1

Y

B12

Client side (of Two-party Application-Association)

C1

－

N

SCSMS Supported B21

SCSM: IEC 61850-8-1 used

Y

Y

Y

B22


N

N

N

B23


Y

N

Y

B24

SCSM: other

N

N

N

Generic Substation Event Model (GSE) B31

Publisher side

－

O

Y

B32

Subscriber side

O

－

Y

Transmission Of Sampled Value Model (SVC) B41

Publisher side

－

O

N

B42

Subscriber side

O

－

N

Where: C1: Shall be "M" if support for LOGICAL-DEVICE model has been declared O: Optional M: Mandatory Y:

Supported by PCS-985G relay

N: Currently not supported by PCS-985G relay 9.4.6.2 ACSI Models Conformance Statement Services

Client

Server

PCS-900 Series

M1

Logical device

C2

C2

Y

M2

Logical node

C3

C3

Y

M3

Data

C4

C4

Y

M4

Data set

C5

C5

Y

M5

Substitution

O

O

Y

M6

Setting group control

O

O

Y

M7

Buffered report control

O

O

Y

M7-1

sequence-number

Y

Y

Y

M7-2

report-time-stamp

Y

Y

Y

Reporting


9-16 Date: 2013-06-29

9 Communication M7-3

reason-for-inclusion

Y

Y

Y

M7-4

data-set-name

Y

Y

Y

M7-5

data-reference

Y

Y

Y

M7-6

buffer-overflow

Y

Y

N

M7-7

entryID

Y

Y

Y

M7-8

BufTm

N

N

N

M7-9

IntgPd

Y

Y

Y

M7-10

GI

Y

Y

Y

M8

Unbuffered report control

M

M

Y

M8-1

sequence-number

Y

Y

Y

M8-2

report-time-stamp

Y

Y

Y

M8-3

reason-for-inclusion

Y

Y

Y

M8-4

data-set-name

Y

Y

Y

M8-5

data-reference

Y

Y

Y

M8-6

BufTm

N

N

N

M8-7

IntgPd

N

Y

Y

M9

Log control

O

O

N

M9-1

IntgPd

N

N

N

M10

Log

O

O

N

M12

GOOSE

O

O

Y

M13

GSSE

O

O

N

M14

Multicast SVC

O

O

N

M15

Unicast SVC

O

O

N

M16

Time

M

M

Y

M17

File transfer

O

O

Y

Logging

GSE

Where: C2: Shall be "M" if support for LOGICAL-NODE model has been declared C3: Shall be "M" if support for DATA model has been declared C4: Shall be "M" if support for DATA-SET, Substitution, Report, Log Control, or Time models has been declared C5: Shall be "M" if support for Report, GSE, or SMV models has been declared M: Mandatory Y:

Supported by PCS-900 series relay

N: Currently not supported by PCS-900 series relay 9.4.6.3 ACSI Services Conformance Statement Service

Server/Publisher


PCS-985G 9-17

Date: 2013-06-29

9 Communication Service

Server/Publisher

PCS-985G

Server S1

ServerDirectory

M

Y

Application association S2

Associate

M

Y

S3

Abort

M

Y

S4

Release

M

Y

M

Y

Logical device S5

LogicalDeviceDirectory

Logical node S6

LogicalNodeDirectory

M

Y

S7

GetAllDataValues

M

Y

S8

GetDataValues

M

Y

S9

SetDataValues

M

Y

S10

GetDataDirectory

M

Y

S11

GetDataDefinition

M

Y

S12

GetDataSetValues

M

Y

S13

SetDataSetValues

O

S14

CreateDataSet

O

S15

DeleteDataSet

O

S16

GetDataSetDirectory

M

Y

M

Y

Data

Data set

Substitution S17

SetDataValues

Setting group control S18

SelectActiveSG

M/O

Y

S19

SelectEditSG

M/O

Y

S20

SetSGValuess

M/O

Y

S21

ConfirmEditSGValues

M/O

Y

S22

GetSGValues

M/O

Y

S23

GetSGCBValues

M/O

Y

Report

M

Y

data-change

M

Y

Reporting Buffered report control block S24 S24-1


9-18 Date: 2013-06-29


Server/Publisher

PCS-985G

S24-2

qchg-change

M

Y

S24-3

data-update

M

Y

S25

GetBRCBValues

M

Y

S26

SetBRCBValues

M

Y

Report

M

Y

S27-1

data-change

M

Y

S27-2

qchg-change

M

Y

S27-3

data-update

M

Y

S28

GetURCBValues

M

Y

S29

SetURCBValues

M

Y

Unbuffered report control block S27

Logging Log control block S30

GetLCBValues

O

S31

SetLCBValues

O

S32

QueryLogByTime

O

S33

QueryLogAfter

O

S34

GetLogStatusValues

O

Log

Generic substation event model (GSE) GOOSE control block S35

SendGOOSEMessage

M

Y

S36

GetGoReference

O

S37

GetGOOSEElementNumber

O

Y

S38

GetGoCBValues

M

Y

S39

SetGoCBValuess

M

Y

S51

Select

O

S52

SelectWithValue

M

Y

S53

Cancel

M

Y

S54

Operate

M

Y

S55

Command-Termination

O

Y

S56

TimeActivated-Operate

O

Control

File transfer S57

GetFile

M/O


Y

9-19 Date: 2013-06-29


Server/Publisher

S58

SetFile

O

S59

DeleteFile

O

S60

GetFileAttributeValues

PCS-985G Y

M/O

Y

M

Y

Time SNTP

9.4.7 Logical Nodes 9.4.7.1 Logical Nodes Table The PCS-985G relay supports IEC61850 logical nodes as indicated in the following table. Note that the actual instantiation of each logical node is determined by the product order code. Nodes

PCS-985G

L: System Logical Nodes LPHD: Physical device information

YES

LLN0: Logical node zero

YES

P: Logical Nodes For Protection Functions PDIF: Differential

－

PDIR: Direction comparison

－

PDIS: Distance

－

PDOP: Directional overpower

－

PDUP: Directional underpower

－

PFRC: Rate of change of frequency

－

PHAR: Harmonic restraint

－

PHIZ: Ground detector

－

PIOC: Instantaneous overcurrent

－

PMRI: Motor restart inhibition

－

PMSS: Motor starting time supervision

－

POPF: Over power factor

－

PPAM: Phase angle measuring

－

PSCH: Protection scheme

YES

PSDE: Sensitive directional earth fault

－

PTEF: Transient earth fault

－

PTOC: Time overcurrent

－

PTOF: Overfrequency

－

PTOV: Overvoltage

－

PTRC: Protection trip conditioning

－

PTTR: Thermal overload

－

PTUC: Undercurrent

－

PTUV: Undervoltage

－

PUPF: Underpower factor

－


9-20 Date: 2013-06-29

9 Communication PTUF: Underfrequency

－

PVOC: Voltage controlled time overcurrent

－

PVPH: Volts per Hz

－

PZSU: Zero speed or underspeed

－

R: Logical Nodes For Protection Related Functions RDRE: Disturbance recorder function

YES

RADR: Disturbance recorder channel analogue

－

RBDR: Disturbance recorder channel binary

－

RDRS: Disturbance record handling

－

RBRF: Breaker failure

－

RDIR: Directional element

－

RFLO: Fault locator

－

RPSB: Power swing detection/blocking

－

RREC: Autoreclosing

－

RSYN: Synchronism-check or synchronizing

－

C: Logical Nodes For Control CALH: Alarm handling

－

CCGR: Cooling group control

－

CILO: Interlocking

－

CPOW: Point-on-wave switching

－

CSWI: Switch controller

－

G: Logical Nodes For Generic References GAPC: Generic automatic process control

YES

GGIO: Generic process I/O

YES －

GSAL: Generic security application I: Logical Nodes For Interfacing And Archiving IARC: Archiving

－

IHMI: Human machine interface

－

ITCI: Telecontrol interface

－

ITMI: Telemonitoring interface

－

A: Logical Nodes For Automatic Control ANCR: Neutral current regulator

－

ARCO: Reactive power control

－

ATCC: Automatic tap changer controller

－

AVCO: Voltage control

－

M: Logical Nodes For Metering And Measurement MDIF: Differential measurements

－

MHAI: Harmonics or interharmonics

－

MHAN: Non phase related harmonics or interharmonic

－

MMTR: Metering

－

MMXN: Non phase related measurement

－

MMXU: Measurement

YES


9-21 Date: 2013-06-29

9 Communication MSQI: Sequence and imbalance

－

MSTA: Metering statistics

－

S: Logical Nodes For Sensors And Monitoring SARC: Monitoring and diagnostics for arcs

－

SIMG: Insulation medium supervision (gas)

－

SIML: Insulation medium supervision (liquid)

－

SPDC: Monitoring and diagnostics for partial discharges

－

X: Logical Nodes For Switchgear TCTR: Current transformer

－

TVTR: Voltage transformer

－

Y: Logical Nodes For Power Transformers YEFN: Earth fault neutralizer (Peterson coil)

－

YLTC: Tap changer

－

YPSH: Power shunt

－

YPTR: Power transformer

－

Z: Logical Nodes For Further Power System Equipment ZAXN: Auxiliary network

－

ZBAT: Battery

－

ZBSH: Bushing

－

ZCAB: Power cable

－

ZCAP: Capacitor bank

－

ZCON: Converter

－

ZGEN: Generator

－

ZGIL: Gas insulated line

－

ZLIN: Power overhead line

－

ZMOT: Motor

－

ZREA: Reactor

－

ZRRC: Rotating reactive component

－

ZSAR: Surge arrestor

－

ZTCF: Thyristor controlled frequency converter

－

ZTRC: Thyristor controlled reactive component

－

9.5 DNP3.0 Interface 9.5.1 Overview The descriptions given here are intended to accompany this relay. The DNP3.0 protocol is not described here; please refer to the DNP3.0 protocol standard for the details about the DNP3.0 implementation. This manual only specifies which objects, variations and qualifiers are supported in this relay, and also specifies what data is available from this relay via DNP3.0. The relay operates as a DNP3.0 slave and supports subset level 2 of the protocol, plus some of the features from level 3. The DNP3.0 communication uses the Ethernet ports at the rear of this PCS-985G Generator Relay

9-22 Date: 2013-06-29

9 Communication

relay.

9.5.2 Link Layer Functions Please see the DNP3.0 protocol standard for the details about the linker layer functions.

9.5.3 Transport Functions Please see the DNP3.0 protocol standard for the details about the transport functions.

9.5.4 Application Layer Functions 9.5.4.1 Time Synchronization 1.

2.

3.

Time delay measurement Master/Slave

Function Code

Object

Variation

Qualifier

Master

0x17

－

－

－

Slave

0x81

0x34

0x02

0x07

Master/Slave

Function Code

Object

Variation

Qualifier

Master

0x01

0x34

0x00, 0x01

0x07

Slave

0x81

0x32

0x01

0x07

Master/Slave

Function Code

Object

Variation

Qualifier

Master

0x02

0x32

0x01

0x00,0x01,0x07,0x08

Slave

0x81

－

－

－

Read time of device

Write time of device

9.5.4.2 Supported Writing Functions 1.

Write time of device See Section 9.5.4.1 for the details.

2.

Reset the CU (Reset IIN bit7) Master/Slave

Function Code

Object

Variation

Qualifier

Master

0x02

0x50

0x01

0x00, 0x01

Slave

0x81

－

－

－

9.5.4.3 Supported Reading Functions 1.

2.

Supported qualifiers Master Qualifier

0x00

0x01

0x06

0x07

0x08

Slave Qualifier

0x00

0x01

0x01

0x07

0x08

Supported objects and variations 

Object 1, Binary inputs


9-23 Date: 2013-06-29

9 Communication Master Variation

0x00

0x01

0x02

Slave Variation

0x02

0x01

0x02

The protection operation signals, alarm signals and binary input state change signals are transported respectively according to the variation sequence in above table. 

Object 2, SOE

Master Variation

0x00

0x01

0x02

0x03

Slave Variation

0x02

0x01

0x02

0x03

If the master qualifier is “0x07”, the slave responsive qualifier is “0x27”; and if the master qualifier is “0x01”, “0x06” or “0x08”, the slave responsive qualifier is “0x28”. 

Object 30, Analog inputs

Master Variation

0x00

0x01

0x02

0x03

0x04

Slave Variation

0x01

0x01

0x02

0x03

0x04

The measurement values are transported firstly, and then the relay measurement values are transported. 

Object 40, Analog outputs

Master Variation

0x00

0x01

0x02

Slave Variation

0x01

0x01

0x02

The protection settings are transported in this object. 

Object 50, Time Synchronization See Section 9.5.4.1 for the details.

3.

Class 0 data request The master adopts the “Object 60” for the Class 0 data request and the variation is “0x01”. The slave responds with the above mentioned “Object 1”, “Object 30” and “Object 40” (see “Supported objects and variations” in Section 9.5.4.3).

4.

Class 1 data request The master adopts the “Object 60” for the Class 1 data request and the variation is “0x02”. The slave responds with the above mentioned “Object 2” (see “Supported objects and variations” in Section 9.5.4.3).

5.

Multiple object request The master adopts the “Object 60” for the multiple object request and the variation is “0x01”, “0x02”, “0x03” and “0x04”.

The slave responds with the above mentioned “Object 1”, “Object 2”, “Object 30” and “Object 40” see “Supported objects and variations” in Section 9.5.4.3.


9-24 Date: 2013-06-29

10 Installation

10 Installation Table of Contents 10 Installation ................................................................................... 10-a 10.1 Overview ...................................................................................................... 10-1 10.2 Safety Information....................................................................................... 10-1 10.3 Checking Shipment..................................................................................... 10-2 10.4 Material and Tools Required ...................................................................... 10-2 10.5 Device Location and Ambient Conditions ................................................ 10-2 10.6 Mechanical Installation ............................................................................... 10-3 10.7 Electrical Installation and Wiring ............................................................... 10-4 10.7.1 Grounding Guidelines ...................................................................................................... 10-4 10.7.2 Cubicle Grounding ........................................................................................................... 10-4 10.7.3 Ground Connection on the Device .................................................................................. 10-5 10.7.4 Grounding Strips and their Installation ............................................................................ 10-6 10.7.5 Guidelines for Wiring ....................................................................................................... 10-6 10.7.6 Wiring for Electrical Cables ............................................................................................. 10-7

List of Figures Figure 10.6-1 Dimensions of PCS-985G.................................................................................. 10-3 Figure 10.6-2 Demonstration of plugging a board into its corresponding slot .................. 10-4 Figure 10.7-1 Cubicle grounding system................................................................................ 10-5 Figure 10.7-2 Ground terminal of this relay............................................................................ 10-6 Figure 10.7-3 Ground strip and termination ........................................................................... 10-6 Figure 10.7-4 Glancing demo about the wiring for electrical cables ................................... 10-7


10-a Date: 2013-05-29

10 Installation

10-b


10 Installation

10.1 Overview The device must be shipped, stored and installed with the greatest care. Choose the place of installation such that the communication interface and the controls on the front of the device are easily accessible. Air must circulate freely around the equipment. Observe all the requirements regarding place of installation and ambient conditions given in this instruction manual. Take care that the external wiring is properly brought into the equipment and terminated correctly and pay special attention to grounding. Strictly observe the corresponding guidelines contained in this section.

10.2 Safety Information Modules and units may only be replaced by correspondingly trained personnel. Always observe the basic precautions to avoid damage due to electrostatic discharge when handling the equipment. In certain cases, the settings have to be configured according to the demands of the engineering configuration after replacement. It is therefore assumed that the personnel who replace modules and units are familiar with the use of the operator program on the service PC. DANGER! Only insert or withdraw the PWR module while the power supply is switched off. To this end, disconnect the power supply cable that connects with the PWR module. WARNING! Only insert or withdraw other modules while the power supply is switched off.

WARNING! The modules may only be inserted in the slots designated in Section 6.2. Components can be damaged or destroyed by inserting boards in the wrong slots. DANGER! Improper handling of the equipment can cause damage or an incorrect response of the equipment itself or the primary plant. WARNING! Industry packs and ribbon cables may only be replaced or the positions of jumpers be changed on a workbench appropriately designed for working on electronic equipment. The modules, bus backplanes are sensitive to electrostatic discharge when not in the unit's housing. The basic precautions to guard against electrostatic discharge are as follows: 

Should boards have to be removed from this relay installed in a grounded cubicle in an HV switchgear installation, please discharge yourself by touching station ground (the cubicle) beforehand.


10-1 Date: 2013-05-29

10 Installation



Only hold electronic boards at the edges, taking care not to touch the components.



Only works on boards that have been removed from the cubicle on a workbench designed for electronic equipment and wear a grounded wristband. Do not wear a grounded wristband, however, while inserting or withdrawing units.



Always store and ship the electronic boards in their original packing. Place electronic parts in electrostatic screened packing materials.

10.3 Checking Shipment Check that the consignment is complete immediately upon receipt. Notify the nearest NR Company or agent, should departures from the delivery note, the shipping papers or the order be found. Visually inspect all the material when unpacking it. When there is evidence of transport damage, lodge a claim immediately in writing with the last carrier and notify the nearest NR Company or agent. If the equipment is not going to be installed immediately, store all the parts in their original packing in a clean dry place at a moderate temperature. The humidity at a maximum temperature and the permissible storage temperature range in dry air are listed in Chapter “Technical Data”.

10.4 Material and Tools Required The necessary mounting kits will be provided, including screws, pincers and assembly instructions. A suitable drill and spanners are required to secure the cubicles to the floor using the plugs provided (if this relay is mounted in cubicles).

10.5 Device Location and Ambient Conditions The place of installation should permit easy access especially to front of the device, i.e. to the human machine interface of the equipment. There should also be free access at the rear of the equipment for additions and replacement of electronic boards. Since every piece of technical equipment can be damaged or destroyed by inadmissible ambient conditions, such as: 1.

The location should not be exposed to excessive air pollution (dust, aggressive substances).

2.

Severe vibration, extreme changes of temperature, high levels of humidity, surge voltages of high amplitude and short rise time and strong induced magnetic fields should be avoided as far as possible.

3.

Air must not be allowed to circulate freely around the equipment.

The equipment can in principle be mounted in any attitude, but it is normally mounted vertically 10-2


10 Installation

(visibility of markings). WARNING! Excessively high temperature can appreciably reduce the operating life of this relay.

10.6 Mechanical Installation The device adopts IEC standard chassis and is rack with modular structure. It uses an integral faceplate and plug terminal block on backboard for external connections. PCS-985G is IEC 8U high and 19” wide. Figure 10.6-1 shows its dimensions. (290)

101.6

76.2

354.8

101.6

482.6 465

465±0.2 +0.4 451-0

101.6±0.1

356.8 -0

+0.4

76.2±0.1 101.6±0.1

8-Ø6.8

Figure 10.6-1 Dimensions of PCS-985G

NOTE! It is necessary to leave enough space top and bottom of the cut-out in the cubicle for heat emission of this relay.


10-3 Date: 2013-05-29

10 Installation

The safety instructions must be abided by when installing the boards, please see Section 10.2 for the details. Following figure shows the installation way of a module being plugged into a corresponding slot.

Figure 10.6-2 Demonstration of plugging a board into its corresponding slot

In the case of equipment supplied in cubicles, place the cubicles on the foundations that have been prepared. Take care while doing so not to jam or otherwise damage any of the cables that have already been installed. Secure the cubicles to the foundations.

10.7 Electrical Installation and Wiring 10.7.1 Grounding Guidelines Switching operations in HV installations generate transient over voltages on control signal cables. There is also a background of electromagnetic RF fields in electrical installations that can induce spurious currents in the devices themselves or the leads connected to them. All these influences can influence the operation of electronic apparatus. On the other hand, electronic apparatus can transmit interference that can disrupt the operation of other apparatus. In order to minimize these influences as far as possible, certain standards have to be observed with respect to grounding, wiring and screening. NOTE! All these precautions can only be effective if the station ground is of good quality.

10.7.2 Cubicle Grounding The cubicle must be designed and fitted out such that the impedance for RF interference of the ground path from the electronic device to the cubicle ground terminal is as low as possible. Metal accessories such as side plates, blanking plates etc., must be effectively connected surface-to-surface to the grounded frame to ensure a low-impedance path to ground for RF interference. The contact surfaces must not only conduct well, they must also be non-corroding.

10-4


10 Installation

NOTE! If the above conditions are not fulfilled, there is a possibility of the cubicle or parts of it forming a resonant circuit at certain frequencies that would amplify the transmission of interference by the devices installed and also reduce their immunity to induced interference. Movable parts of the cubicle such as doors (front and back) or hinged equipment frames must be effectively grounded to the frame by three braided copper strips (see Figure 10.7-1). The metal parts of the cubicle housing and the ground rail are interconnected electrically conducting and corrosion proof. The contact surfaces shall be as large as possible. NOTE! For metallic connections please observe the voltage difference of both materials according to the electrochemical code. The cubicle ground rail must be effectively connected to the station ground rail by a grounding strip (braided copper). Door or hinged equipment frame

Cubicle ground rail close to floor

Braided copper strip Station ground Conducting connection

Figure 10.7-1 Cubicle grounding system

10.7.3 Ground Connection on the Device There is a ground terminal on the rear panel, and the ground braided copper strip can be connected with it. Take care that the grounding strip is always as short as possible. The main thing is that the device is only grounded at one point. Grounding loops from unit to unit are not allowed. There are some ground terminals on some connectors of this relay, and the sign is “GND”. All the ground terminals are connected in the cabinet of this relay. So, the ground terminal on the rear panel (see Figure 10.7-2) is the only ground terminal of this device.


10-5 Date: 2013-05-29

10 Installation

Figure 10.7-2 Ground terminal of this relay

10.7.4 Grounding Strips and their Installation High frequency currents are produced by interference in the ground connections and because of skin effect at these frequencies, only the surface region of the grounding strips is of consequence. The grounding strips must therefore be of (preferably tinned) braided copper and not round copper conductors, as the cross-section of round copper would have to be too large. Proper terminations must be fitted to both ends (press/pinch fit and tinned) with a hole for bolting them firmly to the items to be connected. The surfaces to which the grounding strips are bolted must be electrically conducting and non-corroding. The following figure shows the ground strip and termination. Press/pinch fit cable terminal

Braided copper strip

Terminal bolt Contact surface

Figure 10.7-3 Ground strip and termination

10.7.5 Guidelines for Wiring There are several types of cables that are used in the connection of this relay: braided copper cable, serial communication cable etc. Recommendation of each cable: 

Grounding: braided copper cable, 2.5mm2 ~ 6.0mm2



Power supply, binary inputs & outputs: brained copper cable, 1.0mm2 ~ 2.5mm2



AC voltage inputs: brained copper cable, 1.0mm2 ~ 2.5mm2



AC current inputs: brained copper cable, 1.5mm2 ~ 4.0mm2



Serial communication: 4-core shielded braided cable



Ethernet communication: 4-pair screened twisted category 5E cable

10-6


10 Installation

10.7.6 Wiring for Electrical Cables A female connector is used for connecting the wires with it, and then a female connector plugs into a corresponding male connector that is in the front of one board. See Chapter “Hardware” for further details about the pin defines of these connectors. The following figure shows the glancing demo about the wiring for the electrical cables.

Tighten

01

02

03

04

05

06

07

08

09

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

01

Figure 10.7-4 Glancing demo about the wiring for electrical cables

DANGER! Never allow the current transformer (CT) secondary circuit connected to this equipment to be opened while the primary system is live. Opening the CT circuit will produce a dangerously high voltage.


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10 Installation

10-8


11 Commissioning

11 Commissioning Table of Contents 11 Commissioning ........................................................................... 11-a 11.1 Overview ....................................................................................................... 11-1 11.2 Safety Instructions ....................................................................................... 11-1 11.3 Commission Tools ....................................................................................... 11-2 11.4 Setting Familiarization ................................................................................. 11-2 11.5 Product Checks ............................................................................................ 11-3 11.5.1 With the Relay De-energized ............................................................................................11-3 11.5.2 With the Relay Energized .................................................................................................11-5 11.5.3 Print Fault Report ..............................................................................................................11-8 11.5.4 On-load Checks ................................................................................................................11-8

11.6 Final Checks ................................................................................................. 11-9


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11 Commissioning

11-b


11 Commissioning

11.1 Overview This relay is fully numerical in their design, implementing all protection and non-protection functions in software. The relay employs a high degree of self-checking and in the unlikely event of a failure, will give an alarm. As a result of this, the commissioning test does not need to be as extensive as with non-numeric electronic or electro-mechanical relays. To commission numerical relays, it is only necessary to verify that the hardware is functioning correctly and the application-specific software settings have been applied to the relay. Blank commissioning test and setting records are provided at the end of this manual for completion as required. Before carrying out any work on the equipment, the user should be familiar with the contents of the safety and technical data sections and the ratings on the equipment’s rating label.

11.2 Safety Instructions WARNING! Hazardous voltages are present in this electrical equipment during operation. Non-observance of the safety rules can result in severe personal injury or property damage. WARNING! Only the qualified personnel shall work on and around this equipment after becoming thoroughly familiar with all warnings and safety notices of this manual as well as with the applicable safety regulations. Particular attention must be drawn to the following: 

The earthing screw of the device must be connected solidly to the protective earth conductor before any other electrical connection is made.



Hazardous voltages can be present on all circuits and components connected to the supply voltage or to the measuring and test quantities.



Hazardous voltages can be present in the device even after disconnection of the supply voltage (storage capacitors!)



The limit values stated in the Chapter “Technical Data” must not be exceeded at all, not even during testing and commissioning.



When testing the device with secondary test equipment, make sure that no other measurement quantities are connected. Take also into consideration that the trip circuits and maybe also close commands to the circuit breakers and other primary switches are disconnected from the device unless expressly stated. DANGER! Current transformer secondary circuits must have been short-circuited before the current leads to the device are disconnected.


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11 Commissioning

WARNING! Primary test may only be carried out by qualified personnel, who are familiar with the commissioning of protection system, the operation of the plant and safety rules and regulations (switching, earthing, etc.).

11.3 Commission Tools Minimum equipment required: 

Multifunctional dynamic current and voltage injection test set with interval timer.



Multimeter with suitable AC current range and AC/DC voltage ranges of 0~440V and 0~250V respectively.



Continuity tester (if not included in the multimeter).



Phase angle meter.



Phase rotation meter. NOTE! Modern test set may contain many of the above features in one unit.

Optional equipment: 

An electronic or brushless insulation tester with a DC output not exceeding 500V (for insulation resistance test when required).



A portable PC, with appropriate software (this enables the rear communications port to be tested, if this is to be used, and will also save considerable time during commissioning).



EIA RS-485 to EIA RS-232 converter (if EIA RS-485 IEC60870-5-103 port is being tested).



PCS-900 serials dedicated protection tester HELP-2000.

11.4 Setting Familiarization When commissioning this device for the first time, sufficient time should be allowed to become familiar with the method by which the settings are applied. A detailed description of the menu structure of this relay is contained in Chapter “Operation Theory” and Chapter “Settings”. With the front cover in place all keys are accessible. All menu cells can be read. The LED indicators and alarms can be reset. Protection or configuration settings can be changed, or fault and event records cleared. However, menu cells will require the appropriate password to be entered before changes can be made. Alternatively, if a portable PC is available together with suitable setting software (such as PCS-9700 SAS software), the menu can be viewed one page at a time to display a full column of data and text. This PC software also allows settings to be entered more easily, saved to a file on disk for future reference or printed to produce a setting record. Refer to the PC software user manual for details. If the software is being used for the first time, allow sufficient time to become familiar with its operation. 11-2


11 Commissioning

11.5 Product Checks These product checks cover all aspects of the relay which should be checked to ensure that it has not been physically damaged prior to commissioning, is functioning correctly and all input quantity measurements are within the stated tolerances. If the application-specific settings have been applied to the relay prior to commissioning, it is advisable to make a copy of the settings so as to allow them restoration later. This could be done by extracting the settings from the relay itself via printer or manually creating a setting record.

11.5.1 With the Relay De-energized This relay is fully numerical and the hardware is continuously monitored. Commissioning tests can be kept to a minimum and need only include hardware tests and conjunctive tests. The function tests are carried out according to user’s correlative regulations. The following tests are necessary to ensure the normal operation of the equipment before it is first put into service. 

Hardware tests These tests are performed for the following hardware to ensure that there is no hardware defect. Defects of hardware circuits other than the following can be detected by self-monitoring when the DC power is supplied.



User interfaces test



Binary input circuits and output circuits test



AC input circuits test



Function tests These tests are performed for the following functions that are fully software-based. Tests of the protection schemes and fault locator require a dynamic test set.



Measuring elements test



Timers test



Measurement and recording test



Conjunctive tests The tests are performed after the relay is connected with the primary equipment and other external equipment.



On load test.



Phase sequence check and polarity check.


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11 Commissioning

11.5.1.1 Visual Inspection After unpacking the product, check for any damage to the relay case. If there is any damage, the internal module might also have been affected, contact the vendor. The following items listed is necessary. 

Protection panel Carefully examine the protection panel, protection equipment inside and other parts inside to see that no physical damage has occurred since installation. The rated information of other auxiliary protections should be checked to ensure it is correct for the particular installation.



Panel wiring Check the conducting wire which is used in the panel to assure that their cross section meeting the requirement. Carefully examine the wiring to see that they are no connection failure exists.



Label Check all the isolator binary inputs, terminal blocks, indicators, switches and push buttons to make sure that their labels meet the requirements of this project.



Device plug-in modules Check each plug-in module of the equipments on the panel to make sure that they are well installed into the equipment without any screw loosened.



Earthing cable Check whether the earthing cable from the panel terminal block is safely screwed to the panel steel sheet.



Switch, keypad, isolator binary inputs and push button Check whether all the switches, equipment keypad, isolator binary inputs and push buttons work normally and smoothly.

11.5.1.2 Insulation Test (if required) Insulation resistance tests are only necessary during commissioning if it is required for them to be done and they have not been performed during installation. Isolate all wiring from the earth and test the isolation with an electronic or brushless insulation tester at a DC voltage not exceeding 500V, The circuits need to be tested should include: 

Voltage transformer circuits



Current transformer circuits



DC power supply

11-4


11 Commissioning



Optic-isolated control inputs



Output contacts



Communication ports

The insulation resistance should be greater than 100MΩ at 500V. Test method: To unplug all the terminals sockets of this relay, and do the Insulation resistance test for each circuit above with an electronic or brushless insulation tester. On completion of the insulation resistance tests, ensure all external wiring is correctly reconnected to the protection. 11.5.1.3 External Wiring Check that the external wiring is correct to the relevant relay diagram and scheme diagram. Ensure as far as practical that phasing/phase rotation appears to be as expected. Check the wiring against the schematic diagram for the installation to ensure compliance with the customer’s normal practice. 11.5.1.4 Auxiliary Power Supply The relay only can be operated under the auxiliary power supply depending on the relay’s nominal power supply rating. The incoming voltage must be within the operating range specified in Chapter “Technical Data”, before energizing the relay, measure the auxiliary supply to ensure it within the operating range. Other requirements to the auxiliary power supply are specified in Chapter “Technical Data”. See this section for further details about the parameters of the power supply. WARNING! Energize this relay only if the power supply is within the specified operating ranges in Chapter “Technical Data”.

11.5.2 With the Relay Energized The following groups of checks verify that the relay hardware and software is functioning correctly and should be carried out with the auxiliary supply applied to the relay. The current and voltage transformer connections must remain isolated from the relay for these checks. The trip circuit should also remain isolated to prevent accidental operation of the associated circuit breaker. 11.5.2.1 Front Panel LCD Display Connect the relay to DC power supply correctly and turn the relay on. Check program version and forming time displayed in command menu to ensure that are corresponding to what ordered.


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11 Commissioning

11.5.2.2 Date and Time If the time and date is not being maintained by substation automation system, the date and time should be set manually. Set the date and time to the correct local time and date using menu item “Clock”. In the event of the auxiliary supply failing, with a battery fitted on CPU board, the time and date will be maintained. Therefore when the auxiliary supply is restored the time and date will be correct and not need to set again. To test this, remove the auxiliary supply from the relay for approximately 30s. After being re-energized, the time and date should be correct. 11.5.2.3 Light Emitting Diodes (LEDs) On power up, the green LED “HEALTHY” should have illuminated and stayed on indicating that the relay is healthy. The relay has latched signal relays which remember the state of the trip, auto-reclose when the relay was last energized from an auxiliary supply. Therefore these indicators may also illuminate when the auxiliary supply is applied. If any of these LEDs are on then they should be reset before proceeding with further testing. If the LED successfully reset, the LED goes out. There is no testing required for that that LED because it is known to be operational. It is likely that alarms related to voltage transformer supervision will not reset at this stage. 11.5.2.4 Testing HEALTHY and ALARM LEDs Apply the rated DC power supply and check that the “HEALTHY” LED is lighting in green. We need to emphasize that the “HEALTHY” LED is always lighting in operation course except that the equipment find serious errors in it. Produce one of the abnormal conditions listed in Chapter “Supervision”, the “ALARM” LED will light in yellow. When abnormal condition reset, the “ALARM” LED extinguishes. 11.5.2.5 Testing AC Current Inputs This test verified that the accuracy of current measurement is within the acceptable tolerances. Apply rated current to each current transformer input in turn; checking its magnitude using a multimeter/test set readout. The corresponding reading can then be checked in the relays menu. The measurement accuracy of the protection is 2.5% or 0.02In. However, an additional allowance must be made for the accuracy of the test equipment being used. NOTE! The closing circuit should remain isolated during these checks to prevent accidental operation of the associated circuit breaker. Group No. Three-phase current 1

Item

Input Value

Input Angle

Display Value

Display Angle

Ia

11-6


11 Commissioning Group No.

Item

Input Value

Input Angle

Display Value

Display Angle

Ib Ic Ia Three-phase current 2

Ib Ic Ia

Three-phase current 3

Ib Ic Ia

Three-phase current ……

Ib Ic

11.5.2.6 Testing AC Voltage Inputs This test verified that the accuracy of voltage measurement is within the acceptable tolerances. Apply rated voltage to each voltage transformer input in turn; checking its magnitude using a multimeter/test set readout. The corresponding reading can then be checked in the relays menu. The measurement accuracy of the relay is 2.5% or 0.1V. However an additional allowance must be made for the accuracy of the test equipment being used. NOTE! The closing circuit should remain isolated during these checks to prevent accidental operation of the associated circuit breaker. Group No.

Item

Input Value

Input Angle

Display Value

Display Angle

Ua Three-phase voltage 1

Ub Uc Ua

Three-phase voltage 2

Ub Uc Ua

Three-phase voltage 3

Ub Uc Ua

Three-phase voltage……

Ub Uc

11.5.2.7 Testing Binary Inputs This test checks that all the binary inputs on the equipment are functioning correctly. The binary inputs should be energized one at a time, see external connection diagrams for PCS-985G Generator Relay

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11 Commissioning

terminal numbers. Ensure that the voltage applied on the binary input must be within the operating range. The status of each binary input can be viewed using relay menu. Sign “1” denotes an energized input and sign “0” denotes a de-energized input. Terminal No.

Signal Name

BI Status on LCD

Correct?

Test method: To unplug all the terminals sockets of this protective device, and do the Insulation resistance test for each circuit above with an electronic or brushless insulation tester. On completion of the insulation resistance tests, ensure all external wiring is correctly reconnected to the protection.

11.5.3 Print Fault Report In order to acquire the details of protection operation, it is convenient to print the fault report of protection device. The printing work can be easily finished when operator presses the print button on panel of protection device to energize binary input [BI_Print] or operate control menu. What should be noticed is that only the latest fault report can be printed if operator presses the print button. A complete fault report includes the content shown as follows. 1) Trip event report 2) Binary input when protection devices start 3) Self-check and the transition of binary input in the process of devices start 4) Fault wave forms compatible with COMTRADE 5) The setting value when the protection device trips

11.5.4 On-load Checks The objectives of the on-load checks are: 

Confirm the external wiring to the current and voltage inputs is correct.



Measure the magnitude of on-load current and voltage (if applicable).



Check the polarity of each current transformer.

However, these checks can only be carried out if there are no restrictions preventing the tenderization of the plant being protected. Remove all test leads, temporary shorting leads, etc. and replace any external wiring that has 11-8


11 Commissioning

been removed to allow testing. If it has been necessary to disconnect any of the external wiring from the protection in order to perform any of the foregoing tests, it should be ensured that all connections are replaced in accordance with the relevant external connection or scheme diagram. Confirm current and voltage transformer wiring.

11.6 Final Checks After the above tests are completed, remove all test or temporary shorting leads, etc. If it has been necessary to disconnect any of the external wiring from the protection in order to perform the wiring verification tests, it should be ensured that all connections are replaced in accordance with the relevant external connection or scheme diagram. Ensure that the protection has been restored to service. If the protection is in a new installation or the circuit breaker has just been maintained, the circuit breaker maintenance and current counters should be zero. If a test block is installed, remove the test plug and replace the cover so that the protection is put into service. Ensure that all event records, fault records, disturbance records and alarms have been cleared and LED’s has been reset before leaving the protection.


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11 Commissioning

11-10


12 Maintenance

12 Maintenance Table of Contents 12 Maintenance ................................................................................ 12-a 12.1 Appearance Check ...................................................................................... 12-1 12.2 Failure Tracing and Repair ......................................................................... 12-1 12.3 Replace Failed Modules ............................................................................. 12-1 12.4 Cleaning ....................................................................................................... 12-3 12.5 Storage ......................................................................................................... 12-3


12-a Date: 2013-05-29

12 Maintenance

12-b


12 Maintenance

12.1 Appearance Check 1. The relay case should be clean without any dust stratification. Case cover should be sealed well. No component has any mechanical damage and distortion, and they should be firmly fixed in the case. Relay terminals should be in good condition. The keys on the front panel with very good feeling can be operated flexibly. 2. It is only allowed to plug or withdraw relay board when the supply is reliably switched off. Never allow the CT secondary circuit connected to this equipment to be opened while the primary system is live when withdrawing an AC module. Never try to insert or withdraw the relay board when it is unnecessary. 3. Check weld spots on PCB whether they are well soldered without any rosin joint. All dual inline components must be well plugged.

12.2 Failure Tracing and Repair Failures will be detected by automatic supervision or regular testing. When a failure is detected by supervision, a remote alarm is issued and the failure is indicated on the front panel with LED indicators and LCD display. It is also recorded in the event record. Failures detected by supervision are traced by checking the “Superv Events” screen on the LCD. When a failure is detected during regular testing, confirm the following: 

Test circuit connections are correct



Modules are securely inserted in position



Correct DC power voltage is applied



Correct AC inputs are applied



Test procedures comply with those stated in the manual

12.3 Replace Failed Modules If the failure is identified to be in the relay module and the user has spare modules, the user can recover the protection by replacing the failed modules. Repair at the site should be limited to module replacement. Maintenance at the component level is not recommended. Check that the replacement module has an identical module name (AI, PWR, CPU, SIG, BI, BO, etc.) and hardware type-form as the removed module. Furthermore, the CPU module replaced should have the same software version. In addition, the AI and PWR module replaced should have the same ratings. The module name is indicated on the top front of the module. The software version is indicated in LCD menu “Version Info”.


12-1 Date: 2013-05-29

12 Maintenance

Caution! When handling a module, take anti-static measures such as wearing an earthed wrist band and placing modules on an earthed conductive mat. Otherwise, many of the electronic components could suffer damage. After replacing the CPU module, check the settings. 1)

Replacing a module



Switch off the DC power supply



Disconnect the trip outputs



Short circuit all AC current inputs and disconnect all AC voltage inputs



Unscrew the module. Warning! Hazardous voltage can be present in the DC circuit just after switching off the DC power supply. It takes approximately 30 seconds for the voltage to discharge.

2)

Replacing the Human Machine Interface Module (front panel)



Open the relay front panel



Unplug the ribbon cable on the front panel by pushing the catch outside.



Detach the HMI module from the relay



Attach the replacement module in the reverse procedure.

3)

Replacing the AI, PWR, CPU, BI or BO module



Unscrew the module connector



Unplug the connector from the target module.



Unscrew the module.



Pull out the module



Inset the replacement module in the reverser procedure.



After replacing the CPU module, input the application-specific setting values again. Warning! Units and modules may only be replaced while the supply is switched off and only by appropriately trained and qualified personnel. Strictly observe the basic precautions to guard against electrostatic discharge. Warning!

12-2


12 Maintenance

When handling a module, take anti-static measures such as wearing an earthed wrist band and placing modules on an earthed conductive mat. Otherwise, many of the electronic components could suffer damage. After replacing the CPU module, check the settings. Danger! After replacing modules, be sure to check that the same configuration is set as before the replacement. If this is not the case, there is a danger of the unintended operation of switchgear taking place or of protections not functioning correctly. Persons may also be put in danger.

12.4 Cleaning Before cleaning the relay, ensure that all AC/DC supplies, current transformer connections are isolated to prevent any chance of an electric shock whilst cleaning. Use a smooth cloth to clean the front panel. Do not use abrasive material or detergent chemicals.

12.5 Storage The spare relay or module should be stored in a dry and clean room. Based on IEC standard 60255-1 the storage temperature should be from -40oC to +70oC, but the temperature of from 0oC to +40oC is recommended for long-term storage.


12-3 Date: 2013-05-29

12 Maintenance

12-4


13 Decommissioning and Disposal

13 Decommissioning and Disposal Table of Contents 13 Decommissioning and Disposal ................................................ 13-a 13.1 Decommissioning ....................................................................................... 13-1 13.2 Disposal ....................................................................................................... 13-1


13-a Date: 2013-05-29


13-b



13.1 Decommissioning 1.

Switching off

To switch off the PCS-985G, switch off the external miniature circuit breaker of the power supply. 2.

Disconnecting Cables

Disconnect the cables in accordance with the rules and recommendations made by relational department. Danger! Before disconnecting the power supply cables that connected with the PWR module of the PCS-985G, make sure that the external miniature circuit breaker of the power supply is switched off. Danger! Before disconnecting the cables that are used to connect analog input module with the primary CTs and VTs, make sure that the circuit breaker for the primary CTs and VTs is switched off. 3.

Dismantling

The PCS-985G rack may now be removed from the system cubicle, after which the cubicles may also be removed. Danger! When the station is in operation, make sure that there is an adequate safety distance to live parts, especially as dismantling is often performed by unskilled personnel.

13.2 Disposal In every country there are companies specialized in the proper disposal of electronic waste. Note! Strictly observe all local and national regulations when disposing of the device.


13-1 Date: 2013-05-29


13-2


14 Manual Version History

14 Manual Version History In the latest version of the instruction manual, several descriptions on existing features have been modified. Manual version and modification history records Manual Version Source

Software

New

Version

R1.00

R2.11

Date 2013-07-10

Description of change Form the original manual.


14-1 Date: 2013-07-10

14 Manual Version History


14-2 Date: 2013-07-10

NARI PCS-985G Generator Relay

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