Training On Power System Protection Relaying
APPS Training - 2008 TECHNICAL TRAINING ENERGIZE YOUR EXPERTISE TRAINING ON POWER SYSTEM PROTECTION RELAYING AREVA T
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APPS Training - 2008
TECHNICAL TRAINING
ENERGIZE YOUR EXPERTISE
TRAINING ON POWER SYSTEM PROTECTION RELAYING
AREVA T&D
Basic Protection Philosophy
> Basic Protection Philosophy - January 2004
Protection - Why Is It Needed? All Power Systems may experience faults at some time. PROTECTION IS INSTALLED TO : X Detect fault occurrence and isolate the faulted equipment. SO THAT : X Damage to the faulted equipment is limited; X Disruption of supplies to adjacent unfaulted equipment is minimised. PROTECTION IS EFFECTIVELY AN INSURANCE POLICY - AN INVESTMENT AGAINST DAMAGE FROM FUTURE FAULTS. > Basic Protection Philosophy - January 2004
Protection - Why Is It Needed? FAULTS ON POWER SYSTEMS RISK : Severe damage to the faulted equipment : X Excessive current may flow; X Causes burning of conductors or equipment windings; X Arcing - energy dissipation; X Risk of explosions for oil - filled switchgear, or when in hazardous environments. Damage to adjacent plant : X As the fault evolves, if not cleared quickly; X Due to the voltage depression / loss of supply. > Basic Protection Philosophy - January 2004
Protection - Why Is It Needed? FAULTS ON POWER SYSTEMS RISK : Danger to staff or the public : X Risk of shock from direct contact with the faulted equipment; X Danger of potential (voltage) rises in exposed metalwork – accessible to touch; X Fumes released by burning insulation; X Burns etc. Disruption to adjacent plant : X Prolonged voltage dips cause motors to stall; X Loss of synchronism for synchronous generators / motors. > Basic Protection Philosophy - January 2004
Protection - Why Is It Needed?
SUMMARY : Protection must : X Detect faults and abnormal operating conditions; X Isolate the faulted equipment. So as to : X Limit damage caused by fault energy; X Limit effect on rest of system.
> Basic Protection Philosophy - January 2004
Important Considerations When Applying Protection X X X X X X X X X X X X X X
Types of fault and abnormal conditions to be protected against Quantities available for measurement Types of protection available Speed Fault position discrimination Dependability / Reliability Security / Stability Overlap of protections Phase discrimination / Selectivity CTs and VTs Auxiliary supplies Back-up protection Cost Duplication of protection
> Basic Protection Philosophy - January 2004
Faults Are Mainly Caused By Insulation Failure
Underground Cables
Diggers Overloading Oil Leakage Ageing
> Basic Protection Philosophy - January 2004
Faults Are Mainly Caused By Insulation Failure
Overhead Lines Lightning Kites Trees Moisture Salt Birds Broken Conductors
> Basic Protection Philosophy - January 2004
Faults Are Mainly Caused By Insulation Failure
Machines Mechanical Damage Unbalanced Load
> Basic Protection Philosophy - January 2004
Types of Fault Ø/E
a b c e
Ø/Ø/E
a b c e
Ø/Ø
3Ø
a b c
a b c
3Ø/E
a b c e
> Basic Protection Philosophy - January 2004
Types of Fault
CROSS COUNTRY FAULT
a
a'
b
b'
c
c'
e
e
> Basic Protection Philosophy - January 2004
Types of Fault a OPEN CIRCUIT + Ø/E
b c e
FAULT BETWEEN ADJACENT PARALLEL LINES
> Basic Protection Philosophy - January 2004
Types of Fault
a CHANGING FAULT IN CABLE b
c
> Basic Protection Philosophy - January 2004
Types Of Protection
> Basic Protection Philosophy - January 2004
Types of Protection X Fuses For : LV Systems, Distribution Feeders and Transformers, VTs, Auxiliary Supplies X Direct Acting AC Trip For : LV Systems, Pole Mounted Reclosers X Overcurrent and Earthfault Widely used in all Power Systems Non-Directional Voltage Dependant Directional
> Basic Protection Philosophy - January 2004
Types of Protection
X Differential For : Feeders, Busbars, Transformers, Generators, etc. High Impedance Restricted E/F Biased (or low-impedance) Pilot Wire Digital
> Basic Protection Philosophy - January 2004
Types of Protection
X Distance For : Distribution Feeders and Transmission and Sub-Transmission Circuits Also used as Back-up Protection for Transformers and Generators X Phase Comparison For : Transmission Lines X Directional Comparison For : Transmission Lines
> Basic Protection Philosophy - January 2004
Types of Protection X Miscellaneous Under and Over Voltage Under and Over Frequency Special Relays for Generators, Transformers, Motors, etc. X Control Relays Auto-Reclose, Tap Change Control, etc. X Tripping and Auxiliary Relays
> Basic Protection Philosophy - January 2004
Overcurrent Protection Direct Acting AC Trip
51
Trip Coil IF
X AC series trip common for electromechanical O/C relays > Basic Protection Philosophy - January 2004
Overcurrent Protection Direct Acting AC Trip
IF ' +
51 -
Sensitive Trip Coil
IF
X Capacitor discharge trip used with static relays where no secure DC supply is available > Basic Protection Philosophy - January 2004
Overcurrent Protection DC Shunt Trip IF IF '
51
DC BATTERY
X Requires secure DC auxiliary No trip if DC fails > Basic Protection Philosophy - January 2004
SHUNT TRIP COIL
Overcurrent Protection Co-ordination Principle
R2
R1
IF1 T
IS2 IS1
> Basic Protection Philosophy - January 2004
Maximum Fault Level
I
X Relay closest to fault must operate first X Other relays must have adequate additional operating time to prevent them operating X Current setting chosen to allow FLC X Consider worst case conditions, operating modes and current flows
Differential Protection Principle (1)
Protected Circuit
R
> Basic Protection Philosophy - January 2004
Differential Protection Principle (2)
Protected Circuit
R
> Basic Protection Philosophy - January 2004
Basic Principle of Distance Protection
ZS
Relay PT.
VS
ZLOAD
VR
Impedance measured
> Basic Protection Philosophy - January 2004
ZL
IR
ZR =
Normal Load
VR = Z L + Z LOAD ΙR
Basic Principle of Distance Protection ZL ZS
VS
IR
ZF
VR
ZLOAD
Fault
X Impedance Measured ZR = VR/IR = ZF X Relay Operates if ZF < Z
where Z = setting
X Increasing VR has a Restraining Effect ∴VR called Restraining Voltage X Increasing IR has an Operating Effect > Basic Protection Philosophy - January 2004
Plain Impedance Characteristic
jX
ZL
Impedance Seen At Measuring Location For Line Faults
R TRIP
> Basic Protection Philosophy - January 2004
STABLE
Impedance Characteristic Generation
IF
jIX
zF
IZ V3
VF
V1
V2
IR TRIP
Trip
STABLE
Spring
Restrain
Ampere Turns :
Operate VF
IZ
Trip Conditions : VF < IFZ
Voltage to Relay = Current to Relay = Replica Impedance =
V I Z
Trip Condition :
S2 < S1
where : S1 = IZ ≈ Z S2 = V ≈ ZF
> Basic Protection Philosophy - January 2004
Buchholz Relay Installation 3 x internal pipe diameter (minimum)
Conservator
5 x internal pipe diameter (minimum)
Oil conservator 3 minimum Transformer
> Basic Protection Philosophy - January 2004
Autoreclose Benefits (1) X Improved continuity of supply Supply restoration is automatic (does not require human intervention) Shorter duration interruptions Less consumer hours lost X Use of instantaneous protection for faster fault clearance (NB: some healthy circuits may also be tripped) Less damage Less pre-heating of circuit breaker contacts (reduced maintenance?) Less chance of transient fault becoming permanent
> Basic Protection Philosophy - January 2004
Autoreclose Benefits (2) X Less frequent visits to substations
More unmanned substations Reduced operating costs
> Basic Protection Philosophy - January 2004
Definitions & Considerations
> Basic Protection Philosophy - January 2004
Classes of Protection Non-Unit, or Unrestricted Protection : No specific point downstream up to which protection will protect X Will operate for faults on the protected equipment; X May also operate for faults on downstream equipment, which has its own protection; X Need for discrimination with downstream protection, usually by means of time grading.
> Basic Protection Philosophy - January 2004
Classes of Protection
Unit, or Restricted Protection : Has an accurately defined zone of protection X An item of power system plant is protected as a unit; X Will not operate for out of zone faults, thus no back-up protection for downstream faults.
> Basic Protection Philosophy - January 2004
Co-ordination
LOAD SOURCE LOAD LOAD
F1
LOAD
F2
F3
Co-ordinate protection so that relay nearest to fault operates first – minimises amount of system disconnection.
> Basic Protection Philosophy - January 2004
ANSI Reference Numbers
2 21 25 27 30 32 37 40 46 49 50 79 81 85 86
Time Delay Distance Synchronising Check Undervoltage Annunciator Directional Power Undercurrent or Under Power Field Failure Negative Sequence Thermal Instantaneous Overcurrent Auto-Reclose Frequency Signal Receive Lock-Out
> Basic Protection Philosophy - January 2004
51 51N 52 52a 52b 59 60 64 67 67N 74
Time Delayed Overcurrent Time Delayed Earthfault Circuit Breaker Auxiliary Switch - Normally Open Auxiliary Switch - Normally Closed Overvoltage Voltage or Current Balance Instantaneous Earth Fault (High Impedance) Directional Overcurrent Directional Earthfault Alarm
85 86 87
Signal Receive Lock-Out Differential
Important Considerations When Applying Protection
X Speed Fast operation : Minimises damage and danger Very fast operation : Minimises system instability Discrimination and security can be costly to achieve as it generally involves additional signaling / communications equipment.
> Basic Protection Philosophy - January 2004
Important Considerations When Applying Protection
X Fault Position Discrimination Power system divided into PROTECTED ZONES Must isolate only the faulty equipment or section
> Basic Protection Philosophy - January 2004
Zones of Protection TRANSF- BUSBAR ZONE ORMER ZONE
BUSBAR ZONE FEEDER ZONE GENERATION ZONE
BUSBAR ZONE
> Basic Protection Philosophy - January 2004
FEEDER ZONE
Important Considerations When Applying Protection
X Overlap of Protections No blind spots Where possible use overlapping CTs
> Basic Protection Philosophy - January 2004
Protection Overlap
BBP ‘1’
BBP ‘2’
J
H
‘Z’ G
LP ‘H’
LP ‘J’
L
K
LP ‘K’
> Basic Protection Philosophy - January 2004
LP ‘L’
Important Considerations When Applying Protection
X Dependability / Reliability Protection must operate when required to Failure to operate can be extremely damaging and disruptive Faults are rare. Protection must operate even after years of inactivity Improved by use of: duplicate protection
> Basic Protection Philosophy - January 2004
Back-up protection and
Important Considerations When Applying Protection
X Security / Stability Protection must not operate when not required to, e.g. due to : Load switching Faults on other parts of the system Recoverable power swings
> Basic Protection Philosophy - January 2004
Important Considerations When Applying Protection
X Phase Discrimination Correct indication of phases involved in the fault Important for single phase tripping and autoreclosing applications
> Basic Protection Philosophy - January 2004
Cost
The cost of protection is equivalent to an insurance policy against damage to plant, and loss of supply and customer goodwill. Acceptable cost is based on a balance of economics and technical factors. Cost of protection should be balanced against the cost of potential hazards. There is an economic limit on what can be spent. MINIMUM COST : Must ensure that all faulty equipment is isolated by protection. > Basic Protection Philosophy - January 2004
Cost
TOTAL COST should take account of : X Relays, schemes and associated panels and panel wiring X Setting studies X Commissioning X CTs and VTs X Maintenance and repairs to relays X Damage repair if protection fails to operate X Lost revenue if protection operates unnecessarily
> Basic Protection Philosophy - January 2004
Cost DISTRIBUTION SYSTEMS X Large numbers of switching and distribution points, transformers and feeders X Economics often overrides technical issues X Protection may be the minimum consistent with statutory safety regulations X Speed less important than on transmission systems X Back-up protection can be simple and is often inherent in the main protection X Although important, the consequences of maloperation or failure to operate is less serious than for transmission systems > Basic Protection Philosophy - January 2004
Cost TRANSMISSION SYSTEMS X Emphasis is on technical considerations rather than economics X Economics cannot be ignored but is of secondary importance compared with the need for highly reliable, fully discriminative high speed protection X Higher protection costs justifiable by high capital cost of power system elements protected X Risk of security of supply should be reduced to lowest practical levels X High speed protection requires unit protection X Duplicate protections used to improve reliability X Single phase tripping and auto-reclose may be required to maintain system stability > Basic Protection Philosophy - January 2004
Important Considerations When Applying Protection Current and Voltage Transformers X These are an essential part of the protection scheme to reduce primary current and volts to a low level suitable to input to relay. X They must be suitably specified to meet the requirements of the protective relays. X Correct connection of CTs and VTs to the protection is important. In particular for directional, distance, phase comparison and differential protections. X VTs may be electromagnetic or capacitor types. X Busbar VTs : Special consideration needed when used for line protection. > Basic Protection Philosophy - January 2004
Current Transformer Circuits
X X X X
Never open circuit a CT secondary circuit, so : Never fuse CT circuits; VTs must be fused or protected by MCB. Do wire test blocks in circuit (both VT and CT) to allow commissioning and periodic injection testing of relays. X Earth CT and VT circuits at one point only; Wire gauge > 2.5mm2 recommended for mechanical strength.
> Basic Protection Philosophy - January 2004
Auxiliary Supplies Required for : TRIPPING CIRCUIT BREAKERS CLOSING CIRCUIT BREAKERS PROTECTION and TRIP RELAYS AC AUXILIARY SUPPLIES are only used on LV and MV systems. DC AUXILIARY SUPPLIES are more secure than AC supplies. SEPARATELY FUSED SUPPLIES used for each protection. DUPLICATE BATTERIES are occasionally provided for extra security. MODERN PROTECTION RELAYS need a continuous auxiliary supply. During unoperated (healthy) conditions, they draw a small ‘QUIESCENT’ load to keep relay circuits energised. During operation, they draw a larger current which increases due to operation of output elements.
> Basic Protection Philosophy - January 2004
Relay Outputs TRIP OUTPUT CONTACTS : X Check that these are rated sufficiently to make and carry the circuit breaker trip coil current. If not, a heavier duty tripping relay will be needed. X Use a circuit breaker normally open (52a) contact to interrupt trip coil current. This extends the life of the protection relay trip contacts. TYPE OF CONTACTS : Make (M) / Normally Open (NO)
Close when energised, typically used for tripping.
Break (B) / Normally Closed (NC)
Close when de-energised.
Changeover (C/O)
Can be break before make (BBM) or make before break (MBB).
> Basic Protection Philosophy - January 2004
Design and Application of Protective Relay Equipment
EAI Field of Activities Level AREVA T&D EMM
National Control
4 WAN
Area Control
3 LAN 2 AREVA T&D P&C
Substation LAN Bay
1 Field Bus 0
3
> Relay design tutorial - Feb 2005
Optical transducers CT & VT
Field
3
Protective Relays Primary Function
¾ Detection of faults on primary power system plant
Feeders Transformers Busbar Generators Motors ¾ The relay must identify faults on the protected plant section and isolate this from power system. ¾ The relay should remain stable for faults, or system instabilities outside of protected section, unless required to do so as back-up protection. 4
> Relay design tutorial - Feb 2005
4
Design of Modern Protective Relaying Equipment
Outline ¾ What technologies have been employed ¾ What are the key elements of modern protective relays ¾ Design Considerations ¾ Impact on the Design of protection and control systems
5
> Relay design tutorial - Feb 2005
5
Protective Relays Technologies Employed (1) ¾ ELECTROMECHANICAL (1950) These relays typically use attracted armature or induction disc type elements to implement the protection functions. The emphasis is on an electromagnetic force causing mechanical operation of the relay. ¾ Single Function Devices ¾ Configured by selection and manual settings ¾ Outputs via contact, need for auxiliary relays ¾ Local Indications via Flag
6
> Relay design tutorial - Feb 2005
6
Protective Relays Technologies Employed (2) ¾ STATIC (1970) Static implies that the relay does not have moving parts to create its characteristic, however the trip output contacts would generally be of attracted armature type. Static relays use discrete electronic components (generally analogue devices) for creation of the operating characteristics. ¾ More Compact, higher level of integration ¾ Lower maintenance ¾ Configuration via switches ¾ Indication via LED
7
> Relay design tutorial - Feb 2005
7
Protective Relays Technologies Employed (3) ¾ DIGITAL (1980) Digital relays use microprocessors/micro-controllers to implement protection elements, rather than relying on discrete analogue components. Protection functions are not generally implemented by mathematical algorithms - the only numerical states within the relay are high/low logic (logic one or zero). ¾ Internal logic is more flexible using DIP switches ¾ Devices and smaller, less expensive ¾ Use of keypad/LED interfaces on some digital units ¾ Application of scheme not significantly altered
8
> Relay design tutorial - Feb 2005
8
Protective Relays Technologies Employed (4) ¾ NUMERICAL (Today) Numerical technology implies sampling of the relay inputs, then A/D conversion into number format. These numbers are then used by mathematical algorithms which generate the relay operating characteristics. Integration of multiple protection and control functional blocks High level of flexibility Each device implements complex submodule of complete scheme Integrated measurement and recording facilities Advanced communication facilities
9
> Relay design tutorial - Feb 2005
9
Protective Relay Key Elements - contextual Level National Control
4 WAN
Area Control
3 LAN 2
Substation LAN Bay
1 Field Bus 0
10
> Relay design tutorial - Feb 2005
Optical transducers CT & VT
Field
10
Protective Relay Design Key Elements - implementation Power Supply
Digital Outputs
Digital Inputs
(Relays)
(Optos)
Analogue to Digital Conversion
Analogue Inputs
Interconnection Bus
Signal Processing
11
> Relay design tutorial - Feb 2005
Communications
User Interface (HMI)
11
Protective Relay Design - A Modular Approach Power Supply
Digital Outputs
Digital Inputs
(Relays)
(Optos)
Analogue to Digital Conversion
Analogue Inputs
Interconnection Bus
Signal Processing
12
> Relay design tutorial - Feb 2005
Communications
User Interface (HMI)
12
Analogue Inputs Isolation
Filter
Multiplexer
V Sample
ADC 1011011...
I
Requires accurate measurements Calibrate for Magnitude and phase error Dynamic range (Fault and load conditions) Tranducers Digital conversion Sample rate - protection elements and recording 13
> Relay design tutorial - Feb 2005
13
Analogue Input Limiting +Vref Vref V in
Vout
Vref
-Vref Input signal must not exceed electronic circuitry operating voltage
14
> Relay design tutorial - Feb 2005
14
Input Signal Problem - Scew Correction
Multiplexer
Inputs sampled sequentially Most widely used (cheaper - only 1 A-D required) Scew correction?
15
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A-D Conversion 1
N-bit A/D converter
Analogue sample magnitude
Digital number
for 12-bit A/D :212 = 4096 digital number values possible
16
> Relay design tutorial - Feb 2005
16
A-D Conversion 2 Example ± 10V, 12-bit A/D
+10V 5V 0
xn = 5 x 4096 (10 + 10) = 1024
-10V 5V -5V
1024 -1024
0100 0000 0000 1100 0000 0000 Sign bit
17
> Relay design tutorial - Feb 2005
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Input Signal Problem - Conversion Errors
10110111...
Dynamic Range, Quantisation Effects 12 bit ADC equivalent to 4096 numbers For dynamic range of 64 In Resolution = 30mA (In = 1A) For 16bit, resolution = 2mA
18
> Relay design tutorial - Feb 2005
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Signal Distortion - Aliasing Sampling element Apparent Signal
Actual Signal
Sample Points Sampled waveform appears to be a lower frequency This phenomena is known as ALIASING Eliminate aliasing using a low pass filter 19
> Relay design tutorial - Feb 2005
19
Input Signal Problem - CT Saturation Ip
Φsat Average flux Is
Saturation of the CT magnetic core causes : Current waveform distortion Harmonics 20
> Relay design tutorial - Feb 2005
20
Input Signal Problem - CT Saturation Solution To ensure correct relay operation when waveform is distorted: Eliminate aliasing - (low pass filter) Extract fundamental component - (Fourier filter)
21
> Relay design tutorial - Feb 2005
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Non-conventional Instrument Transformers
¾ Use of alternative technologies to measure voltage and current ¾ Improved linearity ¾ Interface unit to convert to sampled data ¾ Fixed sample rate ¾ Interface is via digital link
Electrical - RS485 Fibre - Ethernet ¾ Example shows nonconventional CT
22
> Relay design tutorial - Feb 2005
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Power Supply
Digital Outputs
Digital Inputs
(Relays)
(Optos)
Analogue to Digital Conversion
Analogue Inputs
Interconnection Bus
Signal Processing
23
> Relay design tutorial - Feb 2005
Communications
User Interface (HMI)
23
Digital Outputs Miniature relays
8-bit data
Verify
24
> Relay design tutorial - Feb 2005
24
Power Supply
Digital Outputs
Digital Inputs
(Relays)
(Optos)
Analogue to Digital Conversion
Analogue Inputs
Interconnection Bus
Signal Processing
25
> Relay design tutorial - Feb 2005
Communications
User Interface (HMI)
25
Digital Inputs Considerations
¾ Wetting currents ¾ Burden ¾ Isolation ¾ How many ? ¾ How fast ? ¾ Thermal dissipation ¾ Safety ¾ Operation for different voltage levels
26
> Relay design tutorial - Feb 2005
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Digital Inputs Operation External Trigger +
+5V Input state (Block Operation ?)
Station battery
0V Strobe Mono-stable
--
27
0V Opto isolation
> Relay design tutorial - Feb 2005
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Protective Relay Design - A Modular Approach Power Supply
Digital Outputs
Digital Inputs
(Relays)
(Optos)
Analogue to Digital Conversion
Analogue Inputs
Interconnection Bus
Signal Processing
28
> Relay design tutorial - Feb 2005
Communications
User Interface (HMI)
28
User Interface Front panel
Fixed function LEDs
Alarm viewer
Menu browser
Programmable LEDs
Battery back-up
Download/ Monitor port
Local communications MiCOM_29 29
> Relay design tutorial - Feb 2005
29
Integrated Protection and Bay Control
30
> Relay design tutorial - Feb 2005
30
Protective Relay Design - A Modular Approach Power Supply
Digital Outputs
Digital Inputs
(Relays)
(Optos)
Analogue to Digital Conversion
Analogue Inputs
Interconnection Bus
Signal Processing
31
> Relay design tutorial - Feb 2005
Communications
User Interface (HMI)
31
Communications
Standards Protocols Media
z Modbus z DNP3.0 z IEC60870-5-103 z UCA2 z IEC61850
RS485/Fibre/Ethernet
32
> Relay design tutorial - Feb 2005
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Protective Relay Design - computing Power Supply
Digital Outputs
Digital Inputs
(Relays)
(Optos)
Analogue to Digital Conversion
Analogue Inputs
Interconnection Bus
Signal Processing
Communications
User Interface (HMI)
Software
33
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Computing Unit - Hardware
¾ Microprocessors:
Microcontroller Digital Signal Processor ¾ Memory
RAM FLASH EPROM NV RAM ¾ Real-time Clock ¾ User Interface ¾ Communication Interfaces
34
> Relay design tutorial - Feb 2005
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Computing Unit - Software z
Application Software Operating Communications Platform BIOS Hardware
35
> Relay design tutorial - Feb 2005
Software – – – – – – – – –
Acquisition Filters Algorithms Scheme logic Communications Event logging Recording HMI RTOS
35
Software Design(1)
¾ Multi-tasking operating system
Threads of execution ¾ Task priorities ¾ Interrupts for time critical information ¾ Polling for other data ¾ Deterministic operation of protection functions ¾ Use of structured design ¾ Aim for re-usable code modules
36
> Relay design tutorial - Feb 2005
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Software Design (2) Signal Processing
¾ Accurate operation of measurement imperative ¾ Most relays operate on power system fundamental quantities ¾ Possible causes of interference
DC Offset CT Saturation Primary distortions (DC conversion, series capacitors, standing wave oscillation, noisy loads)
Capacitor voltage transformer transients ¾ Balance of requirements
Speed / Stability 37
> Relay design tutorial - Feb 2005
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Protective Relaying Equipment Other considerations ¾ Design for manufacture ¾ Field maintenance and diagnostics ¾ Performance requirements
IEC 60255 . . . ¾ Mandatory requirements
CE marking z
LVD
z
EMC
¾ Changes to Legislation
Environmental (WEEE Directive) Safety issues (Company liability) 38
> Relay design tutorial - Feb 2005
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Numerical Relays Physical Structure
39
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Testing of Numerical Relays
¾ Algorithm simulation ¾ Module testing ¾ Integration testing ¾ Environmental testing ¾ Automated testing ¾ System simulation tests
RTDS shown ¾ Complex functionality requires extensive testing ¾ Software modifications require regression tests
40
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External Influences on Relay design
¾ Global Products
Language issues Local practices ¾ Customer changes
Privatisation Loss of skills ¾ Environmental Issues ¾ Technology
Component obsolescence ¾ Competition
41
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Modern numeric protection additional features Bay Monitoring & Control
Programmability & Customisation
Comprehensive Protection Instrumentation Self Diagnostics & Commissioning Tools Communications
42
> Relay design tutorial - Feb 2005
Fault Analysis Tools
42
Instrumentation ¾ Instantaneous measurements (fundamental)
Phase and line voltages and currents Sequence Quantities ¾ RMS measurements ¾ Frequency ¾ Thermal state ¾ Single and three phase power ¾ Active, reactive and apparent power ¾ Peak, average and rolling demand ¾ RTD (Resistive Temperature Device) ¾ Check sync values (angle and slip frequency) ¾ Hardware - dynamic range CT/VT requirements MiCOM40-43 43
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Disturbance Records
zAnalogue and digital channels zHigh resolution recording MiCOM40-44B 44
zPermits post-fault analysis > Relay design tutorial - Feb 2005
44
Event Recording
45
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Customisation : Programmable Scheme Logic
Optos
&
Protection Elements
Relay contacts
Gate Logic
1 & Timers
Control Fixed scheme logic
46
LEDs User programmable scheme logic
> Relay design tutorial - Feb 2005
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Self Diagnostics & Commissioning ¾Self diagnostics
¾ Commissioning features available to user Power-on diagnostics Input states Continuous self-monitoring Output states Condition based Internal logic status maintenance for plant Measurements
MiCOM_47 47
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Application of Electromechanical Relays ¾ Relay selected to form complete protection scheme ¾ Each function is contained within a separate unit ¾ Control logic is implemented by hardwiring protection relays with auxiliary relays ¾ Limited Information is available locally
48
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Substation based on Electromechanical Relays
49
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Scheme design using static/digital relays
¾ As devices remain single function relays are combined using hardwired logic. ¾ Specific logic functions can be implemented within a device-with some customisation options ¾ Use of early Substation control systems to gather information - inputs taken from output contacts ¾ Measurement and recording facilities available within separate units - transfer of measured data using analogue interface
50
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Numerical Relays - Impact on Scheme Design
¾ Integration of a suite of protection and control functions ¾ Each product replaces several discrete relays ¾ Requirement for flexibility as to how these functions are combined (previously controlled by external wiring) ¾ Allocation of functions to physical inputs/outputs ¾ Interface into sub-station control system (SCADA)
Hardwired link Use of communications ¾ Management of information
51
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Scheme Implementation using Programmable Logic
Physical Inputs
Protection Function
Physical Outputs
Protection Programmable Function Logic
Local Indications
Control Inputs
Control Function
System Indications
Scheme Subsystem 52
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Programming the Relay
53
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Application of P&C Schemes ¾ Integration of Scheme sub-modules within each device ¾ Use of programmable logic to implement scheme ¾ Scheme defined by:
Hardwired connections Relay selection and configuration Programmable logic ¾ Bay-control functions
May be within Bay computer Peer-peer communications available within new protocols ¾ IEDs (Relays, Measurement devices, RTU) collect data ¾ Data management to provide upstream information
54
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Ethernet Based Sub-station Master clock (GPS) WEB access
SCADA Interface DNP3 & IEC 60870-5-101
Hubs
Fast Ethernet UCA2-IEC 61850
Hubs HV FEEDER BAY
HV FEEDER BAY Hubs
Hubs
I/Os I/Os COMMON BAY
TRANSFORMER BAY
55
> Relay design tutorial - Feb 2005
MV FEEDER BAYS
Cubicle/Switchboard integration
EXISTING MV FEEDER BAYS 55 55
Protection Scheme using Numeric Products
56
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Numerical Relays - what are the benefits ? ¾ Additional features found in numerical relays
Multiple functions in same relay Scheme logic Intelligent Communications Fault recording Re-configurable inputs and outputs Programmable logic ¾ Flexibility
Soft-configured for application Common hardware ¾ Cost-Effective ¾ Reliability, repeatability, ….
57
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Fault Analysis
Power System Fault Analysis (1) All Protection Engineers should have an understanding TO :z
z
z
z
z z
z z z 3
Calculate Power System Currents and Voltages during Fault Conditions Check that Breaking Capacity of Switchgear is Not Exceeded Determine the Quantities which can be used by Relays to Distinguish Between Healthy (i.e. Loaded) and Fault Conditions Appreciate the Effect of the Method of Earthing on the Detection of Earth Faults Select the Best Relay Characteristics for Fault Detection Ensure that Load and Short Circuit Ratings of Plant are Not Exceeded Select Relay Settings for Fault Detection and Discrimination Understand Principles of Relay Operation Conduct Post Fault Analysis
> Fault Analysis – January 2004
3
Power System Fault Analysis (2)
Power System Fault Analysis also used to :-
X Consider Stability Conditions
Required fault clearance times Need for 1 phase or 3 phase auto-reclose
4
> Fault Analysis – January 2004
4
Vectors
Vector notation can be used to represent phase relationship between electrical quantities. Z
I
V
θ
V = Vsinwt = V ∠0° I = I ∠-θ° = Isin(wt-θ)
5
> Fault Analysis – January 2004
5
j Operator Rotates vectors by 90° anticlockwise : j = 1 ∠90°
90° j2 = 1 ∠180° = -1
90° 1
90°
90°
j3 = 1 ∠270° = -j
Used to express vectors in terms of “real” and “imaginary” parts. 6
> Fault Analysis – January 2004
6
a = 1 ∠120 ° Rotates vectors by 120° anticlockwise Used extensively in “Symmetrical Component Analysis”
1 3 a = 1∠120° = - + j 2 2 120°
120°
1 120°
1 3 a = 1∠240° = − − j 2 2 2
7
> Fault Analysis – January 2004
7
a = 1 ∠120 ° Balanced 3Ø voltages :VC = aVA
a2 + a + 1 = 0
VA
VB = a2VA
8
> Fault Analysis – January 2004
8
Balanced Faults
9
> Fault Analysis – January 2004
9
Balanced (3Ø) Faults (1) X RARE :- Majority of Faults are Unbalanced X CAUSES :1. System Energisation with Maintenance Earthing Clamps still connected. 2. 1Ø Faults developing into 3Ø Faults
X 3Ø FAULTS MAY BE REPRESENTED BY 1Ø CIRCUIT Valid because system is maintained in a BALANCED state during the fault Voltages equal and 120° apart Currents equal and 120° apart Power System Plant Symmetrical Phase Impedances Equal Mutual Impedances Equal Shunt Admittances Equal 10
> Fault Analysis – January 2004
10
Balanced (3Ø) Faults (2)
TRANSFORMER LINE ‘X’
GENERATOR
LINE ‘Y’ LOADS 3Ø FAULT
Ea
ZG
ZT
ZLX
IaF
Eb
IbF
Ec
IcF
ZLY
ZLOAD
11
> Fault Analysis – January 2004
11
Balanced (3Ø) Faults (3) IcF
Ea
IaF
Eb
Ec
IbF Positive Sequence (Single Phase) Circuit :Ea ZG1 ZT1 ZLX1 Ia1 = IaF
F1
ZLX2 ZLOAD N1
12
> Fault Analysis – January 2004
12
Representation of Plant
13
> Fault Analysis – January 2004
13
Generator Short Circuit Current The AC Symmetrical component of the short circuit current varies with time due to effect of armature reaction.
i TIME
Magnitude (RMS) of current at any time t after instant of short circuit :
Ι ac = (Ι" - Ι' )e- t/Td" + (Ι' - Ι )e- t/Td' + Ι where : I" =
14
I'
=
I
=
Initial Symmetrical S/C Current or Subtransient Current = E/Xd" ≈ 50ms Symmetrical Current a Few Cycles Later ≈ 0.5s or Transient Current = E/Xd' Symmetrical Steady State Current = E/Xd
> Fault Analysis – January 2004
14
Simple Generator Models
Generator model X will vary with time. Xd" - Xd' - Xd
X
E
15
> Fault Analysis – January 2004
15
Parallel Generators 11kV
11kV XG=0.2pu
j0.05
j0.1
11kV
20MVA
XG=0.2pu
20MVA
If both generator EMF’s are equal ∴ they can be thought of as resulting from the same ideal source - thus the circuit can be simplified.
16
> Fault Analysis – January 2004
16
P.U. Diagram
j0.05
j0.2
j0.1
j0.05
j0.2
j0.2 IF
1.0
17
1.0
> Fault Analysis – January 2004
⇒
j0.1
j0.2 IF
1.0
17
Positive Sequence Impedances of Transformers 2 Winding Transformers P
P1
S
ZS
ZP
S1
ZM N1
P1
ZT1 = ZP + ZS
ZP
=
Primary Leakage Reactance
ZS
=
Secondary Leakage Reactance
ZM
= =
Magnetising impedance Large compared with ZP and ZS
ZM
Æ Infinity ∴ Represented by an Open Circuit
ZT1 =
S1
N1 18
> Fault Analysis – January 2004
ZP + ZS = Positive Sequence Impedance
ZP and ZS both expressed on same voltage base. 18
Motors X Fault current contribution decays with time X Decay rate of the current depends on the system. From tests, typical decay rate is 100 - 150mS. X Typically modelled as a voltage behind an impedance
Xd"
M
19
> Fault Analysis – January 2004
1.0
19
Induction Motors – IEEE Recommendations Small Motors Motor load 35kW SCM = 4 x sum of FLCM
Large Motors SCM ≈ motor full load amps Xd"
Approximation :
20
> Fault Analysis – January 2004
SCM =
locked rotor amps
SCM =
5 x FLCM ≈ assumes motor impedance 20%
20
Synchronous Motors – IEEE Recommendations
Large Synchronous Motors SCM ≈ 6.7 x FLCM for 1200 rpm
21
Assumes X"d = 15%
≈ 5 x FLCM for 514 - 900 rpm
Assumes X"d = 20%
≈ 3.6 x FLCM for 450 rpm or less
Assumes X"d = 28%
> Fault Analysis – January 2004
21
Analysis of Balanced Faults
22
> Fault Analysis – January 2004
22
Different Voltages – How Do We Analyse?
11/132kV 50mVA
11kV 20mVA ZG=0.3pu
23
> Fault Analysis – January 2004
ZT=10%
O/H Line ZL=40Ω
132/33kV 50mVA
ZT=10%
Feeder ZL=8Ω
23
Per Unit System
Used to simplify calculations on systems with more than 2 voltages.
Definition :
24
P.U. Value = Actual Value of a Quantity Base Value in the Same Units
> Fault Analysis – January 2004
24
Base Quantities and Per Unit Values
11/132 kV 50 MVA
11 kV 20 MVA ZG = 0.3 p.u.
ZT = 10%
O/H LINE ZL = 40Ω
132/33 kV 50 MVA
ZT = 10%
FEEDER ZL = 8Ω
X Particularly useful when analysing large systems with several voltage levels X All system parameters referred to common base quantities X Base quantities fixed in one part of system X Base quantities at other parts at different voltage levels depend on ratio of intervening transformers
25
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25
Base Quantities and Per Unit Values (1)
Base quantites normally used :BASE MVA
= MVAb = 3∅ MVA Constant at all voltage levels Value ~ MVA rating of largest item of plant or 100MVA
BASE VOLTAGE = KVb
=
∅/∅ voltage in kV Fixed in one part of system This value is referred through transformers to obtain base voltages on other parts of system. Base voltages on each side of transformer are in same ratio as voltage ratio.
26
> Fault Analysis – January 2004
26
Base Quantities and Per Unit Values (2)
Other base quantites :-
(kVb )2 Base Impedance = Zb = in Ohms MVAb Base Current
27
> Fault Analysis – January 2004
= Ιb =
MVAb in kA 3 . kVb
27
Base Quantities and Per Unit Values (3)
Per Unit Values = Actual Value Base Value
MVA a Per Unit MVA = MVAp.u. = MVAb KVa Per Unit Voltage = kVp.u. = KVb Per Unit Impedance = Zp.u. = Per Unit Current = Ιp.u. =
28
> Fault Analysis – January 2004
Za MVAb = Za . Zb (kVb )2
Ιa Ιb 28
Referring Impedances X1
R1
N : 1
X2
R2
Ideal Transformer
Consider the equivalent CCT referred to :Primary R1 +
29
N2R2
X1 + N2X2
> Fault Analysis – January 2004
Secondary R1/N2
+ R2
X1/N2 + X2
29
Transformer Percentage Impedance X If ZT = 5% with Secondary S/C 5% V (RATED) produces I (RATED) in Secondary. ∴ V (RATED) produces 100 x I (RATED) 5 = 20 x I (RATED) X If Source Impedance ZS = 0 Fault current = 20 x I (RATED) Fault Power = 20 x kVA (RATED) X ZT is based on I (RATED) & V (RATED) i.e. Based on MVA (RATED) & kV (RATED) ∴ is same value viewed from either side of transformer. 30
> Fault Analysis – January 2004
30
Example (1) Per unit impedance of transformer is same on each side of the transformer. Consider transformer of ratio kV1 / kV2 1
2 MVA
kVb / kV1
kVb / kV2
Actual impedance of transformer viewed from side 1 = Za1 Actual impedance of transformer viewed from side 2 = Za2
31
> Fault Analysis – January 2004
31
Example (2) Base voltage on each side of a transformer must be in the same ratio as voltage ratio of transformer. 11.8kV
Incorrect selection of kVb Correct selection of kVb
Alternative correct selection of kVb
32
> Fault Analysis – January 2004
132/11kV 11.8/141kV OHL
11.8kV
Distribution System
132kV
11kV
132x11.8 141 = 11.05kV
132kV
11kV
11.8kV
141kV
141x11 = 11.75kV 132
32
Conversion of Per Unit Values from One Set of Quantities to Another
Z p.u. 2
Z p.u.1
Zb1
Zb2
MVAb1 MVAb2 kVb1
kVb2
Zp.u.1 =
Za Zb1
Zp.u.2 =
Za Z = Zp.u.1 x b1 Zb2 Zb2
(kVb1)2 MVAb2 = Zp.u.1 x x MVAb1 (kVb2 )2 MVAb2 (kVb1)2 = Zp.u.1 x x MVAb1 (kVb2 )2
Actual Z = Za
33
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33
Example 132/33 kV 50 MVA
11/132 kV 50 MVA
11 kV 20 MVA
0.3p.u.
10%
40Ω
10%
8Ω 3∅ FAULT
kVb
11
132
33
MVAb
50
50
50
349 Ω
21.8 Ω
Zb = kVb2 MVAb Ib = MVAb √3kV b Zp.u.
2.42Ω
∴ I11 kV = 0.698 x Ib = 219 A
2625 A
874 A
0.698 x 2625 = 1833A I132 kV = 0.698 x 219 = 153A
0.3 x 50 20 0.1p.u.
8 = 0.367 40 = 0.115 p.u. 0.1 p.u. p.u. 21.8 349
I33 kV = 0.698 x 874 = 610A
= 0.75p.u. 1.432p.u.
V 1p.u.
34
> Fault Analysis – January 2004
IF =
1 = 0.698p.u. 1.432
34
Fault Types
Line - Ground (65 - 70%) Line - Line - Ground (10 - 20%) Line - Line (10 - 15%) Line - Line - Line (5%) Statistics published in 1967 CEGB Report, but are similar today all over the world.
35
> Fault Analysis – January 2004
35
Unbalanced Faults
36
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36
Unbalanced Faults (1) In three phase fault calculations, a single phase representation is adopted. 3 phase faults are rare. Majority of faults are unbalanced faults. UNBALANCED FAULTS may be classified into SHUNT FAULTS and SERIES FAULTS. SHUNT FAULTS: Line to Ground Line to Line Line to Line to Ground SERIES FAULTS: Single Phase Open Circuit Double Phase Open Circuit 37
> Fault Analysis – January 2004
37
Unbalanced Faults (2) LINE TO GROUND LINE TO LINE LINE TO LINE TO GROUND Causes : 1) Insulation Breakdown 2) Lightning Discharges and other Overvoltages 3) Mechanical Damage
38
> Fault Analysis – January 2004
38
Unbalanced Faults (3)
OPEN CIRCUIT OR SERIES FAULTS Causes : 1) Broken Conductor 2) Operation of Fuses 3) Maloperation of Single Phase Circuit Breakers
DURING UNBALANCED FAULTS, SYMMETRY OF SYSTEM IS LOST
∴ SINGLE PHASE REPRESENTATION IS NO LONGER VALID
39
> Fault Analysis – January 2004
39
Unbalanced Faults (4)
Analysed using :X Symmetrical Components X Equivalent Sequence Networks of Power System X Connection of Sequence Networks appropriate to Type of Fault
40
> Fault Analysis – January 2004
40
Symmetrical Components
41
> Fault Analysis – January 2004
41
Symmetrical Components Fortescue discovered a property of unbalanced phasors ‘n’ phasors may be resolved into :X (n-1) sets of balanced n-phase systems of phasors, each set having a different phase sequence plus X 1 set of zero phase sequence or unidirectional phasors VA = VA1 + VA2 + VA3 + VA4 - - - - - VA(n-1) + VAn VB = VB1 + VB2 + VB3 + VB4 - - - - - VB(n-1) + VBn VC = VC1 + VC2 + VC3 + VC4 - - - - - VC(n-1) + VCn VD = VD1 + VD2 + VD3 + VD4 - - - - - VD(n-1) + VDn -----------------------------------------Vn = Vn1 + Vn2 + Vn3 + Vn4 - - - - - Vn(n-1) + Vnn (n-1) x Balanced
42
> Fault Analysis – January 2004
1 x Zero Sequence 42
Unbalanced 3-Phase System VA = VA1 + VA2 + VA0 VB = VB1 + VB2 + VB0 VC = VC1 + VC2 + VC0 VA2
VA1
120°
VC1
VB1
Positive Sequence
43
240°
> Fault Analysis – January 2004
VC2
VB2
Negative Sequence
43
Unbalanced 3-Phase System
VA0 VB0 VC0
Zero Sequence
44
> Fault Analysis – January 2004
44
Symmetrical Components Phase ≡ Positive + Negative + Zero VA VA = VA1 + VA2 + VA0 VB = VB1 + VB2 + VB0 VC = VC1 + VC2 + VC0 VC VA1
VB VA0VB0
VA2 + VC1 VB1
45
VC2
+
VC0
VB2
VB1 = a2VA1
VB2 = a VA2
VB0 = VA0
VC1 = a VA1
VC2 = a2VA2
VC0 = VA0
> Fault Analysis – January 2004
45
Converting from Sequence Components to Phase Values VA = VA1 + VA2 + VA0 VB = VB1 + VB2 + VB0 = a2VA1 + a VA2 + VA0 VC = VC1 + VC2 + VC0 = a VA1 + a2VA2 + VA0 VA0
VA
VA2 VA1
VC0
VC
VC1 VC2 VB1
VB VB0
VB2 46
> Fault Analysis – January 2004
46
Converting from Phase Values to Sequence Components VA1 = 1/3 {VA + a VB + a2VC} VA2 = 1/3 {VA + a2VB + a VC} VA0 = 1/3 {VA + VB + VC} VA
VB 3VA0
VC
VA0
47
> Fault Analysis – January 2004
47
Summary VA = VA1 VB = ∝2VA1 VC = ∝VA1
+ VA2 + VA0 + ∝VA2 + VA0 + ∝2VA2 + VA0
IA = IA1 IB = ∝2IA1 IC = ∝IA1
+ IA2 + ∝IA2 + ∝2IA2
VA1 = 1/3 {VA + VA2 = 1/3 {VA + VA0 = 1/3 {VA +
∝VB + ∝2VB + VB +
IA1 = 1/3 {IA + ∝IB IA2 = 1/3 {IA + ∝2IB IA0 + 1/3 {IA + IB 48
> Fault Analysis – January 2004
+ IA0 + IA0 + IA0
∝2VC} ∝VC } VC }
+ ∝2IC } + ∝IC } + IC } 48
Residual Current Used to detect earth faults
IA IB IC IRESIDUAL = IA + IB + IC = 3I0 E/F IRESIDUAL is zero for :-
49
Balanced Load 3∅ Faults Ø/∅ Faults
> Fault Analysis – January 2004
IRESIDUAL is ∅/E Faults present for :- ∅/Ø/E Faults Open circuits (with current in remaining phases)
49
Residual Voltage Used to detect earth faults Residual voltage is measured from “Open Delta” or “Broken Delta” VT secondary windings. VRESIDUAL is zero for:Healthy unfaulted systems 3∅ Faults ∅/∅ Faults VRESIDUAL is present for:VRESIDUAL = VA + VB + VC = 3V0
50
> Fault Analysis – January 2004
∅/E Faults ∅/∅/E Faults Open Circuits (on supply side of VT)
50
Example Evaluate the positive, negative and zero sequence components for the unbalanced phase vectors : VA = 1 ∠0°
VC
VB = 1.5 ∠-90°
VA
VC = 0.5 ∠120°
VB 51
> Fault Analysis – January 2004
51
Solution
VA1
=
1/3 (VA + aVB + a2VC)
=
1/3 [ 1 + (1 ∠120) (1.5 ∠-90) + (1 ∠240) (0.5 ∠120) ]
VA2
=
0.965 ∠15
=
1/3 (VA + a2VB + aVC)
=
1/3 [ 1 + (1 ∠240) (1.5 ∠-90) + (1 ∠120) (0.5 ∠120) ]
VA0
52
> Fault Analysis – January 2004
=
0.211 ∠150
=
1/3 (VA + VB + VC)
=
1/3 (1
=
0.434 ∠-55
+ 1.5 ∠-90 + 0.5 ∠120)
52
Positive Sequence Voltages VC1 = aVA1
VA1 = 0.965∠15º 15º
VB1 = a2VA1 53
> Fault Analysis – January 2004
53
VC2 = a2VA2
VA2 = 0.211∠150°
-55º
150º
VA0 = 0.434∠-55º VB0 = VC0 = VB2 = aVA2
Zero Sequence Voltages
Negative Sequence Voltages
54
> Fault Analysis – January 2004
54
Symmetrical Components VC2 VC1
VC0 VC
VA2 VC2
VA2
VA1 VA0
VA VB2
V0
VB1 VB2 VB0 55
> Fault Analysis – January 2004
VB 55
Example Evaluate the phase quantities Ia, Ib and Ic from the sequence components IA1
=
0.6 ∠0
IA2
=
-0.4 ∠0
IA0
=
-0.2 ∠0
IA
=
IA1 + IA2 + IA0 = 0
IB
=
∝2IA1 + ∝IA1 + IA0
=
0.6∠240 - 0.4∠120 - 0.2∠0 = 0.91∠-109
=
∝IA1 + ∝2IA2 + IA0
=
0.6∠120 - 0.4∠240 - 0.2∠0 = 0.91∠-109
Solution
IC
56
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56
Representation of Plant Cont…
57
> Fault Analysis – January 2004
57
Transformer Zero Sequence Impedance
P
Q
ZT0
a
a Q
P
b
b
N0
58
> Fault Analysis – January 2004
58
General Zero Sequence Equivalent Circuit for Two Winding Transformer Primary Terminal
Z T0
'a'
'b'
'a'
Secondary Terminal
'b'
N0
On appropriate side of transformer :
59
Earthed Star Winding
-
Close link ‘a’ Open link ‘b’
Delta Winding
-
Open link ‘a’ Close link ‘b’
Unearthed Star Winding
-
Both links open
> Fault Analysis – January 2004
59
Zero Sequence Equivalent Circuits (1)
P
P0
S
ZT0
a
b
a
S0
b
N0
60
> Fault Analysis – January 2004
60
Zero Sequence Equivalent Circuits (2)
P
P0
S
ZT0
a
b
a
S0
b
N0
61
> Fault Analysis – January 2004
61
Zero Sequence Equivalent Circuits (3)
P
P0
S
ZT0
a
b
a
S0
b
N0
62
> Fault Analysis – January 2004
62
Zero Sequence Equivalent Circuits (4)
P
P0
S
ZT0
a
b
a
S0
b
N0
63
> Fault Analysis – January 2004
63
Sequence Networks
64
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64
Sequence Networks (1)
It can be shown that providing the system impedances are balanced from the points of generation right up to the fault, each sequence current causes voltage drop of its own sequence only.
Regard each current flowing within own network thro’ impedances of its own sequence only, with no interconnection between the sequence networks right up to the point of fault.
65
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65
Sequence Networks (2)
X +ve, -ve and zero sequence networks are drawn for a ‘reference’ phase. This is usually taken as the ‘A’ phase. X Faults are selected to be ‘balanced’ relative to the reference ‘A’ phase. e.g. For Ø/E faults consider an A-E fault For Ø/Ø faults consider a B-C fault X Sequence network interconnection is the simplest for the reference phase.
66
> Fault Analysis – January 2004
66
Positive Sequence Diagram E1 Z1
N1
1.
Start with neutral point N1 -
2.
67
Phase-neutral voltage
Impedance network -
4.
All generator and load neutrals are connected to N1
Include all source EMF’s -
3.
F1
Positive sequence impedance per phase
Diagram finishes at fault point F1
> Fault Analysis – January 2004
67
Example Generator
Transformer
Line
F
N R E
N1
E1
ZG1
ZT1
ZL1
I1
F1 V1 (N1)
68
V1
=
Positive sequence PH-N voltage at fault point
I1
=
Positive sequence phase current flowing into F1
V1
=
E1 - I1 (ZG1 + ZT1 + ZL1)
> Fault Analysis – January 2004
68
Negative Sequence Diagram
Z2
N2
1.
Start with neutral point N2 -
2.
69
No negative sequence voltage is generated!
Impedance network -
4.
All generator and load neutrals are connected to N2
No EMF’s included -
3.
F2
Negative sequence impedance per phase
Diagram finishes at fault point F2
> Fault Analysis – January 2004
69
Example Generator
Transformer
Line
F
N R
System Single Line Diagram
E
ZG2
N2
ZT2
ZL2
I2
F2 V2
Negative Sequence Diagram
70
(N2)
V2
=
Negative sequence PH-N voltage at fault point
I2
=
Negative sequence phase current flowing into F2
V2
=
-I2 (ZG2 + ZT2 + ZL2)
> Fault Analysis – January 2004
70
Zero Sequence Diagram (1) For “In Phase” (Zero Phase Sequence) currents to flow in each phase of the system, there must be a fourth connection (this is typically the neutral or earth connection). IA0
N
IB0 IC0
IA0 + IB0 + IC0 = 3IA0
71
> Fault Analysis – January 2004
71
Zero Sequence Diagram (2) Resistance Earthed System :N
3ΙA0 Zero sequence voltage between N & E given by R
V0 = 3IA0.R Zero sequence impedance of neutral to earth path
E
72
> Fault Analysis – January 2004
Z0 = V0 = 3R IA0
72
Zero Sequence Diagram (3) Generator
Transformer
Line
F
N
RT
R
System Single Line Diagram E
ZG0
N0 3R
ZL0
I0
F0
3RT
E0
73
ZT0
Zero Sequence Network
V0 (N0)
V0
=
Zero sequence PH-E voltage at fault point
I0
=
Zero sequence current flowing into F0
V0
=
-I0 (ZT0 + ZL0)
> Fault Analysis – January 2004
73
Network Connections
74
> Fault Analysis – January 2004
74
Interconnection of Sequence Networks (1) Consider sequence networks as blocks with fault terminals F & N for external connections. F1 POSITIVE SEQUENCE NETWORK
N1 I2 F2 NEGATIVE SEQUENCE NETWORK
V2
N2 I0 ZERO SEQUENCE NETWORK
F0 V0
N0 75
> Fault Analysis – January 2004
75
Interconnection of Sequence Networks (2) For any given fault there are 6 quantities to be considered at the fault point i.e.
VA
VB
VC
IA
IB
IC
Relationships between these for any type of fault can be converted into an equivalent relationship between sequence components V1, V2, V0 and I1, I2 , I0 This is possible if :1) or
2)
Any 3 phase quantities are known (provided they are not all voltages or all currents) 2 are known and 2 others are known to have a specific relationship.
From the relationship between sequence V’s and I’s, the manner in which the isolation sequence networks are connected can be determined. The connection of the sequence networks provides a single phase representation (in sequence terms) of the fault. 76
> Fault Analysis – January 2004
76
To derive the system constraints at the fault terminals :-
F
IA
VA
IB
VB
IC
VC
Terminals are connected to represent the fault. 77
> Fault Analysis – January 2004
77
Line to Ground Fault on Phase ‘A’
IA
VA
78
IB
VB
> Fault Analysis – January 2004
IC
VC
At fault point :VA VB VC
= = =
0 ? ?
IA IB IC
= = =
? 0 0
78
Phase to Earth Fault on Phase ‘A’ At fault point VA
=
0 ; IB = 0 ; IC = 0
but
VA
=
V1 + V2 + V0
∴
V1 I0
+ =
V2 + V0 = 0 ------------------------- (1) 1/3 (IA + IB + IC ) = 1/3 IA
I1
=
1/3 (IA + aIB + a2IC) = 1/3 IA
I2
=
1/3 (IA + a2IB + aIC) = 1/3 IA
∴
I1 = I2 = I0 = 1/3 IA
------------------------- (2)
To comply with (1) & (2) the sequence networks must be connected in series :+ve Seq N/W
I1
F1 V1 N1
-ve Seq N/W
I2
F2
V2
N2
Zero Seq N/W
I0 F0
V0
N0 79
> Fault Analysis – January 2004
79
Example : Phase to Earth Fault SOURCE
F
LINE
A-G FAULT
ZL1 = 10Ω ZL0 = 35Ω
132 kV 2000 MVA ZS1 = 8.7Ω ZS0 = 8.7Ω 8.7
10
IF
I1
F1 N1
8.7
10
I2
F2 N2
8.7
35
I0
F0 N0
Total impedance = 81.1Ω I1 = I2 = I0 = 132000 = 940 Amps √3 x 81.1 IF = IA = I1 + I2 + I0 = 3I0 = 2820 Amps 80
> Fault Analysis – January 2004
80
Earth Fault with Fault Resistance
I1 POSITIVE SEQUENCE NETWORK
F1 V1
N1 I2 NEGATIVE SEQUENCE NETWORK
F2 V2
3ZF
N2 I0 ZERO SEQUENCE NETWORK
F0 V0
N0
81
> Fault Analysis – January 2004
81
Phase to Phase Fault:- B-C Phase
I1 +ve Seq N/W
F1 V1 N1
82
> Fault Analysis – January 2004
I2 -ve Seq N/W
F2 V2 N2
I0 Zero Seq N/W
F0 V0 N0
82
Example : Phase to Phase Fault SOURCE 132 kV 2000 MVA ZS1 = ZS2 = 8.7Ω 132000 √3
F
LINE
B-C FAULT
ZL1 = ZL2 = 10Ω
8.7
10
I1
F1 N1
8.7
10
I2
F2 N2
Total impedance = 37.4Ω I1 = 132000 = 2037 Amps √3 x 37.4 I2 = -2037 Amps 83
> Fault Analysis – January 2004
IB = = = = =
a2I1 + aI2 a2I1 - aI1 (a2 - a) I1 (-j) . √3 x 2037 3529 Amps. 83
Phase to Phase Fault with Resistance
ZF
I1 +ve Seq N/W
F1
I2
-ve Seq N/W
V1
F2 V2
N1
N2
Zero Seq N/W
I0
F0 V0 N0
84
> Fault Analysis – January 2004
84
Phase to Phase to Earth Fault:- B-C-E
I1 +ve Seq N/W
F1 V1 N1
85
> Fault Analysis – January 2004
I2 -ve Seq N/W
F2 V2 N2
I0 Zero Seq N/W
F0 V0 N0
85
Phase to Phase to Earth Fault:B-C-E with Resistance
3ZF
I1 +ve Seq N/W
86
F1 V1
> Fault Analysis – January 2004
N1
-ve Seq N/W
I2
F2 V2 N2
Zero Seq N/W
I0
F0 V0 N0
86
Maximum Fault Level
Single Phase Fault Level :
X Can be higher than 3Φ fault level on solidlyearthed systems
Check that switchgear breaking capacity > maximum fault level for all fault types.
87
> Fault Analysis – January 2004
87
3Ø Versus 1Ø Fault Level (1)
E
XT
Xg
3Ø Xg
XT
ΙF = Z1 E
88
E Xg + XT
≡
E Z1
IF
> Fault Analysis – January 2004
88
3Ø Versus 1Ø Fault Level (2)
1Ø
Xg
XT
Z1
E
Xg2
XT2
IF
Z2 = Z1
Xg0
3E ΙF = 2Z1 + Z0
XT0
Z0
89
> Fault Analysis – January 2004
89
3Ø Versus 1Ø Fault Level (3)
3∅FAULTLEVEL =
3E 3E E = = 2Z1 + Z1 3Z1 Z1
3E 1∅FAULTLEVEL = 2Z1 + Z0 ∴ IF Z0 < Z1 1∅FAULTLEVEL > 3∅FAULTLEVEL
90
> Fault Analysis – January 2004
90
System Earthing
System Earthing Earth faults :- 70 Æ 90% of all faults.
EA IF
System Earthing
Earthing method determines :z
Fault current IF
z
Damage caused
z
Steady state overvoltages
z
Transient overvoltages
z
Insulation requirements
z
Quantities available to detect faults
z
Type of Protection
Earthing Method Solid / Low Z
High Z
IF
High
Low
Overvoltages in Sound Phases
Low
High
Damage
High
Low
Cost of Insulation
Low
High
Low Voltage Systems
For Safety
Medium Voltage Systems
High Voltage & EHV Systems
To limit current cost of insulation acceptable To limit cost of insulation
Methods of Earthing In Common Use
z
Solid or Direct Earthing
z
Resistance Earthing
z
Reactance Earthing
z
Resonant or Petersen Coil Earthing
z
Insulated Earth
System Earthing Solid Lowest System Z0 IF High - Damage - Easy E/F Protn. No Arcing Grounds IF >> ICHARGE Lowest Overvoltages
System Earthing Reactance Lower IF Higher Transient Overvoltages Cheaper than resistance at high volts Overvoltages during E/Fs 0.8 Î 1 x VØ/Ø Not often used except as tuned reactor
System Earthing Petersen Coil XE ≈ ∑ XCHARGING Arcing faults self extinguishing - Good for transient faults XE needs changing if XC alters Overvoltages during E/Fs Î VØ/Ø Insulation important Tuned
Restricts use of auto-transformers Discriminative E/F protection difficult
System Earthing Resistance
Reduced IF Reduced transient overvoltages Not self extinguishing but E/F easier to detect
System Earthing Unearthed Insulated IF Capacitive Can be self extinguishing if IF small Overvoltages during E/Fs = VØ/Ø Arcing faults likely - high transient overvoltages Insulation important
System Earthing Î 660 V
Solid Insulated
660 V Î 33 kV
Resistance or reactance normally used Solid Resistance Reactance Petersen Coil
- Safety - Special cases where continuity of supply required
-
When IF is low IF limited to IFL IF(E/F) limited to IF(3Ø) Overhead lines. Lightning
> 33 kV
Solid Overvoltages more important (insulation)
Directly Coupled Generators
Resistance Solid and Reactance
- Most common - Not recommended (High IF )
System Earthing Generator - Transformer Units
IF ~ 10 Î 15 A
IF ~ 200 Î 300 A
Low Voltage System Earthing
Safety :z
Power system neutral solidly earthed at transformer.
z
Metallic tools and appliances solidly earthed.
z
Sensitive protection by :RCD’s :- Residual current devices ELCB’s :- Earth leakage circuit breakers
Earth Fault Hazard Unearthed Appliance
ZF
ZP
ZF =
VP
Fault impedance
ZP =
Human body impedance
ZE =
Environmental impedance
VP =
Case / earth potential
ZE
Earth Fault Hazard RCD for High ZF
Unearthed Appliance
Fuses for High IF IF ZF
Protective Earth Conductor VH
ZF =
Fault impedance
ZP =
Human body impedance
ZE =
Environmental impedance
VP =
Case / earth potential
ZP VP ZE
Without protective earth : ZP VH = E∅/N . ZP + ZF + ZE
Unearthed L.V. Winding
V
Normal Conditions
v H.V.
L.V.
Breakdown Between HV and LV Windings 3000 / 440 V
Transformer
A2
1730V
a2 n
N c2 C2
254V b2
B2
Normal voltage conditions Neutrals earthed or unearthed
Breakdown Between HV and LV Windings
A2 95V
a2 1730V
xH
x
xL
850V
C2
254V
n c2
1009V b2
755V
B2
Voltage conditions with breakdown between HV and LV at point X on phase LV neutral unearthed
Hand to Hand Resistance of Living Body 50Hz AC (Freiburger 1933)
6000
Resistance - Ohms
5000 4000 Very Dry Skin
3000 2000
Very Moist Skin
1000
0
100
200
300 400 Volts
500
600
Effects of Body Current 1mA
Can be felt
> 9mA
Cannot let go
15mA
Threshold of cramp
30mA
Breathing difficult Rise in blood pressure
50mA
Heart misses odd beat
50 → 200mA
Heavy shock Unconsciousness
> 200mA
Reversible cardiac arrest Current marks Burns
Effects of Various Values of Body Current Current at 50Hz to 60Hz r.m.s. value mA
Duration of shock
0-1
not critical
Range up to threshold of perception. Electrocution not felt.
1-15
not Critical
Range up to threshold of cramp. Independent release of hands from object gripped no longer possible. Possibly powerful and sometimes painful effects on muscles of fingers and arms.
15-30
minutes
Cramp-like contraction of arms. Difficulty in breathing. Rise in blood pressure. Limit of tolerability.
30-50
seconds
Heart irregularities. Rise in blood pressure. Powerful cramp-effect. to minutes Unconsciousness. Ventricular fibrillation if long shock at upper limit of range.
less than cardiac cycle
No ventricular fibrillation. Heavy shock.
above one cardiac cycle
Ventricular fibrillation. Beginning of electrocution in relation to heart phase not important. (Disturbance of stimulus conducting system?) Unconsciousness. Current marks.
less than cardiac cycle
Ventricular fibrillation. Beginning of electrocution in relation to heart phase Important Initiation of fibrillation only in the sensitive phase. (Direct stimulatory effect on heart muscle?) Unconsciousness. Current marks
over one cardiac cycle
Reversible cardiac arrest. Range of electrical defibrillation. Unconsciousness. Current marks. Burns
50 to a few hundred
Above few hundred
Physiological effects on humans
Body Current / Time and Security
Threshold of Fibrillation
10,000 Threshold of Threshold Let Go of Perception
Time 1,000 (mS) IEC Security Curve Let Go
100
Hold On
10 0.1
1.0
10 Current (mA)
100
1000
Earthing Impedance Affects Touch & Step Potentials E
! Touch
RE
Step VH
VH
True Earth
RF IF
Surface RG
Don’t forget communications cables etc. entering S/S ! IF
IF VH = E
RG ' RE + RF + RG '
True Earth
RG
RG' = f(Distance)
d
Displacement of Neutral from Earth during an Earth Fault Z
IF
Va N Vc
Vb
Z Z
ZE Va G
VGN = ΙF ZE = VaN .
G
ZE ZE + Z
N
Vc
Vb
Methods of Neutral Earthing (1) Aspect
Solid
Resistance
Resistance & reactance
High value reactor
Low value reactor
Tuned reactor
Insulated
Normal insulation
Suitable for phase voltage continuously
Suitable for phase voltage continuously
Suitable for phase voltage continuously
Suitable for line voltage for long periods
Suitable for phase voltage continuously
If used for operation with one line earthed for long periods insulation must be suitable for line voltage
Suitable for line voltage for long
Not excessive
Not excessive providing all three phases are made or broken simultaneously
Can be very high Not excessive e.g. neutral inversion
Not excessive if Arcing ground no mutual coup- can give very ling between zero high voltages & positive sequence networks
“
Full reflection at neutral
Full reflection at neutral
Full reflection at neutral
No difficulty, normal methods can be used
Extremely difficult if more than one zone involved
No difficulty normal methods can be used
By using special Extremely technique can be difficult done satisfactorily
In general, diverters rated for line volts are essential
Diverters rated for line volts are essential
In general, diverters rated for line volts are essential
Diverter rated for line volts are essential
Over voltages: (a) Initiated by Not excessive faults, switching, etc
(b) Travelling waves
Negative reflection
In general, negative reflection at neutral
Protection: (a) Automatic No difficulty No difficulty segregation normal methods normal methods of faulty zone can be used can be used
(b) Travelling waves
Diverters rated In general, for phase volts diverters rated are suitable for line voltage are essential
Full reflection at neutral
Diverters rated for line volts are essential
Methods of Neutral Earthing (2) Aspect
Solid
Resistance
Resistance & reactance
High value reactor
Low value reactor
Tuned reactor
Insulated
Earth-fault Current (a) Value
Highest value
High value
High value
Negligible
High value
Negligible
Capacitive if small may be self extinguished
(b) Duration
Few seconds
Few seconds
Few seconds
Long time
Few seconds
Few seconds or continuous, depending on method of application
In general long time
Electromagnetic interference depending on degree of limitation
Electrostatic interference
Electromagnetic interference may necessitate current limitation
If used for Electrostatic running contininterference uously with one line earthed requires particular consideration
Partial limitations Partial limitation of of harmonic harmonic currents currents
Limits all harmonic currents
Appreciably limits all harmonic currents
Appreciably limits all harmonic currents
-
Time rating of 30 sec. neutral apparatus
30 sec.
30 sec.
Continuous
30 sec.
30 sec. or continuous
-
General remarks Maximum disturbance to system
In general use
In general use where a source neutral is not available
Confined mainly to protection of generator on generator transformer unit
Cheaper than resistor at very high voltages
Best continuity of supply. Can be a danger to personnel
(c) Effect on Electromagnetic Electromagnetic communica- interference interference tion circuits may necessidepending on tate current degree of limitation limitation
Harmonic currents in neutral
No limitation of harmonic currents
Some applications on short feeders, in general to be avoided
Application of Non-Directional Overcurrent and Earthfault Protection
Non-Directional Overcurrent and Earth Fault Protection
Overcurrent Protection Purpose of Protection z Detect abnormal conditions z Isolate faulty part of the system z Speed z Fast operation to minimise damage and danger z Discrimination z Isolate only the faulty section z Dependability / reliability z Security / stability z Cost of protection / against cost of potential hazards
Overcurrent Protection Co-ordination
F1
F2
F3
z Co-ordinate protection so that relay nearest to fault operates first z Minimise system disruption due to the fault
Fuses
Overcurrent Protection Fuses z Simple z Can provide very fast fault clearance z Is
I > Is
In Vx
Ph+
0.1 0.1 0.2 0.4 0.4 0.4 0.8
0.05 0 0 0 0 0 0
0 0 0
1 1 1
0.025 0 0 0 0 0
0.05 0.05 0.1 0.2 0.3 0.4
0 0 0 0 0 0
1 2 4 8 10
∝
Is = Σ x Is
0.05 0 0 0 0 0 0
Hz V
Is = Σ x Is RESET
1 1 1
x t = Σ
I
INST =
Σ x Is
D
0.05 0.05 0.1 0.2 0.3 0.4
1 2 4 8 10
∝
x t = Σ
I
LT1
t S1 V1 E1
I
INST =
Σ x Is
z Electronic, multi characteristic z Fine settings, wide range z Integral instantaneous elements
Overcurrent Protection Numerical Relay
I>1 I>2 Time
I>3 I>4 Current
z Multiple characteristics and stages z Current settings in primary or secondary values z Additional protection elements
Co-ordination
Overcurrent Protection Co-ordination Principle z Relay closest to fault must operate first R1
R2
IF1
T
z Other relays must have adequate additional operating time to prevent them operating z Current setting chosen to allow FLC
IS2 IS1
Maximum Fault Level
I
z Consider worst case conditions, operating modes and current flows
Overcurrent Protection Co-ordination Example E
D
B
C
A
Operating time (s)
10
E D
1
C B 0.1
0.01
Current (A)
FLB
FLC
FLD
Overcurrent Protection IEC Characteristics 1000
t =
0.14 (I0.02 -1)
z VI
t = 13.5 (I -1)
z EI
t =
80 (I2
Operating Time (s)
z SI
100
10 LTI SI
1
-1)
z LTI t = 120 (I - 1)
VI EI
0.1 1
10
100
Current (Multiples of Is)
Overcurrent Protection Operating Time Setting - Terms Used
z Published characteristcs are drawn against a multiple of current setting or Plug Setting Multiplier z Therefore characteristics can be used for any application regardless of actual relay current setting z e.g at 10x setting (or PSM of 10) SI curve op time is 3s
1000
Operating Time (s)
z Relay operating times can be calculated using relay characteristic charts
100
10
1
0.1 1
100 10 Current (Multiples of Is)
Overcurrent Protection Current Setting z Set just above full load current z allow 10% tolerance z Allow relay to reset if fault is cleared by downstream device z consider pickup/drop off ratio (reset ratio) z relay must fully reset with full load current flowing z PU/DO for static/numerical = 95% z PU/DO for EM relay = 90% z e.g for numerical relay, Is = 1.1 x IFL/0.95
Overcurrent Protection Current Setting
z Current grading z ensure that if upstream relay has started downstream relay has also started
R1
R2
IF1
z Set upstream device current setting greater than
downstream relay e.g. IsR1 = 1.1 x IsR2
Overcurrent Protection Grading Margin
z Operating time difference between two devices to ensure that downstream device will clear fault before upstream device trips z Must include z breaker opening time z allowance for errors z relay overshoot time z safety margin
GRADING MARGIN
Overcurrent Protection Grading Margin - between relays
R1
R2
z Traditional z breaker op time
-
0.1
z relay overshoot
-
0.05
z allow. For errors
-
0.15
z safety margin
-
0.1
z Total z Calculate using formula
0.4s
Overcurrent Protection Grading Margin - between relays z Formula z t’ = (2Er + Ect) t/100 + tcb + to + ts z Er = relay timing error z Ect = CT measurement error z t = op time of downstream relay z tcb = CB interupting time z to = relay overshoot time z ts = safety margin z Op time of Downstream Relay t = 0.5s z 0.375s margin for EM relay, oil CB z 0.24s margin for static relay, vacuum CB
Overcurrent Protection Grading Margin - relay with fuse
z Grading Margin = 0.4Tf + 0.15s over whole characteristic z Assume fuse minimum operating time = 0.01s z Use EI or VI curve to grade with fuse z Current setting of relay should be 3-4 x rating of fuse to ensure co-ordination
Overcurrent Protection Grading Margin - relay with upstream fuse
Tf Tr I FMAX
z 1.175Tr
+
Allowance for CT and relay error
or z Tf = 2Tr + 0.33s
0.1 CB
+
0.1 Safety margin
=
0.6Tf Allowance for fuse error (fast)
Overcurrent Protection Time Multiplier Setting
z Used to adjust the operating time of an inverse characteristic z Not a time setting but a multiplier z Calculate TMS to give desired operating time in accordance with the grading margin
Operating Time (s)
100
10
1
0.1 1
100 10 Current (Multiples of Is)
Overcurrent Protection Time Multiplier Setting - Calculation
z Calculate relay operating time required, Treq z consider grading margin z fault level z Calculate op time of inverse characteristic with TMS = 1, T1 z TMS = Treq /T1
Overcurrent Protection Co-ordination - Procedure
z Calculate required operating current z Calculate required grading margin z Calculate required operating time z Select characteristic z Calculate required TMS z Draw characteristic, check grading over whole curve Grading curves should be drawn to a common voltage base to aid comparison
Overcurrent Protection Co-ordination Example
200/5
100/5 I
FMAX = 1400 Amp
B Is = 5 Amp
A Is = 5 Amp; TMS = 0.05, SI
z Grade relay B with relay A z Co-ordinate at max fault level seen by both relays = 1400A z Assume grading margin of 0.4s
Overcurrent Protection Co-ordination Example
200/5
100/5 I
FMAX = 1400 Amp
B Is = 5 Amp
A Is = 5 Amp; TMS = 0.05, SI
z Relay B is set to 200A primary, 5A secondary z Relay A set to 100A ∴ If (1400A) = PSM of 14 relay A OP time = t = 0.14 x TMS = 0.14 x 0.05 = 0.13 (140.02 -1) (I0.02 -1) z Relay B Op time = 0.13 + grading margin = 0.13 + 0.4 = 0.53s z Relay A uses SI curve so relay B should also use SI curve
Overcurrent Protection Co-ordination Example 200/5
B Is = 5 Amp
100/5
A
I FMAX = 1400 Amp
Is = 5 Amp; TMS = 0.05, SI
z Relay B Op time = 0.13 + grading margin = 0.13 + 0.4 = 0.53s z Relay A uses SI curve so relay B should also use SI curve z Relay B set to 200A ∴ If (1400A) = PSM of 7 0.14 = 3.52s relay B OP time TMS = 1 = 0.14 x TMS = (I0.02 -1) (70.02 -1) z Required TMS = Required Op time = 0.53 = 0.15 Op time TMS=1 3.52 z Set relay B to 200A, TMS = 0.15, SI
Overcurrent Protection LV Protection Co-ordination 11kV MCGG
4
CTZ61
3
CB 2 x 1.5MVA 11kV/433V 5.1% ACB
4
CTZ61
3
350MVA
(Open)
2
ACB 1 1 2 3 4 F
Relay 1 Relay 2 Relay 3 Relay 4 Fuse
27MVA Fuse Load
ZA2118B
MCCB
F
K 20MVA
Overcurrent Protection LV Protection Co-ordination 1000S
MCCB (cold)
10S
TX damage
Fuse
100S
Very inverse
1.0S Relay 3
Relay 2
Relay 4
0.1S 0.01S 0. 1kA ZA2119
10kA
1000kA
Overcurrent Protection LV Protection Co-ordination 11kV KCGG 142
4
CB
4
350MVA
2 x 1.5MVA 11kV/433V 5.1% KCEG 142
3
ACB
3
(Open)
2
ACB 1 1 2 3 4 F
Relay 1 Relay 2 Relay 3 Relay 4 Fuse
27MVA Fuse Load
ZA2120C
MCCB
F
K 20MVA
Overcurrent Protection LV Protection Co-ordination 1000S Long time inverse
100S Fuse
TX damage
1.0S
MCCB (cold)
10S
Relay 3
0.1S
Relay 2
Relay 4
0.01S 0. 1kA ZA2121
10kA
1000kA
Overcurrent Protection Blocked OC Schemes
Graded protection R3 R2 IF2
R1
Block t > I > Start
IF1 M ZA2135
(Transient backfeed ?)
Blocked protection
Delta / Star Transformers
Overcurrent Protection Transformer Protection - 2-1-1 Fault Current Turns Ratio = √3 :1
z A phase-phase fault on one side of transformer produces 2-1-1 distribution on other side z Use an overcurrent element in each phase (cover the 2x phase) z 2∅ & EF relays can be used provided fault current > 4x setting
Iline Idelta
0.866 If3∅
Overcurrent Protection Transformer Protection - 2-1-1 Fault Current
Turns Ratio = √3 :1
z Istar = E∅-∅/2Xt = √3 E∅-n/2Xt z Istar = 0.866 E∅-n/Xt z Istar = 0.866 If3∅
Iline
z Idelta = Istar/√3 = If3∅ /2 Idelta
0.866 If3∅
z Iline = If3∅
Overcurrent Protection Transformer Protection - 2-1-1 Fault Current
51
51
HV
LV
z Grade HV relay with respect to 2-1-1 for ∅-∅ fault z Not only at max fault level
86.6%If3∅
If3∅
Ø/Ø
Use of High Sets
Overcurrent Protection Instantaneous Protection
z Fast clearance of faults z ensure good operation factor, If >> Is (5 x ?) z Current setting must be co-ordinated to prevent overtripping z Used to provide fast tripping on HV side of transformers z Used on feeders with Auto Reclose, prevents transient faults becoming permanent z AR ensures healthy feeders are re-energised z Consider operation due to DC offset - transient overreach
Overcurrent Protection Instantaneous OC on Transformer Feeders
HV2
HV1
LV
z Stable for inrush
HV2 TIME
z Set HV inst 130% IfLV z No operation for LV fault
HV1 LV
z Fast operation for HV fault
IF(LV)
IF(HV)
1.3IF(LV)
CURRENT
z Reduces op times required of upstream relays
Earthfault Protection
Overcurrent Protection Earth Fault Protection
z Earth fault current may be limited z Sensitivity and speed requirements may not be met by overcurrent relays z Use dedicated EF protection relays z Connect to measure residual (zero sequence) current z Can be set to values less than full load current z Co-ordinate as for OC elements z May not be possible to provide co-ordination with fuses
Overcurrent Protection Earth Fault Relay Connection - 3 Wire System
E/F
OC
OC
OC
z Combined with OC relays
E/F
OC
OC
z Economise using 2x OC relays
Overcurrent Protection Earth Fault Relay Connection - 4 Wire System
E/F
OC
OC
OC
z EF relay setting must be greater than normal neutral current
E/F
OC
OC
OC
z Independent of neutral current but must use 3 OC relays for phase to neutral faults
Overcurrent Protection Earth Fault Relays Current Setting
z Solid earth z 30% Ifull load adequate
z Resistance earth z setting w.r.t earth fault level z special considerations for impedance earthing - directional?
Overcurrent Protection Sensitive Earth Fault Relays A B C
z Settings down to 0.2% possible z Isolated/high impedance earth networks
E/F
z For low settings cannot use residual connection, use dedicated CT z Advisable to use core balance CT z CT ratio related to earth fault current not line current z Relays tuned to system frequency to reject 3rd harmonic
Overcurrent Protection Core Balance CT Connections
OPERATION
NO OPERATION
z Need to take care with core balance CT and armoured cables z Sheath acts as earth return path z Must account for earth current path in connections - insulate cable gland
CABLE GLAND CABLE BOX
E/F
CABLE GLAND/SHEATH EARTH CONNECTION
Application of Directional Overcurrent and Earthfault Protection
Application of Directional Overcurrent and Earthfault Protection - January 2004
Directional Protection
Application of Directional Overcurrent and Earthfault Protection - January 2004
Need for Directional Control Generally required if current can flow in both directions through a relay location e.g. Parallel feeder circuits Ring Main Circuits
0.9
0.1
0.5
0.5
0.1
0.9
Relays operate for current flow in direction indicated. (Typical operating times shown).
Application of Directional Overcurrent and Earthfault Protection - January 2004
Ring Main Circuit With ring closed : Both load and fault current may flow in either direction along feeder circuits. Thus, directional relays are required. Note: Directional relays look into the feeder. Need to establish principle for relay.
51
67
67
67
Load
51
67
Load
67
Load Application of Directional Overcurrent and Earthfault Protection - January 2004
67
Ring Main Circuit Procedure : 1. Open ring at A Grade : A' - E' - D' - C' - B' 2. Open ring at A' Grade : A - B - C - D - E Typical operating times shown. Note : Relays B, C, D’, E’ may be non-directional. A
B'
B
C'
C
0.1
1.3
0.5
0.9
1.7
A'
E
E'
0.1
1.3
1.7
Application of Directional Overcurrent and Earthfault Protection - January 2004
0.9
D'
0.5
D
Ring System with Two Sources Discrimination between all relays is not possible due to different requirements under different ring operating conditions.
}
For F1 :- B’ must operate before A’ For F2 :- B’ must operate after A’
Not Compatible B
F1 B'
A
B
C'
C
A' F2 Application of Directional Overcurrent and Earthfault Protection - January 2004
D
D'
Ring System with Two Sources Option 1 Trip least important source instantaneously then treat as normal ring main. Option 2 Fit pilot wire protection to circuit A - B and consider as common source busbar. B
A
Option 1
50
Option 1
PW
PW
Option 2
Option 2
Application of Directional Overcurrent and Earthfault Protection - January 2004
Option 1
Parallel Feeders Non-Directional Relays :‘F’
51 A
51 C
51 B
51 D
“Conventional Grading” :Grade ‘A’ with ‘C’ and Grade ‘B’ with ‘D’
Load
A&B C&D
Relays ‘A’ and ‘B’ have the same setting. Fault level at ‘F’ Application of Directional Overcurrent and Earthfault Protection - January 2004
Parallel Feeders Consider fault on one feeder :I1 + I2 I1
51 A
I2
51 B
C
51
D
51
LOAD
Relays ‘C’ and ‘D’ see the same fault current (I2). As ‘C’ and ‘D’ have similar settings both feeders will be tipped. Application of Directional Overcurrent and Earthfault Protection - January 2004
Parallel Feeders Solution:- Directional Control at ‘C’ and ‘D’ I1 + I2 I1
51 A
C I2
51 B
D
67
LOAD
67
Relay ‘D’ does not operate due to current flow in the reverse direction.
Application of Directional Overcurrent and Earthfault Protection - January 2004
Parallel Feeders Setting philosophy for directional relays E 51 A
C
Load
67 51
51 B
D
67
Load current always flows in ‘non-operate’ direction. Any current flow in ‘operate’ direction is indicative of a fault condition. Thus Relays ‘C’ and ‘D’ may be set :- Sensitive (typically 50% load) - Fast operating time (i.e. TMS=0.1) Application of Directional Overcurrent and Earthfault Protection - January 2004
Parallel Feeders
Usually, relays are set :50% full load current (note thermal rating) Minimum T.M.S. (0.1) Grading procedure :1. Grade ‘A’ (and ‘B’) with ‘E’ assuming one feeder in service. 2. Grade ‘A’ with ‘D’ (and ‘B’ with ‘C’) assuming both feeders in service.
Application of Directional Overcurrent and Earthfault Protection - January 2004
Parallel Feeders - Application Note
Grade B with C at If1 Grade B with D at If2 (in practice) A Grade A with B at If Load - but check that sufficient margin exists for bus fault at Q when relay A sees total fault current If2, but relay B sees only If2/2.
If2
P B
D
Load
C B
If1:One Feeder If2:Two Feeders
D
D
C
B
A M = Margin If2
If2/2
M
M
If2/2 If1If2
Application of Directional Overcurrent and Earthfault Protection - January 2004
Q
M
If
Establishing Direction
Application of Directional Overcurrent and Earthfault Protection - January 2004
Establishing Direction:- Polarising Quantity
The DIRECTION of Alternating Current may only be determined with respect to a COMMON REFERENCE. In relaying terms, the REFERENCE is called the POLARISING QUANTITY. The most convenient reference quantity is POLARISING VOLTAGE taken from the Power System Voltages.
Application of Directional Overcurrent and Earthfault Protection - January 2004
Directional Decision by Phase Comparison (1) S1 = Reference Direction = Polarising Signal = VPOL S2 = Current Signal = I OPERATION when S2 is within ±90° of S1 :S1 S2
S2
S2
S2
Application of Directional Overcurrent and Earthfault Protection - January 2004
S2
S2
S2
Directional Decision by Phase Comparison (2) RESTRAINT when S2 lags S1 by between 90° and 270° :S1
S2
S2
S2
S2
S2
S2 S2
Application of Directional Overcurrent and Earthfault Protection - January 2004
Polarising Voltage for ‘A’ Phase Overcurrent Relay
OPERATE SIGNAL
=
POLARISING SIGNAL :-
Application of Directional Overcurrent and Earthfault Protection - January 2004
IA Which voltage to use ? Selectable from VA VB VC VA-B VB-C VC-A
Directional Relay Applied Voltage Applied Current
: :
VA IA VA IA
Operate IAF VAF
Restrain
Question : - is this connection suitable for a typical power system ? Application of Directional Overcurrent and Earthfault Protection - January 2004
Polarising Voltage Applied Voltage : VBC Applied Current : IA VA IA IAF MAXIMUM SENSITIVITY LINE
VBC IVBC
ØVBC ZERO SENSITIVITY LINE
X Polarising voltage remains healthy X Fault current in centre of characteristic
Application of Directional Overcurrent and Earthfault Protection - January 2004
Relay Connection Angle The angle between the current applied to the relay and the voltage applied to the relay at system unity power factor e.g. 90° (Quadrature) Connection :
IA and VBC
IA VA
90° VBC
VB overcurrent relays. C The 90°Vconnection is now used for all 30° and 60° connections were also used in the past, but no longer, as the 90° connection gives better performance.
Application of Directional Overcurrent and Earthfault Protection - January 2004
Relay Characteristic Angle (R.C.A.) for Electronic Relays The angle by which the current applied to the relay must be displaced from the voltage applied to the relay to produce maximum operational sensitivity e.g. 45° OPERATE
RESTRAIN
IA FOR MAXIMUM OPERATE SENSITIVITY
VA
45°
RCA
Application of Directional Overcurrent and Earthfault Protection - January 2004
VBC
90° Connection - 45° R.C.A.
MAX SENSITIVITY LINE
OPERATE
IA VA
RESTRAIN
IA FOR MAX SENSITIVITY
VA 45°
90°
45° VBC
VC
135°
VB
RELAY CURRENT VOLTAGE A
IA
VBC
B
IB
VCA
C
IC
VAB
Application of Directional Overcurrent and Earthfault Protection - January 2004
VBC
90° Connection - 30° R.C.A. OPERATE MAX SENSITIVITY LINE IA FOR MAX SENSITIVITY
RESTRAIN
IA VA
VA 30°
90° VBC
30° 150°
VC
VB
RELAY CURRENT VOLTAGE A
IA
VBC
B
IB
VCA
C
IC
VAB
Application of Directional Overcurrent and Earthfault Protection - January 2004
VBC
Selection of R.C.A. (1) Overcurrent Relays 90° connection 30° RCA (lead) Plain feeder, zero sequence source behind relay
Application of Directional Overcurrent and Earthfault Protection - January 2004
Selection of R.C.A. (2) 90° connection 45° RCA (lead) Plain or Transformer Feeder :- Zero Sequence Source in Front of Relay
Transformer Feeder :- Delta/Star Transformer in Front of Relay
Application of Directional Overcurrent and Earthfault Protection - January 2004
Directional Earthfault Protection
Application of Directional Overcurrent and Earthfault Protection - January 2004
Directional Earth Fault Requirements are similar to directional overcurrent i.e. need operating signal and polarising signal Operating Signal obtained from residual connection of line CT's i.e. Iop = 3Io Polarising Signal The use of either phase-neutral or phase-phase voltage as the reference becomes inappropriate for the comparison with residual current. Most appropriate polarising signal is the residual voltage. Application of Directional Overcurrent and Earthfault Protection - January 2004
Residual Voltage May be obtained from ‘broken’ delta V.T. secondary. A B C VA-G
VB-G VC-G
VRES = VA-G + VB-G + VC-G = 3V0
VRES
Notes : 1. VT primary must be earthed. 2. VT must be of the '5 limb' construction (or 3 x single phase units) Application of Directional Overcurrent and Earthfault Protection - January 2004
Directional Earth Fault Relays
Relay Characteristic Angle 0 - Resistance earthed systems 45 (I lags V) - Distribution systems (solidly earthed) 60 (I lags V) - Transmission systems (solidly earthed)
Application of Directional Overcurrent and Earthfault Protection - January 2004
Residual Voltage Solidly Earthed System
E
S
F
R ZL
ZS
A-G VA VA
VB VC
VC VA
VB VC
VB VC
VRES VA VC
VB
VRES VB
VB VC
Residual Voltage at R (relaying point) is dependant upon ZS / ZL ratio.
Application of Directional Overcurrent and Earthfault Protection - January 2004
Residual Voltage Resistance Earthed System S
E
R
ZS
N
F
ZL
ZE
A-G
G VA-G G.F
VC-G
VB-G VC-G
VRES VA-G VC-G
Application of Directional Overcurrent and Earthfault Protection - January 2004
S R G.F
S V A-G R G.F
S
VB-G
VRES VA-G VC-G
VB-G VC-G
VB-G
VB-G
VRES VC-G
VB-G
Current Polarising A solidly earthed, high fault level (low source impedance) system may result in a small value of residual voltage at the relaying point. If residual voltage is too low to provide a reliable polarising signal then a current polarising signal may be used as an alternative. The current polarising signal may be derived from a CT located in a suitable system neutral to earth connection. e.g.
OP POL DEF Relay
Application of Directional Overcurrent and Earthfault Protection - January 2004
Directional Control Static Relay (METI + MCGG)
M.T.A. Selectable
Characteristic Selectable
I
51
V
67 Overcurrent Unit (Static)
Application of Directional Overcurrent and Earthfault Protection - January 2004
Directional Unit (Static)
I
Numerical Relay Directional Characteristic
Characteristic angle Øc Øc = -180° --- 0° --- + 180° in 1° steps
Zone of forward start forward operation +Is
Øc - 90° Polarising thresholds Vp > 0.6V Vop > 0.6 to 80V in 0.2V steps for example Application of Directional Overcurrent and Earthfault Protection - January 2004
Øc
Reverse start
Øc + 90° -Is
TRANSFORMER PROTECTION
Issue A
Slide 1
Causes of failure: ¾ Environment ¾ System ¾ Mal operation ¾ Wrong design ¾ Manufacture ¾ Material ¾ Maintenance
Issue A
Slide 2
Transformer failures classification :
1. Internal failure Causes:
È Winding & terminal faults È Core faults È Onload tap changer faults È Overheating faults
Issue A
Slide 3
Transformer failures classification : 2. External failure Causes:
È Abnormal operating condition È sustained or unclear faults
Issue A
Slide 4
Vector Groups
Phase displacement
Yy0 Dd0 Zd0 Yy6 Dd6 Dz6
Lag phase displacement
Yd1 Dy1 Yz1
Lead phase displacement
Yd11 Dy11 Yz11
Group 1 0
Phase displacement
Group 2 180 Group 3 30 Group 4 30
Issue A
Slide 5
Vector Configurations 12 11 300
1, DRAW PHASE- N EUTRAL VOLTAGE VECTORS
300
Issue A
Slide 6
Vector Configurations 2. Draw Delta Connection A a
b
B
C Issue A
c Slide 7
Vector Configurations 3. Draw A Phase Windings A a a2 A2 a1
b
A 1 B
C Issue A
c Slide 8
Vector Configurations 4. Complete Connections (a) A a C1
A2
a 2 a1
A 1
C 2 C
c 1
B 1 Issue A
B 2
B
b1
b2
c 2 c Slide 9
b
Fault current distribution
Earth fault on Transformer winding T2
T1
V2
V1
X Fig.N
R Fig.3
Issue A
If
Slide 10
Fault current distribution Therefore C.T.secondary current ( on primary side of transformer) =, X2 √3
If differential setting =20% For relay operation
X2
>
20%
√3 Thus X > 59% ie. 59% of winding is unprotected. Differential relay setting
% of winding protected
10%
58%
20%
41%
30%
28%
40%
17%
50%.
7%
Issue A
Slide 11
Fault current distribution If Transformer star winding is solid earthed, fault current limited only by the leakage reactance Star side of the winding 10 9 If as 8 multiple of 7 I F.L. 6 5 4 3
Delta side
2 1
.1
Issue A
.2
.3 .4 .5 .6 .7 .8 .
9 1.0 x
p.u
Fig.Q Slide 12
Basic Protection ¾ Differential ¾ Restricted Earthfault ¾ Overfluxing ¾ Overcurrent & Earthfault
Issue A
Slide 13
Differential Protection ∗ Works on Merz-price current comparison principle ∗ Relays with bias characteristic should only be used
Applied ¾ Where protection co-ordination is difficult / not possible using time delayed elements ¾ For fast fault clearance ¾ For zone of protection
Issue A
Slide 14
Differential Protection Consideration for applying differential protection ¾ Phase correction ¾ Filtering of zero sequence currents ¾ Ratio correction ¾ Magnetizing inrush during energisation ¾ Overfluxing Issue A
Slide 15
Differential Protection - Principle • Nominal current through the protected equipment I Diff = 0 : No tripping
R I diff = 0
Issue A
Slide 16
Differential Protection - Principle • Through fault current
I Diff = 0 : No tripping
R I diff = 0
Issue A
Slide 17
Differential Protection - Principle • Internal Fault I Diff = 0 : Tripping
R
Issue A
I diff = 0
Slide 18
Biased differential protection • Fast operation • Adjustable characteristic • High through fault stability • CT ratio compensation • Magnetising inrush restraint • Overfluxing 5th harmonic restraint Issue A
Slide 19
Biased differential protection Why bias characteristic ? 100 / 1
100/50 KV
200 / 1 1A
1A
R
LOAD = 200 A
0A
I1
I2
OLTC Setting is at mid tap Issue A
Slide 20
Biased differential protection 100 / 1
100/50 KV
200 / 1 1A
0.9 A
LOAD = 200 A
R
0.1 A
OLTC SETTING IS AT 10% Differential current = 0.1 A Relay pickup setting = O.2 A, So the Relay restrains Issue A
Slide 21
Biased differential protection 100 / 1
100/50 KV
200 / 1 10 A
9A
2000 A
R
1A
OLTC SETTING IS AT 10% Relay Pickup Setting is O.2 A So the Relay Operates Issue A
Slide 22
Role of Bias 3
2
Operate
Differential current (x In) = I1+ I2 + I3 + I 4
80
1 Setting range (0.1 - 0.5) 0
%
op l S
e
Restrain lo 20% S
1
pe
2
4
3
Effective bias (x In) = I 1 + I 2 + I 3 + I 4 2 Issue A
Slide 23
USE OF ICT
Dy1(-30 )
Interposing CT provides Vector correction Yd11(+30 )
Ratio correction Zero sequence compensation
R
R
R
PROTECTION TRANSFORMATEUR CURRENT DIFFERENTIAL PROTECTION sur défaut interne: Protection différentielle
Vector Group Correction - Static Relays
Yd11
Dy1(-30 )
R R R
Vector and Ratio correction by interposing CT
Vector Group Correction - Static Relays
Yd11
R R R
Vector and Ratio correction by CT Connection
VECTOR GROUP CORRECTION
Dy1 (-30 )
Yy0 0
87
Yd11 +30
Yy0, Yd1, Yd5 , Yy6, Yd7, Yd11, Ydy0 0 , -30 , -150 , 180,+150, +30 , 0
SELECTION OF SUITABLE VECTOR CORRECTION FACTOR
Dy11 (+30 )
Yy0 0
87
Yd1 -30
CT RATIO MISMATCH CORRECTION
200/1
33kV : 11kV 10 MVA I L = 175A
I L = 525A
400/1
1.31 Amps
0.875A 1A
1A
1.14
0.76 87
ZERO SEQUENCE COMPENSATION
+VE SEQUENCE CURRENTS BALANCE REQUIRE ZERO SEQUENCE CURRENT TRAPS FOR STABILITY
A
B
C
High Impedance Principle Based on Current operated relay with an external stabilising resistor • Requires matched current transformers of low reactance design, typically class X or equivalent • Equal CT ratios • Non-linear resistor may be required to limit voltage across relay circuit during internal faults • Suitable for zones up to 200 - 300 metres (typically)
Issue A
Slide 24
High Impedance Principle RCT
2RL
M
2RL
A
ZM
RCT
ZM
RCT 2RL M
Issue A
2RL
TC RCTsaturé Slide 25
High Impedance Principle RCT
ZM
2RL
M
A
2RL
RCT
ZM
M
Issue A
Slide 26
High Impedance Principle RCT
ZM
2RL
M
A
2RL
RCT
ZM
M
TC saturé Issue A
Slide 27
High Impedance Principle RCT
ZM
2RL
M
A
2RL
RCT
ZM
M
Issue A
Slide 28
High Impedance Principle RCT
ZM
2RL
M
A
2RL
RCT
ZM
M
TC saturé
Issue A
Slide 29
High Impedance Principle RCT
ZM
2RL
M
A
2RL
RCT
ZM
M
Issue A
Slide 30
High Impedance Principle RCT
ZM
2RL
M
A
2RL
RCT
ZM
TC saturé M
Issue A
Slide 31
High Impedance Principle RCT
2RL
M
2RL
A
ZM
RCT
ZM=0
False tripping RCT 2RL M
CT Saturation 2RL
RCT
TC saturé Issue A
Slide 32
High Impedance Principle M RCT
2RL
2RL
RCT
RS A
ZM
ZM=0
RCT 2RL M
2RL
RCT
TC saturé Issue A
Slide 33
High Impedance Principle RCT
2RL
2RL
M
RCT
RS A
ZM
ZM=0
Stabilising resistor
RCT 2RL M
2RL
RCT
TC saturé
Issue A
Slide 34
High Impedance Principle RCT
2RL
2RL
M
RCT
RS A
ZM
ZM
Vset
RCT 2RL M
Issue A
2RL
RCT
Slide 35
High Impedance Principle RCT
2RL
2RL
M
RCT
RS A
ZM
ZM=0
RCT 2RL M
Issue A
ZM = 0
Vset 2RL
RCT
(CT "short circuited" )
Slide 36
High Impedance Principle RCT
2RL
2RL
M
RCT
RS A
ZM
ZM
RCT
RCT 2RL
2RL M Vset
Issue A
Slide 37
High Impedance Principle RCT
2RL
2RL
M
RCT
RS A
ZM
ZM
RCT
RCT 2RL
2RL M
Vset
Issue A
Slide 38
High Impedance Principle RC
2R
T
L
M
2R
RC
L
T
RS A
ZM
Metrosil may be required for voltage limitation
RC T
2R L
M M
ZM
RC 2R
T
L
Vset
Issue A
Slide 39
Restricted Earthfault Protection ¾ Uses high impedance principle ¾ Increased sensitivity for earth faults ¾ REF elements for each transformer winding ¾ CTs may be shared with differential element
64
64
Issue A
64 Slide 40
Restricted Earthfault Protection REF Case I : Normal Condition Stability level : usually maximum through fault level of transformer P1
P2
S1
S2 P1 S1
P1
S1
P2
S2
P2 S2 P1
P2
S1
S2
Under normal conditions no current flows thro’ Relay So, No Operation Issue A
Slide 41
Restricted Earthfault Protection REF Case II : External Earth Fault
External earth fault - Current circulates between the phase & neutral CTs; no current thro’ the relay
So, No Operation Issue A
Slide 42
Restricted Earthfault Protection REF Case III : Internal Earth Fault
For an internal earth fault the unbalanced current flows thro’ the relay
So, Relay Operates Issue A
Slide 43
Restricted Earthfault Protection Restricted Earth Fault Protection Setting 1MVA (5%) 11000V 415V
1600/1 RCT = 4.9Ω
Setting will require calculation of : 1) Setting stability voltage (VS)
80MVA
2) Value of stabilising resistor required 1600/1 RCT = 4.8Ω
RS
MCAG14 IS = 0.1 Amp
2 Core 7/0.67mm (7.41Ω/km) 100m Long
Issue A
3) Peak voltage developed by CT’s for internal fault
Slide 44
Restricted Earthfault Protection Example : Earth fault calculation :Using 80MVA base Source impedance = 1 p.u. 1 P.U.
Transformer impedance = 0.05 x 80 = 4 p.u. 1 1
1
4 I1
1
4 I2
∴ I1 = 1 = 0.0714 p.u. 14 Base current = 80 x 106 √3 x 415 = 111296 Amps
4 I0
Issue A
Total impedance = 14 p.u.
∴ IF = 3 x 0.0714 x 111296 = 23840 Amps (primary) = 14.9 Amps (secondary) Slide 45
Restricted Earthfault Protection (1) Setting voltage VS = IF (RCT + 2RL) Assuming “earth” CT saturates, RCT = 4.8 ohms 2RL = 2 x 100 x 7.41 x 10-3 = 1.482 ohms ∴ Setting voltage = 14.9 (4.8 + 1.482) = 93.6 Volts (2) Stabilising Resistor (RS) RS = VS - 1 IS IS2
Where IS = relay current setting
∴ RS = 93.6 - 1 = 836 ohms 0.1 0.22
Issue A
Slide 46
Restricted Earthfault Protection 3) Peak voltage = 2√2 √VK (VF - VK) VF = 14.9 x VS = 14.9 x 936 = 13946 Volts IS For ‘Earth’ CT, VK = 1.4 x 236 = 330 Volts (from graph) ∴ VPEAK = 2√2 √330 (13946 - 330) = 6kV Thus, metrosil voltage limiter will be required.
Issue A
Slide 47
Magnetising Inrush • Transient condition - occurs when a transformer is energised • Normal operating flux of a transformer is close to saturation level • Residual flux can increase the mag-current • In the case of three phase transformer, the point-on-wave at switch-on differs for each phase and hence, also the inrush currents
Issue A
Slide 48
Magnetising Inrush Transformer Magnetising Characteristic Twice Normal Flux
Normal Flux
Normal No Load Current No Load Current at Twice Normal Flux Issue A
Slide 49
Magnetising Inrush Inrush Current + Φm
V
Φ Im
STEADY STATE - Φm Im
2 Φm
Φ V
Issue A
SWITCH ON AT VOLTAGE ZERO - NO RESIDUAL FLUX
Slide 50
Magnetising Inrush
Issue A
Slide 51
Magnetising Inrush Effect of magnetising current
• Appears on one side of transformer only - Seen as fault by differential relay - Transient magnetising inrush could cause relay to operate • Makes CT transient saturation - Can make mal-operation of Zero sequence relay at primary
Issue A
Slide 52
Magnetising Inrush
IR IS
P1
P2
S1
S2 P1
IT
S1
P2 S2 P1
P2
S1
S2
IR + IS + IT = 3Io = 0 Issue A
Slide 53
Magnetising Inrush Effect of magnetising current
Example of disurbance records with detail
Issue A
Slide 54
Magnetising Inrush Restrain 2nd (and 5th) harmonic restraint • Makes relay immune to magnetising inrush • Slow operation may result for genuine transformer faults if CT saturation occurs
Issue A
Slide 55
Magnetising Inrush Restrain Bias differential threshold
Differential comparator
Trip T1 = 5ms
T2 = 22ms
Differential input Comparator output T1 Trip T2
Issue A
Reset
Slide 56
Overfluxing - Basic Theory Overfluxing = V/F
Causes Low frequency High voltage Geomagnetic disturbances Issue A
Slide 57
Overfluxing - Basic Theory V = kfΦ
2Φm
Φm Ie
Effects Transient Overfluxing - Tripping of differential element Prolonged Overfluxing - Damage to transformers
Issue A
Slide 58
Overfluxing - Condition Differential element should be blocked for transient overfluxing-+ 25% OVERVOLTAGE CONDITION
Overfluxing waveform contains very high 5th Harmonic content
43% 5TH HARMONIC CONTENT Issue A
Slide 59
Overfluxing - Protection V
KΦ α f
• Trip and alarm outputs for clearing prolonged overfluxing • Alarm : Definite time characteristic to initiate corrective action • Trip : IT or DT characteristic to clear overfluxing condition
Issue A
Slide 60
BUCCHOLZ PROTECTION Oil conservator
Bucholz Relay
Issue A
Slide 60
BUCCHOLZ PROTECTION Buchholz Relay Installation To oil conservator 3 x internal pipe diameter (minimum) 5 x internal pipe diameter (minimum)
76 mm typical Transformer
Issue A
Slide 60
BUCCHOLZ PROTECTION Buchholz Relay Petcock Alarm bucket
Mercury switch To oil conservato r From transformer
Trip bucket
Deflector plate Issue A
Slide 60
BUCCHOLZ PROTECTION Buccholz Protection Application Accumulation of gaz Oil Leakage Severe winding faults
Issue A
Slide 60
BUCCHOLZ PROTECTION Accumulation of Gaz Interturn faults Winding faults to earth with low power (fault close to neutral for example)
Issue A
Slide 60
BUCCHOLZ PROTECTION Inter-Turn Fault
E
CT Load
Shorted turn
Nominal turns ratio : 11,000 / 240 Fault turns ratio Current ratio
: 11,000 / 1 :1 / 11,000 Primary
Issue A
Secondary Slide 60
BUCCHOLZ PROTECTION Inter-Turn Fault
E
CT Shorted turn
Nominal turns ratio : 11,000 / 240 Fault turns ratio Current ratio
: 11,000 / 1 :1 / 11,000 Primary
Issue A
Secondary Slide 60
BUCCHOLZ PROTECTION Interturn Fault Current / Number of Turns Short Circuited Primary current (multiples of rated current) 100 Fault current (multiples of rated current)
80
60
40
20
5
Issue A
10
15
20
25
Turn shortcircuited (percentage of winding) Slide 60
BUCCHOLZ PROTECTION Interturn Fault Current / Number of Turns Short Circuited Primary current (multiples of rated current) 100 Fault current (multiples of rated current)
80
60
Fault current very high
40
Detected by Bucholz relay
20
Primary phase current very low
5
Issue A
10
15
20
25
Not detected by current operated relays Slide 60
BUCCHOLZ PROTECTION Accumulation of Gaz Interturn faults Winding faults to earth with low power (fault close to neutral for example)
Issue A
Slide 60
BUCCHOLZ PROTECTION Earth Fault Current / Number of Turnsof Short Circuited multiples max fault current Primary current 100
80 Fault current 60
40
20
5 Issue A
10
15
20
25
Turn shortcircuited (percentage of winding)
Slide 60
BUCCHOLZ PROTECTION Accumulation of Gaz Operating principle
Issue A
Slide 60
BUCCHOLZ PROTECTION
Buchholz Relay Accumulation of gaz
Issue A
Slide 60
BUCCHOLZ PROTECTION
Buchholz Relay Accumulation of gaz
Issue A
Slide 60
BUCCHOLZ PROTECTION
Buchholz Relay Accumulation of gaz
Issue A
Slide 60
BUCCHOLZ PROTECTION
Accumulation of gaz
Color of gaz indicates the type of fault White or Yellow : Insulation burnt Grey : Dissociated oil
Issue A
Slide 60
BUCCHOLZ PROTECTION Buchholz Relay Accumulation of gaz
Issue A
Gaz can be extracted for detailled analysis
Slide 60
BUCCHOLZ PROTECTION Effects of Oil Maintenance
• After oil maintenance, false tripping may occur because Oil aeration Bucholz relay tripping inhibited during suitable period
Need of electrical protection
Issue A
Slide 60
BUCCHOLZ PROTECTION Bucholtz Protection Application Accumulation of gaz Oil Leakage Severe winding faults
Issue A
Slide 60
BUCCHOLZ PROTECTION Buchholz Relay Oil Leakage
Issue A
Slide 60
BUCCHOLZ PROTECTION Buchholz Relay Oil Leakage
Issue A
Slide 60
BUCCHOLZ PROTECTION Buchholz Relay Oil Leakage
Issue A
Slide 60
BUCCHOLZ PROTECTION Buchholz Relay Oil Leakage
Issue A
Slide 60
BUCCHOLZ PROTECTION Buccholz Protection Application Accumulation of gaz Oil Leakage Severe winding faults
Issue A
Slide 60
BUCCHOLZ PROTECTION Buchholz Relay Severe winding fault
Issue A
Slide 60
BUCCHOLZ PROTECTION Buchholz Relay Severe winding fault
Issue A
Slide 60
BUCCHOLZ PROTECTION Buchholz Relay Severe winding fault
Issue A
Slide 60
CONCLUSION
Scheme exemple Up to 1MVA 3.3kV
200/5
1500/5 P120
51
50
1MVA 3.3/0.44kV
51 N
64
MCAG14
1500/5
51 N
50 N
P121
CONCLUSION
Scheme exemple 1 - 5MVA
11kV 51 64
1000/5 P120
50
MCAG14
5MVA 11/3.3kV
51 N
64
P121
1000/5
MCAG14 3.3kV
CONCLUSION
Scheme exemple Above 5MVA 33KV
51
50 P141
200/5
P120 10MVA 33/11KV
51 N
600/5
64 MCAG14
600/5 5/5A
87 P631
CONCLUSION
Three Winding Transformer 300/5
63MVA 132KV
25MVA 11KV
1600/5
50MVA 33KV
1000/5
4.59
5.51
10.33
2.88
5
2.88
5
All interposing C.T. ratio’s refer to common MVA base (63MVA)
Pilot Wire Differential Protection of Feeders
1
> Title of presentation - Date - References
1
X
Why Needed
X
Circulating Current and Balanced Voltage Principles
X
Electromechanical Pilot Wire Relays and Schemes
X
Solid State Pilot Wire Relays and Schemes
X
Polar Diagrams
X
Summation Transformers and Fault Settings
X
Line Charging Currents
X
Pilot Wire :
Characteristics Isolation Supervision
2
X
Overcurrent Check
X
Intertripping / Destabilising
> Title of presentation - Date - References
2
Differential Feeder Protection Why Needed ? -
Overcomes application difficulties of simple overcurrent relays when applied to complex networks, i.e. co-ordination problems and excessive fault clearance times. Basic Principle Involves measurement of current at each end of feeder and Transmission of information between each end of feeder
Protection should operate for faults inside the protected zone (i.e. the feeder) but must remain stable for faults outside the protected zone. Thus can be instantaneous in operation. 3
> Title of presentation - Date - References
3
System Where Directional O/C Cannot Be Used I1
1
10 (v)
(v)
2 (i) (i) → (v) represents increasing time setting
9 (i)
3 (iv)
8 4 (ii)
(iv)
I2
5 7
6
(ii)
(iii)
(iii)
I1
I1 10
10
I1
I2
I1+I2
I1+I2
I2
2
4 8 8
I1
6
4 must operate before 8 4
> Title of presentation - Date - References
I1+I2
I2
I2 4
I1+I2
4 must operate after 8
4
Use of Pilot Wire Differential Protection 10 (iii) 1 2
9 (i)
8 (ii) 4
3
5 7
(ii)
6
(i)
(iii)
c, d, e, f are pilot wire differential relays l is non directional O/C relays g, h, i, j are directional O/C relays Operating times :- {g and l} > {i and j} > {k and h} > {c, d, e and f} 5
> Title of presentation - Date - References
5
Merz-Price Differential or Unit Protection
Protected Circuit or Plant
R
Boundaries of protection coverage accurately defined Protection responds only to faults in protected zone 6
> Title of presentation - Date - References
6
End A
End B
Relay
Circulating Current System End A
End B
Relay Balanced Voltage System Basic mertz-price principle applies well where CT secondary circuit can be kept short, protection of transformers, busbars, machines.
7
eg.
For feeder protection where boundaries of protection are a distance apart, a communication channel is required. > Title of presentation - Date - References
7
Unit Protection Involving Distance Between Circuit Breakers (1) A
B
Relaying Point
R Trip B
Trip A
Simple Local Differential Protection 8
> Title of presentation - Date - References
8
Unit Protection Involving Distance Between Circuit Breakers (2) A
B Communication Channel
Relaying Point
Relaying Point R
R
Trip A
Trip B
Unit Protection Involving Distance Between Circuits 9
> Title of presentation - Date - References
9
Early Merz-Price Balanced Voltage Systems for Feeders
R
R
2 Problems : (1) Maloperation due to unequal open circuit secondary voltages of the two transformers for thro’ fault currents. (2) High output voltages of CT’s cause capacitance currents to flow thro’ relay. Since capacitive currents are proportional to pilot length, relay insensitive for all but very short lines. 10
> Title of presentation - Date - References
10
Basic Pilot Wire Schemes
B
with Bias (1)
B I
V OP
OP
I
V
Circulating Current 11
> Title of presentation - Date - References
11
Translay Differential Protection End A
End B
A B C Summation Winding Secondary Winding
Pilot
Bias Loop 12
> Title of presentation - Date - References
12
MBCI Feeder Protection Circuit Diagram A
A
B
B
C
C
T1
Tr
Tt ØC
PILOT WIRES
To
13
T1 T2 To Tr Tt
RVO v
T2
T1
Tr
RS Ts
RPP
RPP
T2
Ro
- Summation Transformer - Auxiliary Transformer - Operating Winding - Restraining Winding - Reference Winding > Title of presentation - Date - References
ØC T t
To
Ro
Ts RVD Ro Rpp Øc
RS RVO v
-
Ts
Auxiliary Winding Non Linear Resistor Linear Resistor Pilots Padding Resistor Phase Comparator
13
Summation Current Transformer Output (1) a b c
l
m
output
n
14
> Title of presentation - Date - References
14
Summation Transformer Sensitivity for Different Faults (1) IA 1 IB 1 Output for operation = K
IC 3 IN Let output for operation = K (1)
15
Consider A-E fault for relay operation :
> Title of presentation - Date - References
IA (1 + 1 + 3) > K IA > 1/5K or 20%K 15
Summation Transformer Sensitivity for Different Faults (2) (2)
(3)
B-E fault for relay operation : C-E fault for relay operation :
IB (1 + 3) > K IB > 25%K IC x (3) > K IC > 331/3%K
(4)
(5)
(6) 16
AB fault for relay operation : BC fault for relay operation : AC fault for relay operation :
> Title of presentation - Date - References
IAB x (1) > K IAB > 100%K IBC x (1) > K IBC > 100%K IAC (1 + 1) > K IAC > 50%K
16
17
Type of Fault
Relay Sensitivity
Sensitivity of E/M Pilot Wire Relay
A-E
20% K
22% In
B-E
25% K
28% In
C-E
331/3 % K
22% In
AB
100% K
90% In
BC
100% K
90% In
CA
50% K
45% In
3 Phase
57.7% K
52% In
> Title of presentation - Date - References
17
Fault Settings for Plain Feeders Input transformer summation ratio is 1.25 : 1 : N where N = 3 for normal use and N = 6 to give low earth fault settings Fault
Settings N = 3
N = 6
A-N B-N C-N
0.19 x Ks x In 0.25 x Ks x In 0.33 x Ks x In
A-B B-C C-A A-B-C
0.80 1.00 0.44 0.51
x x x x
Ks Ks Ks Ks
x x x x
0.12 x Ks x In 0.14 x Ks x In 0.17 x Ks x In
In In In In
Ks is a setting multiplier, variable from 0.5 to 2.0 In is the relay rated current 1 Amp or 5 Amps 18
> Title of presentation - Date - References
18
Selection of Ks & N Values of Ks and N are chosen such that IS (C - N) < 0.3 x min. E/F current. For solidly earthed systems :IS (A - N) > 3.2 x steady state line charging current. For resistanced earthed systems with one relay per phase :IS (A - N) > 1.9 x steady state line charging current. For systems where the steady state charging current is negligible select Ks setting to give required primary sensitivity.
19
> Title of presentation - Date - References
19
Pilot Wire Resistance and shunt capacitance of pilots introduce magnitude and phase differences in pilot terminal currents.
Pilot Resistance Attenuates the signal and affects effective minimum operating levels. To maintain constant operating levels for wide range of pilot resistance, padding resistor used.
R
Rp/2
R
Rp/2 Padding resistance R set to ½ (1000 - Rp) ohms 20
> Title of presentation - Date - References
20
Pilot Capacitance
Circulating current systems : X
Pilot capacitance effectively in parallel with relay operating coil.
X
Capacitance at centre of pilots has zero volts across them.
Balanced voltage systems :
21
X
Relay operating coil connected in series with pilot.
X
Capacitance current therefore tends to cause instability.
> Title of presentation - Date - References
21
Pilot Isolation Electromagnetic Induction Field of any adjacent conductor may induce a voltage in the pilot
circuit.
Induced voltage can be severe when : (1)
Pilot wire laid in parallel to a power circuit.
(2)
Pilot wire is long and in close proximity to power circuit.
(3)
Fault Current is severe.
Induced voltage may amount to several thousand volts. Danger to personnel Danger to equipment Difference in Station Earth Potentials Can be a problem for applications above 33kV - even if feeder is
22
> Title of presentation - Date - References
short.
22
Formula for Induced Voltage e = 0.232 I L Log10 De/S where
I
=
primary line E/F current
L
=
length of pilots in miles
De
=
Equiv. Depth of earth return in metres = 655 . √e/f
e
=
soil resistivity in Ω.m
f
=
frequency
s
= separation between power line and pilot circuit in metres
Effect of screening is not considered in the formula. If the pilot is enclosed in lead sheath earthed at each end, screening is provided by the current flowing in the sheath. Sheath should be of low resistance. 0.3 V / A / Mile Unscreened Pilots 0.1 V / A / Mile Screened Pilots 23
> Title of presentation - Date - References
23
Pilot circuits and all directly connected equipment should be insulated to earth and other circuits to an adequate voltage level. Two levels are recognised as standard : 5kV & 15kV
Relay Case 15kV
5kV Pilot Terminal
Relay Input
Relay Circuit Pilot Wire 2kV
24
> Title of presentation - Date - References
5kV
24
Supervision of Pilot Circuits Pilot circuits are subject to a number of hazards, such as :
- Manual Interference - Acts of Nature (storms, subsidence, etc.) - Mechanical Damage (excavators, impacts)
Therefore supervision of the pilots is felt to be necessary.
Two types exist :
- Signal injection type - Wheatstone Bridge type
25
> Title of presentation - Date - References
25
Pilot Wire Supervision
Pilot Wire Open Circuited Pilot Wire Short Circuited Pilot Wire Crossed
Circulating Current Schemes
Balanced Voltage Schemes
Maloperate
Stable
Stable
Maloperate
Maloperate
Maloperate
Maloperation occurs even under normal loading conditions if 3-phase setting < ILOAD. Overcurrent check may be used to prevent maloperation. Overcurrent element set above maximum load current.
26
> Title of presentation - Date - References
26
Pilot Wire Supervision Relay SJA PILOT
Cross Pilot Detector Box B Unbalance Detector Circuit
A Supervision Supply 27
> Title of presentation - Date - References
27
MRTP Features
28
X
Detects open circuit, short circuit or crossed pilots.
X
Gives indication of loss of supervision supply.
> Title of presentation - Date - References
28
Connections for Pilot Supervision (5 kV)
A1
A1 PILOTS
LVAC
29
A2
A2
A3
A3
AC
> Title of presentation - Date - References
29
Overcurrent Check Relays (1)
A B C 50 A
50 C
PILOT WIRE RELAY (87PW)
50 G
30
> Title of presentation - Date - References
30
Overcurrent Check Relays (2)
50A-1
87PW-1 TRIP CIRCUITS
+ 50C-1
50G-1
31
> Title of presentation - Date - References
Isoc > Ifl 0.9 Isef > 1.2 IZ Isef < 0.8 x Ief
31
System Requiring Intertripping
Source Feeder Protection Busbar Protection
32
> Title of presentation - Date - References
32
Destabilising Relay MVTW01
P6
S2
P7
PILOTS S1
17
MBCI 18 19
17
UN-1
18 19
UN-2 UN-3
20 I1 V x (1) + I2 V x (2) + V x (3) + I3 - I4
UN 3
MVTW01
33
> Title of presentation - Date - References
33
November 2002
MiCOM P521 Numerical Current Differential Protection Relay
34
> Title of presentation - Date - References
34
Current Differential Principle
End B
End A
IA
IF
IB
Communication Link IA + IB = 0 Healthy IA + IB ≠ 0 (= IF) Fault 35
> Title of presentation - Date - References
35
All Digital/Numerical Design
0IIIIII0I0.....0I0IIIIII Digital messages 0 End A
A/ D
End B
µP
Comms Channel
Digital communication interface (electrical or fibre) 36
> Title of presentation - Date - References
36
Current Differential Advantages X No voltage transformers needed X Detect very high resistance faults X Uniform trip time X Clearly defined zone of operation X Simple to set with no coordination problems
37
> Title of presentation - Date - References
37
MiCOM P521 Protection Comms
38
> Title of presentation - Date - References
38
Current Differential Signalling Options X Electrical communications
EIA485 (direct or via PZ511 interface) EIA232 / EIA485 Modems (requires single twisted pair) X Direct fibre optic
850 nm multi-mode 1300 nm multi-mode 1300 nm single mode X Multiplexed communications
39
> Title of presentation - Date - References
39
Direct 4 Wire EIA485 Connection 1.2km max
64kbps
Tx MT RS485
Rx
MT RS485
2 Screened Twisted Pairs
R x T x
Surge Protection 40
> Title of presentation - Date - References
40
4 Wire EIA485 Up To 10km 10km max
19.2kbps
Tx PZ511 Interface
Rx
PZ511 Interface
2 Screened Twisted Pairs
R x T x
EIA 485 41
NOTE:10/ 20kV isolation transformers available if required (4 required per scheme) > Title of presentation - Date - References
41
Pilot Wire Communications (1) 10km max
19.2kbp R Leased s Leased x Line Line Modem Twiste Modem Rx T d Pair (Pilot x Cable) EIA 485 or EIA 232 Tx
42
NOTE:10/ 20kV isolation transformers available if required (2 required per scheme) > Title of presentation - Date - References
42
Pilot Wire Communications (2) 10km max
Tx
Same as Fibre..!! 64kbps
MDSL Modem Twiste
Rx
d Pair (Pilot Cable)
R MDSL x Modem
T x
EIA 485 43
NOTE:10/ 20kV isolation transformers available if required (2 required per scheme) > Title of presentation - Date - References
43
Condition Line Communications No strict limits
9.6 kbps
Tx Dial-up Modem
Rx
44
R Dial-up x Modem
Conditioned Telephone Line EIA 485 or EIA 232
> Title of presentation - Date - References
T x
44
Direct Optical Fibre Link
OPGW
45
> Title of presentation - Date - References
45
Communications Path for Fibre Optic Application
T x R x End A
46
> Title of presentation - Date - References
CH1
R x T x End B
46
Optical Budgets for Direct Optical Connection Between Relays 850nmMulti Mode
1300nmMulti Mode
-19.8dBm
-8.2dBm
-8.2dBm
-25.4dBm
-38.2dBm
-38.2dBm
Optical Budget
5.6dB
30.0dB
30.0dB
Less Safety Margin (3dB)*
2.6dB
27.0dB
27.0dB
2.6dB/km
0.8dB/km
0.4dB/km
1km
30km
60km
Min. Transmit Output Level Receiver Sensitivity
Typical Cable Loss Max Transmission. Distance
Short Haul
1300nm Single Mode
Medium Haul
Key: * 3dB allowance for joint loss/ageing 47
> Title of presentation - Date - References
47
Interfacing to Multiplexers
P591/2/3 interface unit
850nm multimode optical fibre
48
> Title of presentation - Date - References
Multiplexer
G.703, X21 or V.35 electrical
48
Multiplexed Optical Link
Earth wire optical fibre
Multiplexer
Multiplexer 34 Mbit/s
Telephone
64k bits/s
Telecontrol
End A
End B Teleprotection
P521 current differential protection 49
> Title of presentation - Date - References
49
Multiplexed Microwave Link
Multiplexer
Multiplexer
Telephone 64k bits/s
Telecontrol
End A
End B Teleprotection
50
> Title of presentation - Date - References
50
Propagation Delay Compensation
X Synchronise sampling in both relays
Direct comparison of samples IRIG-B a possibility, but not always available (= protection out of service)
X Asynchronous sampling
Continual time difference measurement Vector transformation in software
51
> Title of presentation - Date - References
51
Propagation Delay Problem
Relay A
Relay B Current at B
Current received from A Propagation delay 52
> Title of presentation - Date - References
52
Propagation Delay Time Measurement - 1
Relays A
tA1 tA2
Data mess Curre ag e vecto nt rs tA 1 tp1
tA3 tA4 tA5 53
B
> Title of presentation - Date - References
tB1 tB2 tB3
tB
*
tB4 tB5 53
Propagation Delay Time Measurement - 2 Propagation delay time Measured sampling time tp1 = tp2 = 1/2 (tA - tA1) - td tB3 = (tA - tp2)
*
tA1 tA2 tB3
* tA *
54
*
*
Current vectors
tp1
tA5
tB1 tB2 td
tA3 tA4
tA 1
tp2 td A t tB 1 3
> Title of presentation - Date - References
nt e r r u C or s vect ge a s s e Data m
tB3
tB
*
tB4 tB5
54
Time Alignment of Current Vectors
I (tA4) θ ∆ θ
I (tB3 )
*
∆t = (tA4 - tB3 ) ∆θ=ω∆ t If then ∆ θ) 55
*
I (tB3 ) = Is + j Ic = I cosθ + j I sinθ I (tA4) = I (tB3 ) . (cos ∆ θ + j sin = I cos (θ + ∆ θ) + j I sin (θ + ∆ θ)
> Title of presentation - Date - References
*
*
55
Current Differential X Dual slope bias characteristic
X Selectable operating time / characteristic
Allows grading with tapped off fuse protected loads Allows smaller CT’s to be used X Operating times when set to instantaneous:
Baud rate (kbits/s) 9.6 19.2 56 64 56
> Title of presentation - Date - References
Max. Time (ms) 100 80 45 45
Typical Time (ms) 90 70 30 30 56
Current Differential Characteristic IA
IB
Differential current I diff
=
rc e P
Trip
I A + IB P
I S1
k1 s a i b age t n e c r e
g a t en
ia b e
2 k s
No trip
I S2 Bias current I bias = 1/2 ( IA + I B )
57
> Title of presentation - Date - References
57
Line Charging Currents
A/km
A/km
30
1
1.2
0.3 11kV
400kV Line Volts
Underground cables
132kV
400kV Line Volts
Overhead lines
•Capacitive current is only seen at one end of the line •To prevent instability set Is1 setting to 2.5x steady state line charging cur •Capacitive inrush current is rejected by the relay filtering methods
58
> Title of presentation - Date - References
58
CT Ratio Correction 500/1
600/1 0.83A
Max Load = 500A
End A
1.0A
Comms Channel
End B
To correct CT ratio mismatch a correction factor can be applied to End A. To maintain good sensitivity, correct to 1 pu:1A Correction Factor = = 1.2 0.83A 59
> Title of presentation - Date - References
59
Protection of Transformer Feeders
Power transformer
Ratio correction
Vectorial correction Virtual interposing CT
60
> Title of presentation - Date - References
Virtual interposing CT
60
Stability for Magnetising Inrush Current Magnetising inrush current flows into the energised winding at switch on This current is not represented at the remote end of the line A method of restraint is required to avoid trips on closure of the breaker : Inrush current is rich in harmonics: 2nd, 5th etc.. Increase bias current by adding a multiple of 2nd harmonic current = RESTRAINT
Inrush restraint facility can be enabled or disabled via a dedicated setting MiCOM-P540-61 61
> Title of presentation - Date - References
61
Inrush Current - Theory
+Φm
V
Φ Im
Steady state - Φm Im
2Φm
Φ V
Switch on at voltage zero - No residual flux
MiCOM-P540-62 62
> Title of presentation - Date - References
62
Example MV Application: Teed Feeder Protection
End A X
Differential protection can be IDMT or DT delayed to discriminate with tapped feed protection:
63
IF
End B
Fused spurs Tee-off transformer in-zone
> Title of presentation - Date - References
63
Direct Intertrip (DIT)
Relay A
Relay B Transformer Protection DTT=1
Data Message
64
+ > Title of presentation - Date - References
-
+ 64
Permissive Intertrip (PIT) IB F Relay A
Relay B
Busbar Relay
PIT=1
Data Message +
X
65
+
Example shows interlocked overcurrent protection
X
-
Feeder fault seen within busbar zone Remote end trip after set delay for PIT & current > Is1
Current check can be disabled thus giving a second DIT channel > Title of presentation - Date - References
65
66
> Title of presentation - Date - References
66
Generator Protection
Generator Protection
The extent and types of protection specified will depend on the following factors :-
Type of prime mover and generator construction MW and voltage ratings Mode of operation Method of connection to the power system Method of earthing
2
2
Connection to the
Power System
1. Direct :
2. Via Transformer :
3
3
Typical Generator Installations
Generator Transformer
Generator Transformer Station Transformer
Earthing Transformer
Unit / Station Transformer
1(b) 4
Unit Transformer
1(c) 4
Generator Protection Requirements
To detect faults on the generator To protection generator from the effects of abnormal power system operating conditions To isolate generator from system faults not cleared remotely
Action required depends upon the nature of the fault.
Usual to segregate protection functions into : Urgent Non-urgent Alarm 5
5
Generator Faults Mixture of mechanical and electrical problems. Faults include :Insulation Failure Stator Rotor
Excitation system failure Prime mover / governor failure Bearing Failure Excessive vibration Low steam pressure etc.
6
6
System Conditions
Short circuits Overloads Loss of load Unbalanced load Loss of synchronism
7
7
Generator Protections to be Considered Earth faults on stator and generator connections Phase faults on stator and generator connections Interturn faults on stator Backup protection :- External Earth faults External Phase faults Failure of prime mover Loss of field Unbalanced loading Rotor earth faults and interturn faults Overload Failure of speed governing system Sudden loss of load
8
8
Stator Earth Fault Protection
Fault caused by failure of stator winding insulation Leads to
burning of machine core welding of laminations
Rebuilding of machine core can be a very expensive process Earth fault protection is therefore a principal feature of any generator protection package TYPE OF PROTECTION
9
METHOD OF EARTHING
METHOD OF CONNECTION 9
Method of Earthing (1) Machine stator windings are surrounded by a mass of earthed metal Most probable result of stator winding insulation failure is a phase-earth fault Desirable to earth neutral point of generator to prevent dangerous transient overvoltages during arcing earth faults Several methods of earthing are in use Damage resulting from a stator earth fault will depend upon the earthing arrangement
10
10
Method of Earthing (2)
Solidly Earthed Machines :
Fault current is high Rapid damage occurs burning of core iron welding of laminations
Used on LV machines only
11
11
Method of Earthing (3) Desirable to limit earth fault current : limits damage reduces possibility of developing into phase-phase fault Degree to which fault current is limited must take into account : detection of earth faults as near as possible to the point ease of discrimination with system earth fault protection (directly connected machines)
12
neutral
12
Method of Earthing : Limitation of Earth Fault Current (1) Less than 5A :
F
Earth faults on the power system are not seen by the generator earth fault protection.
Discrimination not required ∴ can limit current to very low value. 20A : Used on oil and gas platforms. Limits power supply disturbance, but still enables grading of up to 3 zones.
13
13
Method of Earthing : Limitation of Earth Fault Current (2)
100A : As for 20A, but higher current allows better discrimination and sensitivity. Generator Full Load Current (1200A max) : Most popular. Used for ease of fault detection and discrimination. Residual connection of CTs can be used, BUT Can result in serious core damage.
14
14
Stator Earth Fault Protection and Protection Against Earth Faults on Generator Connections Depending on the Generator arrangement this can be provided by :Time delayed overcurrent protection Time delayed earth fault protection Sensitive earth fault protection Neutral displacement voltage relay Neutral displacement voltage detection by overcurrent relay High impedance restricted earth fault protection High impedance differential protection Biased differential protection Directional earth fault protection 100% stator earth fault protection
15
15
Overcurrent Protection (1) For small generators this may be the only protection applied. With solid earthing it will provide some protection against earth faults. For a single generator, CTs must be connected to neutral end of stator winding.
51 16
16
Overcurrent Protection (2) For parallel generators, CTs can be located on line side.
51
17
17
Stator Earth Fault Protection Directly Connected Generators :
51N
Earthed Generator : Earth fault relay must be time delayed for co-ordination with other earth fault protection on the power system.
50N
51N
Unearthed Generators : Other generators connected in parallel will generally be unearthed. Protection is restricted to faults on the generator, grading with power system earth fault protection is not required. A high impedance instantaneous relay can be used (Balanced Earth Fault protection). 18
18
Percentage Winding Protected 11.5kV; 75,000KVA
xV
250/1A
IS
xV R For operation
ΙF =
Ι S(PRIMARY) R
33Ω
< ΙF
xV R x.6600 < < x.200 33 1 Ι S(SECONDARY) < x.200 x < 0.8x 250
3RD harmonic current * Or use relay with 3RD harmonic rejection
R’ = Effective Primary Resistance = N2.R 22
22
Restricted Earthfault Protection
RSTA B
High Impedance Principle
64
Instantaneous Protection Protects approx. 90 - 95% of generator winding. All CT’s should be similar - Good quality - Class ‘X’ 23
23
Restricted Earthfault Protection for Generators on 4 Wire L.V. Systems (1) Earthing at Generator Neutral
5 x CT’s required RSTAB 64
24
24
Restricted Earthfault Protection for Generators on 4 Wire L.V. Systems (2) Earthing at Busbars
RSTAB 64 4 x CT’s required
25
25
Differential Protection (1) Provides high speed protection for all fault types May be : High impedance type : Biased (low impedance) type Good quality CT’s required CT’s required in neutral end of winding
High Impedance Scheme
Stabilising Resistors Relay
26
26
Differential Protection (2)
BIAS
BIAS
OPERATE
Biased Differential Scheme 27
27
Differential Protection (3)
INTERPOSING C.T.
Overall Differential Scheme 28
28
Stator Earth Fault Protection
100% Stator Earth Fault Protection : Standard relays only cover 95% of winding. Probability of fault occuring in end 5% is low. On large machines 100% stator earth fault protection may be required. Two methods :
29
*
Low Frequency Injection
*
Third Harmonic Voltage Measurement 29
100% Stator Earth Fault Protection For Large Machines Only Two methods :Low frequency injection – 12.5Hz to 20Hz
Third harmonic voltage - various
Low Frequency Injection
Earthing Transformer
59 Complete protection during start-up if source is independent of generator, e.g. derived from station battery.
Injection Transformer
Independent of system V, f and load current. High cost due to injection equipment.
51
30
Alternative Injection Points 30
Third Harmonic Neutral Voltage Scheme
Relies on >1% generated 3rd harmonic volts 59
27 59P
27 - 3rd harmonic undervoltage relay. 59P - Terminal Voltage Check
59
Allows trip if circuit breaker is open but terminal voltage present.
59P
TRIP 59 - Conventional neutral overvoltage protection.
27
OVERLAP
27
59 FUNDAMENTAL FREQ. ELEMENT
0
50
100
Earth Fault Position 31
31
100% Stator Earth Fault Protection a)
UTE
G N
UTE T
0 N UNE
50%
T 100%
m
UNE b)
UTE
G N
T
0 N
UTE 50%
T 100%
m
c)
N
G
T
0 N UNE UNE
50%
100%
m P2175ena
Distribution of 3rd harmonic voltage along the stator winding (a) normal operation (b) stator earth fault at star point (c) stator earth fault at the terminals 32
32
Stator Phase-Phase Fault Protection (1)
Phase-phase faults caused by :
Insulation failure Flashover in terminal box
Majority of phase-phase faults begin as earth faults. High fault current causes rapid damage ∴ fast protection required.
33
33
Stator Phase-Phase Fault Protection (2) Single Generator Use time delayed overcurrent. CTs must be in neutral side to cover winding faults.
51
51
51
Small solidly earthed machines - overcurrent also provides degree of earth fault protection. Overcurrent is often only protection applied to small machines. 34
34
Stator Phase-Phase Fault Protection (3) Larger Machines, Parallel Operation Require Differential Protection
Type types :
High impedance - most common Biased (low impedance) - used for generator - generator transformer sets
Class X CTs required.
35
35
Stator Phase-Phase Fault Protection (4) High Impedance Scheme
Stabilising Resistors Relay
36
36
Stator Phase-Phase Fault Protection
Previous methods require access to winding neutral end
Small machines : Star connection made inside machine Winding neutral ends are not brought out
If high speed protection required, restricted earth fault scheme should be used
37
37
Stator Interturn Fault Protection (1)
Longitudinal differential system does not detect interturn faults
Interturn fault protection not commonly provided because : Fault rare Even if interturn fault occurs, will develop into earth fault
Possible that serious damage can occur before fault is detected
38
38
Stator Interturn Fault Protection (2) Zero Sequence Voltage Method :
VA VB VC FAUL T
VA
VB VC
VR
3rd Harmonic Rejection Required
R
39
VR = VA + VB + VC 39
Stator Interturn Fault Protection (3) Transverse Differential Protection (Double Wound Machines) :
Bias Coils
Operate Coils
40
40
Prime Mover Failure (1) Isolated Generators : Machine slows down and stops. Other protection initiates shut down.
Parallel Sets : System supplies power - generator operates as a motor. Seriousness depends on type of drive.
Steam Turbine Sets : Steam acts as a coolant. Loss of steam causes overheating. Turbulence in trapped steam causes distortion of turbine blades. Motoring power 0.5% to 6% rated. Condensing turbines, rate of heating slow. Loss of steam instantly recognised.
41
41
Prime Mover Failure (2) Diesel Driven Sets : Prime mover failure due to mechanical fault. Serious mechanical damage if allowed to persist. Motoring power from 35% rated for stiff machine, to 5% rated for run in machine.
Gas Turbines : Motoring power 100% rated for single shaft machine, 10% to 15% rated for double shaft.
Hydro Sets : Mechanical precautions taken if water level drops. Low head types - erosion and cavitation of runner can occur. Additional protection may be required.
42
42
Prime Mover Failure (3)
Reverse Power Protection : Reverse power measuring relays used where protection required. Single phase relay is sufficient as prime mover failure results in balanced conditions. Sensitive settings required - metering class CTs required for accuracy.
43
43
Reverse Power Protection (1) Importing lagging VAR’s -MVARLAG
Leading P.F. Operate -MW
Restrain +MW
87.1°
Operate
Restrain Lagging P.F.
+MVARLAG Exporting lagging VAR’s 44
44
Loss of Excitation (1) EFFECTS Single Generator : Loses output volts and therefore load. Parallel Generators : Operate as induction motor (> synch speed) Flux provided by reactive stator current drawn from system-leading pf Slip frequency current induced in rotor - abnormal heating Situation does not require immediate tripping, however, large machines have short thermal time constants - should be unloaded in a few seconds.
45
45
Loss of Excitation (2) Simple Protection Scheme
Field Winding
Exciter
Shunt
Requires access to
Ie
field connections. DC relay (setting < Ie min)
Not suitable if generator operates normally with low
Aux Supply
excitation (large T1
machines). Alternative scheme monitors impedance
T2
Overcomes Slip Frequency Effects
0.2 - 1 sec
at generator Alarm or terminals. Trip
2 - 10 secs 46
46
Loss of Excitation (3) Alternative Scheme
XG
XT
XS ES
EG R
On field failure ratio EG / ES decreases and rotor angle increases.
Machine starts to pole slip with decaying internal EMF.
47
47
Loss of Excitation (4) Impedance seen by relay follows locus shown below :
X
Load Impedance
Impedance Locus
R Offset – Prevents operation on pole slips Diameter
Typically : Offset 50-75%X’d Diameter 50-100% XS 48
Relay Characteristic Time Delayed 48
Impedance Diagram for Various Operating Modes of Machine jx
EXPORT WATTS EXPORT VARAG
IMPORT WATTS EXPORT VARLAG
R
-R EXPORT WATTS EXPORT VARLEAD
IMPORT WATTS EXPORT VARLEAD
-jx
49
EXPORTING VARLAG
=
IMPORTING VARLEAD
EXPORTING VARLEAD
=
IMPORTING VARLAG 49
Unbalanced Loading (1)
Effects Gives rise to negative phase sequence (NPS) currents results in contra-rotating magnetic field. Stator flux cuts rotor at twice synchronous speed. Induces double frequency current in field system and rotor body. Resulting eddy currents cause severe over heating.
50
50
Unbalanced Loading (2) Protection Machines are assigned NPS current withstand values : * *
Continuous NPS rating, I2R Short time NPS rating, I22t
If possible level of system unbalance approaches machin continuous withstand, protection is required. Use negative sequence overcurrent relay. Relay should have inverse time characteristic to match generator I22t withstand. Relay pick-up setting should be just below I2R rating. Can use an alarm setting of 70% to 100% to pick-up. 51
51
Unbalanced Loading (3) Machine NPS Withstand Values TYPE OF MACHINE
ROTOR COOLING
Typical Salient Pole Cylindrical Rotor
Conventional Air Conventional Hydrogen 0.5 PSI Conventional Hydrogen 15 PSI Conventional Hydrogen 30 PSI Direct Hydrogen 40 - 60 PSI
Cylindrical Rotor Cylindrical Rotor Cylindrical Rotor
52
I2R (PU CMR)
I22t = K
0.40
60
0.20
20
0.15
15
0.15
12
0.10
3
52
Rotor Earth Fault Protection (1)
Field circuit is an isolated DC system. Insulation failure at a single point : -
No fault current, therefore no danger Increase change of second fault occurring
Insulation failure at a second point : -
Shorts out part of field winding Heating (burning of conductor) Flux distortion causing violent vibration of rotor
Desirable to detect presence of first earth fault and give an alarm. 53
53
Rotor Earth Fault Protection (2) Potentiometer Method
Exciter
R
Required sensitivity approximately 5% exciter voltage. No auxiliary supply required. “Blind spot” - require manually operated push button to vary tapping point. 54
54
Rotor Earth Fault Protection (3) AC Injection Method
AC Auxiliary Supply R
Brushless Machines No access to rotor circuit Require special slip rings for measurement If slip rings not present, must use telemetering techniques (expensive) 55
55
Overload Protection (1) high load current
heating of stator and rotor
insulation failure Governor Setting Should prevent serious overload automatically. Generator may lost speed if required load not be met by other sources. High reactive power flow can give high stator current - not affected by governor settings.
56
56
Overload Protection (2) Direct Temperature Measuring Devices Resistance temperature detectors (RTDs), thermocouples etc., embedded in windings. Provide alarm and/or trip via auxiliary relays. Overcurrent Protection Set just above maximum load current. Intended for short circuit protection. Thermal Replica Relays Current operated. May have ambient temperature compensation.
57
57
Generator Back-Up Protection (1) Overcurrent Protection Typical use : Very or extremely inverse for LV machines Normal inverse for HV machines Must consider generator voltage decrement characteristic for close-in faults. With reliable AVR system, “conventional” overcurrent relays may be used. Otherwise, voltage controlled / restrained relays are required.
10 x FL
with AVR Full Load
no AVR Cycles
58
58
Generator Back-Up Protection (2) Overcurrent Protection Voltage Restrained Operating characteristic is continuously varied depending on measured volts. Alternatively, use impedance relay. Voltage Controlled Relay switches between fault characteristic and load characteristic depending on measured volts.
F 59
59
Voltage Controlled Overcurrent Protection
Fault Characteristic
I 60
Current Pick - up
t
Overload Characteristic
Is
Vs Voltage 60
Voltage Restrained Overcurrent Protection
Equivalent to impedance devices
Current Pick-up
More suited for indirect connected generators
I> KI>
VS2 VS1 Voltage 61
61
10 O/L CHARAC 1.0
FAULT CHARAC LARGEST OUTGOING FEEDER
t se c
GENERATO R DECREMEN T CURVE
0.1
0.01 100 62
240 600 1000
3000
10,000
6.6kV 5MVA 115% XS 500/5 200/5
AMPS 62
Impedance Relay jx
R
RELAY CHARACTERISTI C MZTU
Set to operate at 70% rated load impedance when voltage drops to zero, current required to operate relay is 10% rated current. Built-in timer for co-ordination purposes. 63
63
Under & Over Frequency Conditions (1)
Over Frequency Results from generator over speed caused by sudden loss of load. In isolated generators may be due to failure of speed governing system. Over speed protection may be provided by mechanical means. Desirable to have over frequency relay with more sensitive settings.
64
64
Under & Over Frequency Conditions (2) Under Frequency Results from loss of synchronous speed due to excessive overload. In isolated generators may be due to failure of speed governing system. Under frequency condition gives rise to: Overfluxing of stator core at nominal volts Plant drives operating at lower speeds - can affect generator output Mechanical resonant condition in turbines
Desirable to supply an under frequency relay. Protection may be arranged to initiate load shedding as a first step.
65
65
Under & Over Voltage Conditions (1)
Protection Under & over voltage protection usually provided as part of excitation system. For most applications an additional high set over voltage relay is sufficient. Time delayed under and over voltage protection may be provided.
66
66
Under & Over Voltage Conditions (2) Over Voltage Results from generator over speed caused by sudden loss of load. May be due to failure of the voltage regulator. An over voltage condition : Causes overfluxing at nominal frequency Endangers integrity of insulation
Under Voltage No danger to generator. May cause stalling of motors. Prolonged under voltage indicates abnormal conditions.
67
67
Other Protection Considerations
68
68
Pole Slipping Protection Simplified diagram of a generator
Stator
Rotor
X E G
E S
ZG9356 69
69
Pole Slipping Detection
E E = 2.8 (max) G S E E = 1.2 G S E E =1 G S
X R
E E = 0.8 G S E E = 0.19 (min) G S
MIS9357 70
70
Pole Slipping Protection Also referred to as Out of Step protection Techniques depends on machine/system requirements Utility practices
May be required to detect the first pole slip Could be time delayed to detect pole slips resulting in instability
71
71
72
72
73
73
74
74
75
75
Pole Slipping Protection - 78
Conventional lenticular (lens) characteristic 2 Zones defined by reactance line Zone 1 - pole slip in the generator Zone 2 - pole slip in the power system Separate counters per zone (1-20)
Setting to detect pole slipping when : Generating Motoring Both (Pumped storage generator)
76
76
Pole Slipping Protection - 78
Pole slip when generating Impedance position on RHS of lens characteristic Impedance crosses lens on RHS Impedance spends >T1 (15ms) in RHS of lens Impedance spends >T2 (15ms) in LHS of lens Impedance leaves lens on LHS Zone 1 and 2 counter is incremented if in Z1 Zone 2 counter is incremented if in Z2 Trip when zone counter value exceeded
Pole slipping when motoring is the opposite
77
77
Overfluxing Often applied to :Generator transformers Grid transformers
Flux Ø ∝ V / f Caused by either :Increase in voltage Reduction in frequency Combination of both
Usually only a problem :during run-up or shut down can be caused by loss of load / load shedding
78
78
Transformer Magnetising Characteristic Twice Normal Flux
Normal Flux
Normal No Load Current 79
No Load Current at Twice Normal Flux 79
Magnetising Current with Transformer Overfluxed
ZG0780C 80
80
Overfluxing Effects of overfluxing :Increase in magnetising current Increase in winding temperature Increase in noise and vibration Overheating of laminations and metal parts (caused by stray flux)
Protective relay responds to V/f ratio Co-ordinate with plant withstand characteristics Typical generator application Stage 1 - lower A.V.R. Stage 2 - Trip field
81
81
Over-Fluxing Relay
Ex
G
VT
AVR
82
RL
82
Low Forward Power Interlocking
Urgent Trip Trip Directly to Circuit Breaker and Initiate shut down Risk of overspeed Examples :Generator Differential stator ground fault negative phase sequence.
83
83
Low Forward Power Interlocking Non-Urgent Trip Trip governor Use low forward power interlocking to determine when main Circuit Breaker is tripped Reduced risk of overspeed, and consequential damage to the machine Examples :Over voltage Over load Loss of synchronism Field failure
84
84
Unintentional Energisation at Standstill Scheme
Typical Approach 50 &
27 & VTS
Trip
tPU tDO
Overcurrent element detects breaker flashover or starting current (as motor) Three phase undervoltage detection MiCOM-P340-85 85
VTS function checks no VT anomalies 85
VT Fuse Failure Protection
Typical Voltage Balance scheme (60) Used for blocking purposes and for alarms Line voltage comparison done independently Fast Operating time May provide three outputs – Comparison VT fuse failure – Protection VT fuse failure – Protection block ZG7965D 86
86
Synchronising Relays Often applied to :Synchronising of Generators Transmission line auto-reclose schemes
Synchronising of Generators Check voltage magnitudes Check slip frequency Check phase angle difference
Synchroscope Speed of rotation depends on slip frequency If frequencies matched, phase angle displacement indicated Does not indicate voltage magnitude
87
87
Voltage Checking & Comparators Voltage comparators often used in Transmission line autoreclose schemes :-
-
Live Line / Dead Bus
-
Dead Line / Live Bus
-
Dead Line / Dead Bus
Voltage monitors :-
88
-
Undervoltage monitor (e.g. Transmission Line)
-
Differential voltage monitor (e.g. Generator)
88
Auto-Synchronising Relays
Applied to Synchronising of Generators to control the machine Controls :Filed current to adjust voltage magnitude Governor to adjust slip frequency Governor to correct constant phase displacement
89
89
Typical Schemes
90
90
Tripping Modes
91
Class A
HV breaker , Field breaker, Turbine For faults in the generator zone
Class B
Turbine Trip HV Breaker & Field Breaker interlocked with low forward power relay
Class C
HV breaker
91
Protection Package for Diesel Generator Connected Directly and Operating in Parallel with a Supply Authority Infeed
87 G
64 R 32
64 R
92
51 V
32
Reverse Power MWTU01
64R
Rotor Earth Fault MRSU01
64S
Stator Earth Fault MCSU01
51V
Voltage Dependent Overcurrent MCVG31
87G
Generator Differential MFAC34
92
Overall Protection of Directly Connected Generator Installation
Stator Earth Fault
64S
Rotor Earth Fault
64R
Differential Protection
87
51V Voltage Controlled O/C 46
Negative Phase Sequence
32 Reverse Power 40
Field Failure
81 Under / Over Frequency 27/59 93
Under / Over Voltage 93
Overall Protection of Generator Installation (1) Generator Feeder Protn. Overcurrent Voltage Restraint
51 V
Restricted E/F
Buchholz Winding Temp.
Reverse Power
32
Field Failure
40
Generator Differential Rotor E/F
64R
Overall Gen/Trans Diffl Protn.
94
87
Prime Mover Protection Negative Phase Sequence
Stator E/F
46
64S
94
Overall Protection of Generator Installation (2) Generator Feeder Protection O/C
Circuit Breaker Fail
Busbar Protection
Restricted E/F
Buchholz Winding Temperature
O/C + E/F
Buchholz
O/C
V.T.s Transformer Overfluxing Permissive (Low Power) Interlock
Standby E/F Restricted E/F
Pole Slipping
Field Failure Generator Differential
Unit Transformer Differential Protn.
Overall Generator Transformer Differential Protn.
Rotor E/F
Low Steam Pressure, Loss of Vacuum Loss of Lubricating Oil Loss of Boiler Water Governor Failure Vibration, Rotor Distortion Negative Phase Sequence
Stator E/F Protection
95
95
Embedded Generation
96
96
Embedded Generation
USED TO PROVIDE:
Emergency Power Upon Loss Of Main Supply Operate In Parallel To Reduce Site Demand Excess Generation May Be Exported Or Sold
97
97
Co-generation/Embedded Machines
AR?
PES system
Islanded load fed unearthed
MiCOM-P340-98 98
98
Islanded Operation Must Be Avoided To Ensure: Unearthed Operation Of Main Supply Network Automatic Reclosure Of CB Will Not Result In Connecting Unsynchronised Supplies Staff Cannot Attempt Unsynchronised Manual Closure Of An Open CB Faults On Electricity Supply Companies Network Being Undetected Due To Low Fault Supplying Capability Of Embedded Generator Voltage & Frequency Supplied To Customers Remains Within Statutory Limits
99
99
PROTECTION Under/Over Voltage & Under/Over Frequency Keep Voltage & Frequency Within Statutory Limits Directional Power / Overcurrent Used When Generator Does Not Export Power During Normal Operation
100
100
PROTECTION Loss Of Mains Used Where Generating Capacity Is Closely Matched To Load Or Where Normal Operation Requires The Export Of Power Two Types Are Used: Rate Of Change Of Frequency - Sensitive - Possible Nuisence Tripping Voltage Vector Shift - Requires Higher Change In load - More Stable 101
101
Protection
Under/Over Voltage & Under/Over Frequency Keep Voltage & Frequency Within Statutory Limits Directional Power / Overcurrent Used When Generator Does Not Export Power During Normal Operation
102
102
Protection Loss Of Mains Used Where Generating Capacity Is Closely Matched To Load Or Where Normal Operation Requires The Export Of Power Two Types Are Used: Rate Of Change Of Frequency
-
Sensitive Possible Nuisance Tripping
Voltage Vector Shift
103
Requires Higher Change In load More Stable 103
MiCOM P341 Applications G59 Protection Equipment Voltage Vector Shift Protection An expression for a sinusoidal mains voltage waveform is generally given by the following: V = Vp sin (wt) or V = Vp sin θ (t) where
θ(t) = wt = 2πft
If the frequency is changing at constant rate Rf from a frequency fo then the variation in the angle θ(t) is given by: θ(t) = 2π∫f dt, (F = Fo + Rf t) which gives
θ(t) = 2π{fo t + t Rf t/2}
and
V = V sin {2π(fo + t Rf/2)t}
Hence the angle change ∆θ(t) after time t is given by: ∆θ(t) = πRf t2
104
104
MiCOM P341 Applications G59 Protection Equipment Single phase line diagram showing generator parameters
jX
R E
IL VT
- MiCOM P341 Generator Protection 105
105
MiCOM P341 Applications G59 Protection Equipment Vector Diagram Representing Steady State Condition
E
IL
VT
IL X I LR
- MiCOM P341 Generator Protection 106
106
MiCOM P341 Applications G59 Protection Equipment Transient voltage vector change θ due to change in load current ∆IL
E VT θ
IL
VT
∆IL
ILX ILR
∆ILX”
- MiCOM P341 Generator Protection 107
107
MiCOM P341 Applications G59 Protection Equipment
df/dt The rate of change of speed, or frequency, following a power disturbance can be approximated by:
df/dt = ∆P.f 2GH where
P = Change in power output between synchronised and islanded operation f = Rated frequency G = Machine rate MVA H = Inertia constant
108
108
MiCOM P341 Applications G59 Protection Equipment P341 df/dt calculation
df/dt =
F n - f n - 3 cycle 3 cycle
Two consecutive calculations must give a result above the setting threshold before a trip decision can be initiated
- MiCOM P341 Generator Protection 109
109
Voltage and Frequency Relay
fi-3
fi-2
fi-1
fi
fi+1 (df/dt)i-2 =
(df/dt)i-1 =
f(i-2) - f(i-3) t(i-2) - t(i-3)
f(i-1) - f(i-2) t(i-1) - t(i-2)
(df/dt)i =
The instantaneous ROCOF is measured every cycle based upon frequencies being insensitive to vector shift, phase jumps and harmonics
110
f(i) - f(i-1) t(i) - t(i-1)
(df/dt)i+1 =
f(i+1) - f(i) t(i+1) - t(i)
110
Voltage and Frequency Relay
1
1 2
fi-3 df/dt)i-3
df/dt VALIDAT NB = 2 Threshold : df/dt [81R]df/dt1 = 0,5 Hzs 111
3
fi-2
fi-1
fi
df/dt)i-2
df/dt)i-1
df/dt)i
df/dt =
df/dt)i-3 + df/dt)i-2 + df/dt)i-1 3
df/dt =
df/dt)i-2 + df/dt)i-1 + df/dt)i 3
Average Values
df/dt CYCLE BN = 3
3 2
If both measured values are > than the threshold, the protectionelement will function. 111
Voltage and Frequency Relay
21
1
fi-3 df/dt)i-3
31 2
31 2
fi-2
fi-1
df/dt)i-2
df/dt)i-1
fi
df/dt =
df/dt = df/dt VALIDAT NB = 4
df/dt = Threshold : df/dt
112
df/dt =
df/dt)i
3
fi+1 df/dt)i+1
fi+2 df/dt)i+2
df/dt)i-3 + df/dt)i-2 + df/dt)i-1 3
df/dt)i-2 + df/dt)i-1 + df/dt)i 3
df/dt)i-1 + df/dt)i+ df/dt)i+1 3
Average Values
df/dt CYCLE NB = 3
[81R]df/dt1 = 0,5 Hzs
32
df/dt)i + df/dt)i+1+ df/dt)i+2 3 112
Voltage and Frequency Relay
Frequency supervised rate of change of frequency F EQU.A= Load SHED.
AND df/dt aver.
f
50 Hz 49 Hz Slow decay.
48.6 Hz
Rapid decay. t 113
113
Voltage and Frequency Relay
The rate of change of frequency is supervised by a value of frequency. The percentage of load to be shed to stop the frequency decay varies with the df/dt. This could be used to make the load shedding scheme faster to severe system conditions and accelerate the recovery process by shedding more load than would have been done for slow decay at same frequency.
Frequency supervised rate of change of frequency f+df/dt
114
114
MiCOM P341 Applications G59 Protection Equipment df/dt+t: Time Delayed ROCOF
t Start
Pick up cycles
Trip f
Time delay
df/dt Setting 115
115
Auto-Reclosing On Transmission Systems
Fault Shunts (1) Z1
F1
E
ZF N1
ZF
= Fault shunt = Combined Impedance of -ve and zero sequence network impedances for particular fault.
2
> Auto-Reclosing and System Stability – January 2004
2
Fault Shunts (2)
Ø/E
ZF = Z2 + Z0
Ø/Ø
ZF = Z2
Ø/Ø/E
ZF = Z2 . Z0 Z2 + Z0
3
3Ø
ZF = 0 (short circuit)
Healthy
ZF = ∝ (open circuit)
> Auto-Reclosing and System Stability – January 2004
3
Use Of Power Angle Curves
4
> Auto-Reclosing and System Stability – January 2004
4
Power Angle Curves
Power Flow =
E1 E2 sin δ Z
Power
Load Angle (δ) 5
> Auto-Reclosing and System Stability – January 2004
5
Comparative Power Angle Curves
Power
3Ø Healthy 2Ø Healthy 1Ø Tripped
Ø/E Fault
Ø/Ø/E Fault 3Ø Fault 3Ø Tripped
Load Angle (δ) 6
> Auto-Reclosing and System Stability – January 2004
6
Steady State Y
X
Power
Normal Healthy Operation
P0
A
Phase Angle Difference
δ0 7
> Auto-Reclosing and System Stability – January 2004
7
During Fault Y
X
Power
Normal
P0
A Ø/Ø/E Fault
P0 - P1 P1
8
C B δ0
δ1
> Auto-Reclosing and System Stability – January 2004
Phase Difference 8
Increased Power Level Y
X
Power Normal
P2 ' P0 P2
F Faulted Feeder Disconnected
A E D
Ø/Ø/E Fault
B
C
δ0 δ1 9
Phase Difference
δ2
> Auto-Reclosing and System Stability – January 2004
9
Damping Normal
Power
F
P0
Faulted Feeder Disconnected
E
Ø/Ø/E Fault
Phase Difference
Power transfer and phase difference oscillates around ‘E’. Damping causes system to settle at E in stable condition:P0 transfer. 10
> Auto-Reclosing and System Stability – January 2004
10
Equal Area Criteria Power Normal
P0 '
E A
G
D
B
Ø/Ø/E Fault
C
δ2
11
Faulted Feeder Disconnected
Phase Angle Difference
G
=
Equal areas when G lies on P0'
P0'
=
Max. power transmitted for transient stability.
> Auto-Reclosing and System Stability – January 2004
11
Transient Fault – Successful A/R Normal
Power
G
P0''
H
A D
F E
BC
Successful 3Ø A/R at ‘E’. H
Faulted Feeder Disconnected
Ø/Ø/E Fault
Phase Angle Difference
= Equal area when H lies on P0''
P0'' = Max. power transmitted for transient stability with 3Ø A/R. 12
> Auto-Reclosing and System Stability – January 2004
12
3ph or 1ph A/R
13
> Auto-Reclosing and System Stability – January 2004
13
Single Feeder – 3ph A/R Y
X Power Normal
P3Ø(A/R) Ø/E Fault Line Open 3Ø
δ P3Ø(A/R) 14
Phase Angle Difference
= Power transfer limit for stability following successful high speed 3Ø auto-reclose.
> Auto-Reclosing and System Stability – January 2004
14
High Speed 1Ø A/R Single Interconnector Normal
Power
P1Ø(A/R) 1Ø Open
Ø/E Fault
δ P1Ø(A/R) 15
Phase Angle Difference
= Power transfer limit for stability following successful high speed 1Ø auto-reclose.
> Auto-Reclosing and System Stability – January 2004
15
1Ø Auto-Reclose Advantages (over 3Ø A/R)
16
1.
Higher power transfer limit.
2.
Reduced power swing amplitude.
3.
Reduced switching overvoltages due to reclosing.
4.
Reduced shock to generators. Sudden changes in mechanical output are less
> Auto-Reclosing and System Stability – January 2004
16
Choice of Scheme
17
> Auto-Reclosing and System Stability – January 2004
17
Choice of Scheme (1)
High Speed Auto-Reclose 1.
Single transmission links.
2.
3Ø A/R.
3.
1Ø A/R for E/Fs Lockout for multiphase faults.
4.
1Ø A/R for E/Fs 3Ø A/R for multiphase faults.
18
> Auto-Reclosing and System Stability – January 2004
18
Choice of Scheme (2) Delayed 3Ø Auto-Reclose 1.
Densely interconnected systems. Ð Minimal power transfer level reduction during dead time
2.
Power swings due to fault and tripping allowed to decay Ð Less shock to system than with speed A/R
19
> Auto-Reclosing and System Stability – January 2004
high
19
1Ø Auto-Reclose Factors Requiring Consideration 1.
Separate control of circuit breaker poles.
2.
Protection must provide phase selection.
3.
Mutual coupling can prolong arcing and require de-ionising time.
4.
Unbalance during dead time (i) Interference with communications (ii) Parallel feeder protection may maloperate
5.
20
More complex and expensive than 3Ø A/R
> Auto-Reclosing and System Stability – January 2004
20
High Speed Auto-Reclose (H.S.A.R.) (1)
Protection High speed < 2 cycles
Fast clearance at each line end.
Phase comparison Distance schemes with signalling Distance scheme with zone 1 extension Direct intertrip
Phase selection required for 1Ø A/R
21
> Auto-Reclosing and System Stability – January 2004
21
High Speed Auto-Reclose (H.S.A.R.) (2)
Dead Time (short as possible) Circuit breaker minimum ‘open - close’ time ∼ 200 - 300 msecs.
Same dead time at each line end.
De-ionising time 1Ø A/R longer → special steps
22
> Auto-Reclosing and System Stability – January 2004
22
Delayed Auto-Reclosing (D.A.R.) (1) Protection High speed not critical for system stability ↓ desirable to limit fault damage ↓ improves probability of successful A/R
Dead Time Allow for power swings and rotor oscillations to die down. Different settings for opposite feeder ends. Typically 5 to 60 secs. 23
> Auto-Reclosing and System Stability – January 2004
23
Delayed Auto-Reclosing (D.A.R.) (2)
Reclaim Time Allow c.b. capacity to recover to full interrupting value.
Number of Shots 1 (invariably)
24
> Auto-Reclosing and System Stability – January 2004
24
Check Synchronizing
25
> Auto-Reclosing and System Stability – January 2004
25
Synchronism Check On interconnected systems - little chance of complete loss of synchronism after fault and disconnection of a single feeder. Phase angle difference may change to cause unacceptable shock to system when line ends are re-connected.
VB
VL
VL = 0 VB = live ∴ Dead Line Charge
26
> Auto-Reclosing and System Stability – January 2004
26
Check Synchronising
Used when system is non radial. Check synch relay usually checks 3 things:
27
1)
Phase angle difference
2)
Voltage
3)
Frequency difference
> Auto-Reclosing and System Stability – January 2004
27
Current Transformers
Current Transformer Function
X Reduce power system current to lower value for measurement. X Insulate secondary circuits from the primary. X Permit the use of standard current ratings for secondary equipment.
REMEMBER : The relay performance DEPENDS on the C.T which drives it !
3
> Current Transformers – January 2004
3
Instrument Transformer Standards IEC
IEC 185:1987
CTs
IEC 44-6:1992
CTs
IEC 186:1987
VTs
BS 7625
VTs
BS 7626
CTs
BS 7628
CT+VT
BS 3938:1973
CTs
BS 3941:1975
VTs
AMERICAN
ANSI C51.13.1978
CTs and VTs
CANADIAN
CSA CAN3-C13-M83
CTs and VTs
AUSTRALIAN
AS 1675-1986
CTs
EUROPEAN
BRITISH
4
> Current Transformers – January 2004
4
Polarity
Is P2
P1 Ip
S1
S2
Inst. Current directions :P1 Î P2 S1 Î S2 Externally 5
> Current Transformers – January 2004
5
Flick Test
P1 Is
Ip
FWD kick on application,
S1 +
REV kick on removal of test lead.
-
Battery (6V) + to P1 AVO +ve lead to S1
V
S2
P2
6
> Current Transformers – January 2004
6
Basic Theory
7
> Current Transformers – January 2004
7
Basic Theory (1) IS IP
R
1 Primary Turn N Secondary Turns
For an ideal transformer :PRIMARY AMPERE TURNS = SECONDARY AMPERE TURNS ⇒ IP = N x IS
8
> Current Transformers – January 2004
8
Basic Theory (2) IS IP
ES
R
For IS to flow through R there must be some potential ES = the E.M.F. ES = IS x R ES is produced by an alternating flux in the core. ES ∝ dØ dt 9
> Current Transformers – January 2004
9
Basic Theory (3) NP IP NS IS
EK ZCT
ZB
VO/P 10
> Current Transformers – January 2004
=
ISZB = EK - ISZCT 10
Basic Formulae
Circuit Voltage Required : ES = IS (ZB + ZCT + ZL) Volts where :IS
=
Secondary Current of C.T. (Amperes)
ZB
=
Connected External Burden (Ohms)
ZCT
=
C.T Winding Impedance (Ohms)
ZL
=
Lead Loop Resistance (Ohms)
Require EK > ES
11
> Current Transformers – January 2004
11
Low Reactance Design
With evenly distributed winding the leakage reactance is very low and usually ignored. Thus ZCT ~ RCT
12
> Current Transformers – January 2004
12
Exciting Voltage (VS)
Knee-Point Voltage Definition
+10% Vk Vk +50% Iek
Iek Exciting Current (Ie) 13
> Current Transformers – January 2004
13
C.T. Equivalent Circuit Ip
ZCT Is
P1 Ip/N
Ie
S1 N
14
Ze
Vt
Es
Ip = Primary rating of C.T.
Ie
= Secondary excitation current
N
Is
= Secondary current
= C.T. ratio
Zb = Burden of relays in ohms
Es = Secondary excitation voltage
(r+jx) ZCT = C.T. secondary winding impedance in ohms (r+jx) Ze = Secondary excitation impedance in ohms (r+jx)
Vt = Secondary terminal voltage across the C.T. terminals
> Current Transformers – January 2004
Zb
14
Phasor Diagram Φ
Ip/N Ie Ie
Is Es
15
Ep
Im Ic
Ep = Es =
Primary voltage Secondary voltage
Im = Ie =
Magnetising current Excitation current
Φ = Ic =
Flux Iron losses (hysteresis & eddy currents)
Ip = Is =
Primary current Secondary current
> Current Transformers – January 2004
15
Saturation
16
> Current Transformers – January 2004
16
Steady State Saturation (1)
E= 100V
100A
100A
1A
1A 100/1
E
100/1
1 ohm
E
100 ohm
E= 1V
100A
1A
1A 100/1
17
E=?
100A E
10 ohm
E= 10V
> Current Transformers – January 2004
100/1
E
1000 ohm
17
Transient Saturation v = VM sin (wt + σ) L1
R1 Z1
i1
v = VM sin (wt + σ) i1 = +
VM V sin (wt + σ - ∅ ) = M sin (σ - ∅ ) . e Z1 Z1
= + Ιˆ1 sin (wt + σ - ∅ ) - Ιˆ1 sin (σ - ∅ ) . e =
18
STEADY STATE
> Current Transformers – January 2004
+
-R1t / L1
-R1t / L1
TRANSIENT
where : -
Z1 =
R12 + w 2L12
∅ = tan-1
wL1 R1
V Ιˆ1 = M Z1
18
Transient Saturation : Resistive Burden
Required Flux ØSAT
FLUX Actual Flux Mag Current
0
Primary Current Secondary Current CURRENT 0
19
10
20 30
40 50
60 70
> Current Transformers – January 2004
80
M
19
CT Types
20
> Current Transformers – January 2004
20
Current Transformer Function
Two basic groups of C.T. X
Measurement C.T.s
Limits well defined X
Protection C.T.s
Operation over wide range of currents Note : They have DIFFERENT characteristics
21
> Current Transformers – January 2004
21
Measuring C.T.s Measuring C.T.s X Require good accuracy up to approx 120% rated current. X Require low saturation level to protect instruments, thus use nickel iron alloy core with low exciting current and knee point at low flux density.
B Protection C.T.
Protection C.T.s X Accuracy not as important as above. X Require accuracy up to many times rated current, thus use grain orientated silicon steel with high saturation flux density. 22
> Current Transformers – January 2004
Measuring C.T.
H 22
Current Transformer Ratings
23
> Current Transformers – January 2004
23
Current Transformer Ratings (1) Rated Burden X Value of burden upon which accuracy claims are based X Usually expressed in VA X Preferred values :2.5, 5, 7.5, 10, 15, 30 VA
Continuous Rated Current X Usually rated primary current
Short Time Rated Current X Usually specified for 0.5, 1, 2 or 3 secs X No harmful effects X Usually specified with the secondary shorted
Rated Secondary Current X Commonly 1, 2 or 5 Amps 24
> Current Transformers – January 2004
24
Current Transformer Ratings (2) Rated Dynamic Current Ratio of :IPEAK : IRATED (IPEAK = Maximum current C.T. can withstand without suffering any damage). Accuracy Limit Factor - A.L.F. (or Saturation Factor) Ratio of :IPRIMARY : IRATED up to which the C.T. rated accuracy is maintained. e.g. 200 / 1A C.T. with an A.L.F. = 5 will maintain its accuracy for IPRIMARY < 5 x 200 = 1000 Amps 25
> Current Transformers – January 2004
25
Choice of Ratio Clearly, the primary rating IP ≥ normal current in the circuit if thermal (continuous) rating is not to be exceeded. Secondary rating is usually 1 or 5 Amps (0.5 and 2 Amp are also used). If secondary wiring route length is greater than 30 metres - 1 Amp secondaries are preferable. A practical maximum ratio is 3000 / 1. If larger primary ratings are required (e.g. for large generators), can use 20 Amp secondary together with interposing C.T. e.g. 5000 / 20 - 20 / 1 26
> Current Transformers – January 2004
26
Current Transformer Designation
Class “P” Specified in terms of :i) Rated burden ii) Class (5P or 10P) iii) Accuracy limit factor (A.L.F.) Example :15 VA 10P 20 To convert VA and A.L.F. into useful volts Vuseful ≈ VA x ALF IN
27
> Current Transformers – January 2004
27
BS 3938 Classes :-
5P, 10P. ‘X’
Designation (Classes 5P, 10P) (Rated VA)
(Class)
(ALF)
Multiple of rated current (IN) up to which declared accuracy will be maintained with rated burden connected. 5P or 10P. Value of burden in VA on which accuracy claims are based. (Preferred values :- 2.5, 5, 7.5, 10, 15, 30 VA) ZB = rated burden in ohms = Rated VA IN2 28
> Current Transformers – January 2004
28
Interposing CT
29
> Current Transformers – January 2004
29
Interposing CT
LINE CT
NP
NS
ZB
ZCT
Burden presented to line CT = ZCT + ZB x NP2 NS2 30
> Current Transformers – January 2004
30
NEG.
5A
1A
0.5Ω
R 500/5
0.1Ω
1VA @ 1A ≡ 1.0Ω
0.4Ω
‘Seen’ by main ct :- 0.1 + (1)2 (2 x 0.5 + 0.4 + 1) = 0.196Ω (5) Burden on main ct :- I2R = 25 x 0.196 = 4.9VA Burden on a main ct of required ratio :0.5Ω
R 500/1
1.0Ω
Total connected burden = 2 x 0.5 + 1 = 2Ω Connected VA = I2R = 2 ∴ The I/P ct consumption was about 3VA. 31
> Current Transformers – January 2004
31
Current Transformer Designation
32
> Current Transformers – January 2004
32
Current Transformer Designation Class “X” Specified in terms of :-
33
i)
Rated Primary Current
ii)
Turns Ratio (max. error = 0.25%)
iii)
Knee Point Voltage
iv)
Mag Current (at specified voltage)
v)
Secondary Resistance (at 75°C)
> Current Transformers – January 2004
33
Choice of Current Transformer X Instantaneous Overcurrent Relays
Class P Specification A.L.F. = 5 usually sufficient For high settings (5 - 15 times C.T rating) A.L.F. = relay setting
X IDMT Overcurrent Relays
Generally Class 10P Class 5P where grading is critical Note : A.L.F. X V.A < 150 X Differential Protection
Class X Specification Protection relies on balanced C.T output 34
> Current Transformers – January 2004
34
Selection Example
35
> Current Transformers – January 2004
35
Burden on Current Transformers
1. Overcurrent : RCT + RL + Rr
2. Earth : RCT + 2RL + 2Rr
RCT
RCT
RCT RCT RL Rr
36
RCT
IF
RCT
IF RL
RL
Rr
> Current Transformers – January 2004
Rr
RL
Rr
RL Rr
IF
IF
RL
Rr
RL
Rr
RL
Rr
36
Overcurrent Relay VK Check Assume values :
If max C.T
= =
7226 A 1000 / 5 A 7.5 VA 10P 20
RCT = Rr = RL =
0.26 Ω 0.02 Ω 0.15 Ω
Check to see if VK is large enough : Required voltage = VS = IF (RCT + Rr + RL) = 7226 x 5 (0.26 + 0.02 + 0.15) = 36.13 x 0.43 = 15.54 Volts 1000 Current transformer VK approximates to :VK Ω VA x ALF + RCT x IN x ALF In = 7.5 x 20 + 0.26 x 5 x 20 = 56 Volts 5 VK > VS therefore C.T VK is adequate 37
> Current Transformers – January 2004
37
Earth Fault Relay VK Check Assume values : As per overcurrent. Note
For earth fault applications require to be able to pass 10 x relay setting.
Check to see if VK is large enough :
VK = 56 Volts
Total load connected = 2RL + RCT + 2Rr = 2 x 0.15 + 0.26 + 2 x 0.02 ∴
Maximum secondary current = 56 = 93.33A 0.6
Typical earth fault setting
= =
30% IN 1.5A
Therefore C.T can provide > 60 x setting C.T VK is adequate 38
> Current Transformers – January 2004
38
Voltage Transformers
39
> Current Transformers – January 2004
39
Voltage Transformers
40
X
Provides isolation from high voltages
X
Must operate in the linear region to prevent accuracy problems - Do not over specify VT
X
Must be capable of driving the burden, specified by relay manufacturer
X
Protection class VT will suffice
> Current Transformers – January 2004
40
Typical Working Points on a B-H Curve Flux Density ‘B’
Saturation
1.6
Tesla 1.0
0.5
Metering C.T.’s & Power Transformers
V.T.’s
Protection C.T. (at full load) ‘H’ 1000
2000
3000 Magnetising Force AT/m
41
> Current Transformers – January 2004
41
Types of Voltage Transformers
Two main basic types are available: X Electromagnetic VT`s
Similar to a power transformer May not be economical above 132kV X Capacitor VT`s (CVT)
Used at high voltages Main difference is that CVT has a capacitor divider on the front end.
42
> Current Transformers – January 2004
42
Electromagnetic Voltage Transformer
NP / NS = Kn
LP
RP IP
EP = ES
43
> Current Transformers – January 2004
IS
Ie LM
VP
LS
RS
IM
Re
VS
ZB
(burden)
IC
43
Basic Circuit of a Capacitor V.T.
C1 L T
VP C2
44
> Current Transformers – January 2004
ZB VC2
Vi
VS
44
VT Earthing
X Primary Earthing
Earth at neutral point Required for phase-ground measurement at relay X Secondary Earthing Required for safety Earth at neutral point When no neutral available - earth yellow phase (VERY COMMON) No relevance for protection operation
45
> Current Transformers – January 2004
45
VT Construction
X
5 Limb
Used when zero sequence measurement is required (primary must also be earthed)
X
Three Single Phase
Used when zero sequence measurement is required (primary must also be earthed)
X
3 Limb
Used where no zero sequence measurement is required
X
V Connected (Open Delta)
46
No yellow phase Cost effective Two phase-phase voltages No ground fault measurement
> Current Transformers – January 2004
46
VT Connections
Broken Delta A
B
da
a
47
C
N
V Connected a
b
c
dn
b
> Current Transformers – January 2004
c n
a
b
c
47
VT Construction - Residual
X Used to detect earthfault X Useful where current operated protection cannot be used X Connect all secondary windings in series X Sometimes referred to as `Broken Delta` X Residual Voltage is 3 times zero sequence voltage X VT must be 5 Limb or 3 single phase units X Primary winding must be earthed
48
> Current Transformers – January 2004
48
Voltage Factors Vf
X Vf is the upper limit of operating voltage.
49
X
Important for correct relay operation.
X
Earthfaults cause displacement of system neutral, particularly in the case of unearthed or impedance earthed systems.
> Current Transformers – January 2004
49
Protection of VT’s
50
X
H.R.C. Fuses on primary side
X
Fuses may not have sufficient interrupting capability
X
Use MCB
> Current Transformers – January 2004
50
Motor Protection
Introduction
z z
Many different applications Different motor characteristics
Difficult to standardise protection Protection applied ranges from FUSES
to
RELAYS
Introduction
COST & EXTENT OF PROTECTION
=
POTENTIAL HAZARDS
SIZE OF MOTOR, TYPE & IMPORTANCE OF THE LOAD
Motor Protection SYSTEM Voltage Dips Voltage Unbalance Loss of supply Faults
MOTOR CIRCUIT Insulation failure Open circuits Short circuits Overheating
LOAD Overload Locked rotor Coupling faults Bearing faults
Motor Protection Application Voltage
Rating
Switching Device
Protection
< 600V
< 11kW
Contactor
(i) Fuses (ii) Fuses + direct acting thermal O/L + U/V releases
< 600V
11 - 300kW
Contactor
3.3kV
100kW - 1.5MW
Contactor
6.6kV
1MW - 3MW
Contactor
6.6kV
> 1MW
Circuit Breaker
11kV
> 1MW
Circuit Breaker
Fuses + Electronic O/L + Time delayed E/F Options :- Stalling Undercurrent As above + Instantaneous O/C + Differential
Introduction Protection must be able to :Operate for abnormal conditions Protection must not :Affect normal motor operation Considerations :- Starting current - Starting time - Full load current - Stall withstand time (hot & cold) - Thermal withstand
Mechanical Overload
Mechanical Overload OVERLOAD
HEATING
INSULATION DETERIORATION
OVERLOAD PROTECTION
FUSES
THERMAL REPLICA
Motor Heating MOTOR TEMPERATURE T = Tmax (1 - e-t/τ) TMAX
Time Rate of rise depend on motor thermal time constant τ
or as temp rise ∝ (current)2 T = KI2max (1 - e-t/τ)
Motor Heating I2 I22
T2 T1
I12 IR2
TMAX
t2 t1
Time
Time
t1
Thermal Withstand
t2
IR I1 I2
Current
Motor Cooling COOLING EQUATION : I2m' = I2m e-t/τr Current2 Im
Im' 0
t
Time
After time ‘t’ equivalent motor current is reduced from Im to Im’.
Motor Heating Temp
Trip Tmax T
Cooling time constant τr
t1
t1 = Motor restart not possible t2 = Motor restart possible
t2
Time
Emergency Restart
z
In certain applications, such as mine exhaust and ship pumps, a machine restart is required knowing that it will result in reduced life or even permanent damage. – All start up restrictions are inhibited – Thermal state limited to 90%
Start / Stall Protection
Stalling Protection Required for :Stalling on start-up (locked rotor) Stalling during running With normal 3Ø supply :ISTALL = ILOCKED ROTOR ~ ISTART ∴ Cannot distinguish between ‘STALL’ and ‘START’ by current alone. Most cases :-
tSTART < tSTALL WITHSTAND
Sometimes :-
tSTART > tSTALL WITHSTAND
Locked Rotor Protection Start Time < Stall Withstand Time
Where Starting Time is less than Stall Withstand Time : z Use thermal protection characteristic z Use dedicated locked rotor protection
Locked Rotor Protection :- tSTART < tSTALL Thermal relay also provides protection against 3Ø stall. t
Thermal Cold Curve Cold Stall Withstand
tSL tST Start
IFL
Thermal Hot Curve IST ISL
I
Dedicated Locked Rotor Protection
Definite Time Thermal Cold tSL tS
Cold Stall Withstand
tSTART
O/C (IS)
(tS) T
Trip
tSL > tS > tSTART IS
IST ISL
Hot Stall Protection Tstart < Tstall Use of motor start contact to distinguish between starting and hot stall Time
Hot Stall Withstand start time
tSL (HOT) Full load Current
Io/c
Current
Locked Rotor Protection Start Time > Cold Stall Withstand z z
z
Motors with high inertia loads may often take longer to start than the stall withstand time However, the rotor is not being damaged because, as the rotor turns the “skin effect” reduces, allowing the current to occupy more of the rotor winding This reduces the heat generated and dissipates the existing heat over a greater area z Detect start using tachometer input
Stall Protection Tstart > Tstall Use of tachoswitch and definite time overcurrent relay. Time
Tacho opens at ∼ 10% speed TD < Tstall > Tacho opening
Start Time
Stall - Tstall
TD
Full load Current
Io/c
Current
Unbalanced Supply Protection
Operation on Supply Unbalance
Negative sequence impedance is much less than positive sequence impedance. Small unbalance = relatively large negative sequence current. Heating effect of negative sequence is greater than equivalent positive sequence current because they are HIGHER FREQUENCY.
Operation on Supply Unbalance At normal running speed POSITIVE SEQ IMP ≈ NEGATIVE SEQ IMP CURRENT
STARTING CURRENT NORMAL RUNNING
Negative sequence impedance is much less than positive sequence impedance. Small unbalance = relatively large negative sequence current. Heating effect of negative sequence is greater than equivalent positive sequence current because they are HIGHER FREQUENCY.
Equivalent Motor Current Heating from negative sequence current greater than positive sequence →
take this into account in thermal calculation
Ieq = (I12 + nI22)½ where : n = typically 6 →
small amount of I2 gives large increase in Ieq and hence calculated motor thermal state.
Loss of 1 Phase While Starting STAR A
Normal starting current VAN z With 1 phase open
C
B
B
ΙA =
C
Ι' A
3VAN VAB = = 2z 2z = 0.866 x Ι A
1 1 (Ι' A + aΙ'B ) = (1- a)Ι' A 3 3 1 Ι1 = Ι A 2 1 1 2 Ι 2 = (Ι' A + a Ι'B ) = (1- a2 )Ι' A 3 3 1 Ι2 = Ι A 2 Ι1 =
DELTA A
z
z z
Normal =
3VAB z
1 Phase open 3 = VAB x 2z = 0.866 x normal 1 winding carries twice the current in the other 2.
Single Phase Stalling Protection
z z z
Loss of phase on starting motor remains stationary Start Current = 0.866 normal start I Neg seq component = 0.5 normal start I – Clear condition using negative sequence element
Typical setting ~ 1/3 I2 i.e. 1/6 normal start current
Single Phasing While Running
Difficult to analyse in simple terms z Slip calculation complex z Additional I2 fed from parallel equipment Results in :z I2 causes high rotor losses. Heating considerably increased. z Motor output reduced. May stall depending on load. z Motor current increases.
Reverse Phase Sequence Starting
Protection required for lift motors, conveyors Instantaneous I2 unit Time delayed thermal trip Separate phase sequence detector for low load current machines
Undervoltage Protection
Undervoltage Considerations z z z z
Reduced torque Increased stator current Reduced speed Failure to run-up
Form of undervoltage condition :z Slight but prolonged (regulation) z Large transient dip (fault clearance) Undervoltage protection :z Disconnects motor from failed supply z Disconnects motor after dip long enough to prevent successful re-acceleration
Undervoltage Considerations z
U/V tripping should be delayed for essential motors so that they may be given a chance to re-accelerate following a short voltage dip (< 0.5s)
z
Delayed drop-out of fused contactor could be arranged by using a capacitor in parallel with the AC holding coil
Insulation Failure
Insulation Failure
Results of prolonged or cyclic overheating z Instantaneous Earth Fault Protection z Instantaneous Overcurrent Protection z Differential Protection on some large machines
Stator Earth Fault Protection Rstab 50
(A) Residually connected CT’s
M
50
M
Note:
(B) Core Balance (Toroidal)CT
* In (A) CT’s can also drive thermal protection * In (B) protection can be more sensitive and is stable
50 Short Circuit z z z
Due to the machine construction internal phase-phase faults are almost impossible Most phase-phase faults occur at the machine terminals or occasionally in the cabling Ideally the S/C protection should be set just above the max Istart (I>>=1.25Istart), however, there is an initial start current of up to 2.5Istart which rapidly reduces over 3 cycles – Increase I>> or delay tI>> in small increments according to start conditions – Use special I>> characteristic
Instantaneous Earth Fault or Neg. Seq. Tripping is not Permitted with Contactors
TRIP
TIME MPR FUSE M MPR ELEMENT
Ts
Is
Icont
CURRENT
Ts > Tfuse at Icont.
Differential Protection
High-Impedance Winding Differential Protection A
B
C
87 A
87 B
87 C
Note: Protection must be stable with starting current.
Self-Balance Winding Differential Protection A
87 A
B
87 B
C
87 C
Bearings
Bearing Failure
Electrical Interference Induced voltage Results in circulating currents May fuse the bearings Remember to take precautions - earthing Mechanical Failure Increased Friction Loss or Low Lubricant Heating
Use of RTDs
RTD sensors at known stator hotspots Absolute temperature measurements to bias the relay thermal characteristic Monitoring of motor / load bearing temperatures Ambient air temperature measurement
Synchronous Motors
Synchronous Machines z
OUT OF STEP PROTECTION Inadequate field or excessive load can cause the machine to fall out of step. This subjects the machine to overcurrent and pulsating torque leading to stalling >Field Current Method Detect AC Current Induced In Field Circuit. >Power Factor Method Detect Heavy Current At Low Power Factor.
Synchronous Machines
z
LOSS OF SUPPLY On Loss Of Supply Motor Should Be Disconnected If Supply Could Be Restored Automatically. Avoids Supply Being Restored Out Of Phase. >Overvoltage & Underfrequency >Underpower & Reverse Power
Busbar Protection Protection & Contrôle / Application 08/02 1 05/02/03
Rev. A JM, September 2004
1
Without Busbar Protection
F1
F2
Argues z z
08/02 2 05/02/03
There are fewer faults on busbars than on other parts of the power system. No risk of dislocation of system due to accidental operation of busbar protection. 2
Without Busbar Protection
F1
F2
Drawbacks z
08/02 3 05/02/03
Slow fault clearance. Busbar faults at F1 and F2 are cleared by remote time delayed protection on circuits feeding the faults: Time Delayed Overcurrent or Time Delayed Distance Protection 3
With Busbar Protection BUSBAR ZONE F1
z
08/02 4 05/02/03
Fast clearance by breakers at the busbars
4
With Busbar Protection BUSBAR ZONE F1
z
08/02 5 05/02/03
F2
Where busbars are sectionalised, Protection can limit the amount of system disruption for a busbar fault
5
With Busbar Protection 1/2 SS 1
SS 2
87BB
SS 3
87BB
21
08/02 6 05/02/03
21
6
With Busbar Protection 2/2 87BB 87BB
21
08/02 7 05/02/03
21
7
With No Busbar Protection 1/2
21
21
08/02 8 05/02/03
21
21
21
8
With No Busbar Protection 2/2
21
21
08/02 9 05/02/03
21
21
21
9
With Burbar protection 87BB 87BB
21
21
With No Burbar protection
21
21 08/02 1005/02/03
21
21
21 10
Busbar Faults Are Usually Permanent Causes of Busbar Faults : z
Falling debris
z
Insulation failures
z
Circuit breaker failures
z
Current transformer failures
z
Isolators switchs operated on load or outside their ratings
z
Safety earths left connected
Therefore : Circuit breakers should be tripped and locked out by busbar protection 08/02 1105/02/03
11
Busbar Protection must be : z
RELIABLE – Failure to trip could cause widespread damage to the substation
08/02 1205/02/03
z
STABLE – False tripping can cause widespread interruption of supplies to customers / possible power system instability
z
DISCRIMINATING – Should trip the minimum number of breakers to clear the fault
z
FAST – To limit damage and possible power system instability
12
Methods of Providing Busbar Protection z
Frame to Earth (Leakage) Protection >I
Insulation
z
Blocking Scheme Protection >I
z
08/02 1305/02/03
Differential Protection :
>I
>I
>I
>I
High Impedance Low Impedance
13
Frame Leakage Protection Protection & Contrôle / Application 08/02 1405/02/03
Rev. A JM, September 2004
14
Frame Leakage Busbar Protection
>I
Insulation
08/02 1505/02/03
15
Frame Leakage Busbar Protection
>I
08/02 1605/02/03
16
Frame Leakage Busbar Protection
>I
08/02 1705/02/03
17
Frame Leakage Busbar Protection
>I
08/02 1805/02/03
>I
18
Frame Leakage Busbar Protection
08/02 1905/02/03
z
Can detect only earth faults
z
Switchgear must be insulated from earth (by standing on concrete plinth)
z
Only one single earth conductor allowed on switchgear
z
All cable glands must be insulated
z
Switchgear sections must be insulated
19
Frame Leakage Busbar Protection Neutral Check False Operation because induced loop
>I
>I
08/02 2005/02/03
No operation prevents from false trip
20
Frame Leakage Busbar Protection Neutral Check
>I
>I
08/02 2105/02/03
21
Frame Leakage Busbar Protection Neutral Check
>I
>I
08/02 2205/02/03
22
Blocking Scheme Protection Protection & Contrôle / Application 08/02 2305/02/03
Rev. A JM, September 2004
23
Blocking Scheme Busbar Protection
>I
08/02 2405/02/03
>I
>I
>I
>I
24
Blocking Scheme Busbar Protection
>I
08/02 2505/02/03
>I
>I
>I
>I
25
Blocking Scheme Busbar Protection
>I
08/02 2605/02/03
>I
>I
>I
>I
26
High Impedance Protection Protection & Contrôle / Application 08/02 2705/02/03
Rev. A JM, September 2004
27
Single Bus Substation
08/02 2805/02/03
28
Single Bus Substation
08/02 2905/02/03
P1
S1
P1
S1
P1
S1
P2
S2
P2
S2
P2
S2
29
Single Bus Substation
08/02 3005/02/03
30
Single Bus Substation
08/02 3105/02/03
31
Single Bus Substation
08/02 3205/02/03
32
Double Bus Substation
08/02 3305/02/03
33
Isolator Auxiliary Switches Current switching Bus A Bus B
P1 S1 P2 S2
a b
08/02 3405/02/03
P1
S1
P1
S1
P1
S1
P2 S2
P2
S2
P2
S2
P2
S2
P1 S1
Current
34
Isolator Auxiliary Switches Current switching Bus A Bus B
Current a b
08/02 3505/02/03
35
Isolator Auxiliary Switches Current switching Bus A Bus B
a b
08/02 3605/02/03
Current
36
Isolator Auxiliary Switches Current switching Bus A Bus B
a b
08/02 3705/02/03
Current
37
Isolator Auxiliary Switches Current switching Bus A Bus B
a b
08/02 3805/02/03
Current
38
Isolator Auxiliary Switches Current switching Bus A Bus B
a b
08/02 3905/02/03
Current
39
Isolator Auxiliary Switches Tripping switching Bus A Bus B
Tripping a b a Current b
08/02 4005/02/03
40
Interposing CT are not acceptable z
Main CT must be identical
z
Current switching via auxilliary relay is not acceptable. Requirement of number of position contact (Disconnector switch) is high
08/02 4105/02/03
41
Isolator Auxiliary Switches Current switching Bus A Bus B
a Current b
08/02 4205/02/03
42
Isolator Auxiliary Switches Current switching Bus A
Bus A
Bus B
Bus B
Current
08/02 4305/02/03
a b
Current
a b
43
Isolator Auxiliary Switches On Load Transfer Bus A Bus B
a Current b
08/02 4405/02/03
44
Isolator Auxiliary Switches On Load Transfer Bus A Bus B
a Current b
08/02 4505/02/03
45
Isolator Auxiliary Switches On Load Transfer Bus A Bus B
a Current b
08/02 4605/02/03
46
Isolator Auxiliary Switches On Load Transfer Bus A Bus B
a Current b
08/02 4705/02/03
47
Isolator Auxiliary Switches On Load Transfer Bus A Bus B
Current a b
08/02 4805/02/03
48
Isolator Auxiliary Switches On Load Transfer Bus A Bus B
a Current b
08/02 4905/02/03
49
Isolator Auxiliary Switches On Load Transfer Bus A Bus B
a Current b
08/02 5005/02/03
50
Isolator Auxiliary Switches Check Zone Bus A
Trip Bus B
Trip Bus A
Bus B
Zone A Zone B
08/02 5105/02/03
51
Isolator Auxiliary Switches Check Zone Bus A
Current switching failure
Trip Bus B
Trip Bus A
Bus B
Zone A Zone B
False Tripping 08/02 5205/02/03
52
Isolator Auxiliary Switches Check Zone Bus A
Trip Bus B
Trip Bus A
Bus B
Zone A Zone B
Check Zone 08/02 5305/02/03
53
Isolator Auxiliary Switches Check Zone Bus A
Trip Bus B
Trip Bus A
Bus B
Zone A Zone B
08/02 5405/02/03
54
Isolator Auxiliary Switches Check Zone Bus A
Trip Bus B
Trip Bus A
Bus B
Check Zone 08/02 5505/02/03
55
One Breaker and a Half Substation
08/02 5605/02/03
56
S1
P1
S2
P2
Bus A P1 S1
08/02 5705/02/03
Bus B P2 S2
P2
P1
S2
S1
57
Bus A
08/02 5805/02/03
Bus B
58
Bus A
08/02 5905/02/03
Bus B
59
Bus A
08/02 6005/02/03
Bus B
60
Bus A
08/02 6105/02/03
Bus B
61
Bus A
08/02 6205/02/03
Bus B
62
Bus A
08/02 6305/02/03
Bus B P1
P2
P2
P1
S1
S2
S2
S1
P1
P2
P2
P1
S1
S2
S2
S1
63