CBIP Presentation on Protection and Communication

North Delhi Power Limited

Protection Requirements for Power Distribution

NDPL Case Studies

Flow of Presentation

• Overview of NDPL network

•Transformation for betterment

•Exploration in Relaying

•Exploitation of Relay facilities

•NDPL Case Studies

OVERVIEW

Overview of NDPL Network

•NDPL is a Joint venture of TATA Power and Govt. of NCT of Delhi

•NDPL looks after Power Distribution of North and North-west area of Delhi

•Area of distribution network - 510 sq. km

•Total number of 66/33 KV Grid Stations – 59

•No. of Distribution Transformers – 9000

•Total no. of RMU’s - 8500

Performance Measurement• NDPL has developed and maintained a Performance Index of Protection since 2004 on a monthly basis

• Protection System Reliability has improved from 98.4% to 99.66%

• Reduction of uncoordinated tripping by 3-4 no’s every month has been observed.

2004-5 2005-6 2006-7 2007-8 2008-9 2009-1097

97.5

98

98.5

99

99.5

100

100.5

PPIRIDI

TRANSFORMATION

Transformation

•System reliability and availability is the main focus of a power distribution utility.

•Protection and control system and its timely and correct operation during faults is an important and crucial aspect in efficient and successful operation of Power distribution utilities.

•NDPL has completed its GSAS (Grid Substation Automation Scheme) project in 2005

•Grids were commissioned with use of IED’s that are compatible to SCADA

•This transformation from Electromechanical to Numerical relaying lead to better system reliability.

Transformation (Grid Stations)

After GSAS in Grid

Substations

Transformation (Distribution) PRE- GSAS POST -GSAS

Old Switch Gears New Ring Main Units

PRE- GSAS POST- GSAS

Electromechanical relays were used in all the panels.

Numerical relays were used in all the new panels commissioned after GSAS commissioning work.

No time synchronization feature is available in the relay. Electromechanical relays are prone to sluggish operation.

Time synchronization of all the Numerical relays with Data control center.

No FDR/ waveform/ event list can be downloaded and hence Fault analysis becomes a tedious job.

Availability of FDR / Waveform/Event in milliseconds resolution helps in detailed analysis of various faults.

Electromechanical relays are single function relay.

They are multifunctional IED’s i.e. Measurement/ Protection/ Control.

Limitation of feature in the relay i.e. operational only for selected protection element and no internal logic can be developed.

Inbuilt logic development feature in the relay for the purpose of better coordination.

Transformation Stages

Transformation Stages (Distribution)

PRE- RMU/AR/PSS POST-RMU/AR/PSS

Sluggish Operation of the relay.

Excellent Sensitivity and fast operation.

No FDR / EVENT recording FDR/ EVENTS is recorded which is useful for analysis.

Setting Coordination was a major concern.

Better coordination between grid and RMU can be obtained.

• Redundancy of Protection functions in terms of

Main/Backup relay.

Multiple protection elements.

• Communication compatibility for SCADA systems.

• Fast operation of the system with correct indication

• Improvement of the system with faster Corrective and Preventive

Actions.

• Efficient and Correct Fault Discrimination

• Record of Real time metering along-with its quality features

• Online Diagnosis and relay setting

Expectations from newly adopted relaying system

Effective Distribution Protection

Application cum Coordination Various characteristics like NI/VI/EI have been effectively used from grid to

RMU to accommodate stiffer relay setting coordination of even 250ms.

Sustainability: Sustainability of the settings has

ensured proper sealing of RMU relays.

2005.5 2006 2006.5 2007 2007.5 2008 2008.5 2009 2009.5 2010 2010.50%

10%

20%

30%

40%

50%

60%

70%

59%60%

39%

26%24%

% Tripping Escalation to Grid

% Tripping at Grid

EXPLORATION

Improvement in System ReliabilityWith IEDs used as relays, reliability of the Power System improved due to various available functions.

•Faster relay operating time as low as 20 ms

•Effectiveness and Relay Co-ordination possibility on micro level by utilizing multiple elements in the Relay. Almost all feeders provided with High-set and IDMT Protection.

•As At feed end (DTL) only IDMT Protection is available best co-ordination has been achieved by using DT-High set protection at our end.

•Protection, Metering, Monitoring, Diagnosis and Control functions can be performed from the one unit-IED

•All Protection relays cum BCU’s are well protected with Password. Separate Passwords for operation and Protection facilitate safe Protection settings and eliminated tampering of the relay settings.

•Ultimate Goal of the Automation is to operate the system in Unmanned mode. Mimic diagrams and friendly relay functions of the Relay helps breakdown team to visualize and understand the fault and operation.

•Additional Trip Supervision relay and wiring has been reduced by using status inputs of the Numerical Relay.

•Following Logics has been Configured in the relay for having effective control and Protection of the system without conventional hard wiring.

1.CBFP cum LBB Scheme.2.Reverse Blocking Scheme for Bus bar Protection.3. No requirement of the Annunciation fascia due to availability of sufficient Configurable LED’s on relay itself.

Improvement in System Reliability

•Important Projects/Logics includes:

• Reverse Blocking

• Local Breaker Backup

• Transformer Monitoring Unit

• CAP ON TAP

• Remote Relay Parameterization

• Multiple Relay setting groups

• Safety concerns tackled with relaying

• Life assessment of Lightning Arrestors

Schemes/Logics Implementation

Reverse Blocking• Reverse Blocking scheme is very useful for having co-ordination in tripping

between 11 KV OG Feeder and 11 KV Incomer Breaker of the Bus.

• All outgoing feeders send a blocking command for 50 ms to prevent tripping of the Incomer breaker during heavy faults and even in cases of delayed tripping of outgoing feeder breaker.

• Control wiring has been reduced by around 30% owing to facility of control logic development in the relay.

• No requirement of interposing CT’s and VT’s in the system for relay operation.

• Ratio Correction facility will serve the purpose.

Reverse Blocking

I>>> start

I>> start

I> (IDMT)

I< low

Io>> start

Io>>> start

Io> (IDMT)

Io< low

Reverse Blocking commandOR

O/G

Fee

ders

of S

ectio

n - 1

&

BLOCK HIGH SET I/C#1

BLOCK HIGH SET OF B/C

BLOCK HIGH SET OF I/C#2

B/C ON

Reverse Blocking command is given by Outgoing feeders to incomers/Bus-couplers to Block tripping of Incomers in case of fault in 11 KV Outgoing feeder.

Reverse Blocking (Cont.)

11 KV Incomer-1 11 KV Incomer-2

Mithila ViharNithari feeder

Both feeders running on same pole generally face external faults simultaneously

Incomer sees vector summation of both the fault currents and cause tripping

11 KV Incomer tripping alongwith 11 KV Outgoing Due to fault summation at RG-22 Grid.

•Fault on one of the Outgoing feeder was being induced in the other one.•This causes tripping of the incomer on account of summated timing

Reverse Blocking (Cont.)•ADLI Approach lead to rectification of Problem

•APPROACH: Specific type of fault was studied

•DEPLOYMENT: New Scheme implemented in 61850 compliant grid stations

•LEARNING: On the lines of the scheme implemented in soft form in 61850 compliant grid stations. New scheme designed for Grid stations working on older standards is designed.

•INTEGRATION: The learning is integrated across all NDPL grids and that helped a lot in increasing reliability of the network.

Directional Protection for parallel feeders

•Parallel feeders are protected with the help of a combination of directional as well as non-directional relays

•Helpful in cases where we have stiff margins in long feeders through a series of grid stations.

•Directional relays are also effectively used for protection of Line as well as Bus-Bar by using Tri-mode settings.

•Use of relays in Tri-mode helps in reducing the restoration time compared to that could have been taken if the bus fault has been cleared by DTL station.

CBFP Protection Circuit

&200 ms

Time delayTrip

Upstream

1. I>>> Start up (Used for CBFP Only)2. Breaker in service3. Breaker Close4. 86 Operated

Breaker

&

Transformer Monitoring Units•TMUs have replaced the older RTCC panels and enabled high control over transformers

•Use of TMUs as IED in system has made the Transformer functionality more accurate and redundant one.

•Some of the important features of TMU are:• Voltage control/Regulation through various logics• High speed Forward Backward Switching of OLTC for Voltage control• Fan control through temperature settings.• Display of Voltage/Current/Power/Power factor etc and can be used as

Output also for remote indication.• Event log of the selected functions.• Recorder mode monitoring of OTI/WTI/VOLTAGE CURRENT in Dual

Parameters at a Time.• Correct calculation based on Algorithm for WTI with input of OTI/LOAD

OF Transformer/Winding exponent/Time constant of winding

CAP ON TAP•There was always a thrust within us to provide quality power to our consumers.

•It lead to start of Automatic Tap changers for voltage/reactive power control from 2007 onwards

•OLTCs were integrated with our Transformer Monitoring Units (AVR)

•But every solution comes with a problem.Tap operations increased

drastically

High maintenance cost and Equipment Breakdown !

33 / 66 KV unregulated Input Voltage

11 KV regulated output voltage

Capacitor Bank

Automatic Voltage Regulator

Power Transformer with ON-LOAD Tap Changer

Conventional Automatic Voltage Regulation

33 / 66 KV unregulated Input Voltage

11 KV regulated output voltage

Capacitor Bank

Automatic Voltage Regulator

Power Transformer with ON-LOAD Tap Changer

CAP ON TAP

K101 K102

52A ( Cap. Bank) AVR (Input- Cap. Bank Close)

U17 U18

R8(O/V)TMU

R7(U/V) AVR R4(>I)AVR

I13 (Relay-Open)

I21( Relay-Close)

K101

K102

53

51

50

53 3635

11 12

1 2

7 8S

O/V monitored by AVR

U/V monitored by AVR

I> monitored by AVR

Relay

Relay

Trip Breaker + Display On Relay Panel and at CLD through SCADA network

Close Breaker + Display On Relay Panel and at CLD through SCADA network

AVR Signal + Breaker Close ?

AVR Signal + Breaker Open+ Efficacy Time+ Protection OK?

Cap. Bank CB status

Underlying logic used…..

Increase in Power Quality after CAP on TAP

0:001:00

2:003:00

4:005:00

6:007:00

8:009:00

10:0011:00

12:0013:00

14:0015:00

16:0017:00

18:0019:00

20:0021:00

22:0023:00

0.000

5.000

10.000

15.000

20.000

25.000

30.000

35.000

11 KV 33 KV

Remote Relay Parameterization•It is a concept that deals with connecting to the relays from a remote location for the purpose of retrieving data.

•Connection to the relays from a remote location is done to enable a distant user to retrieve Fault Data Records, along with making configuration changes in terms of Relay settings.

•Remote parameterization is done for the following purpose:• Downloading of Fault Data Records• Changing the Relay settings according to Power flow• Configuration changes in the relays• Mitigating issues pertains to n/w changes

Relay setting and Centralized Fault Data Downloading

Advantages of RRPPROFIT•Downloading of Fault data from a central location would save considerable amount of manpower and time.(There is saving of about 20-25 Km run daily along with daily saving of 8-10 man-hours)

•Relay settings can be changed quickly after any updation in NOC to save on MU’s lost in case of uncoordinated trippings due to inappropriate settings.

•Exploiting of available features in relay with use of new/innovative technology would lead to better utilization of available resources.

PEOPLE•Time saved in commutation to the sites for downloading FDR’s could be used by employees for other analysis/works.

PLANET•There would be considerable saving in carbon credits due to saving in commutation of engineers/technicians to site.

Multiple Relay setting groups•Existing facility of multiple setting groups used to easily change settings.

•With any updation in NOC, relay settings need coordination with respect to new power flow.

•Non-updated/wrong relay settings can lead to uncoordinated trippings

•Relay settings are entered in groups with reference to generally used Normal operating conditions.

•These different setting groups are then activated through local/remote signals for the specific NOC.

•It increases reliability and usability of the network.

Life assessment of Lightning Arrestors•NDPL has recently done residual life assessment of the Lightning arrestors installed at its Grid stations to avoid damage to Bay equipments owing to LA failure.

•Monitoring of the following attributes has been done to check the life expectancy of the metal oxide arrestors in service.

• True RMS of the total leakage current. • Peak value of the total leakage current. • True RMS of the third harmonic in leakage current.

•These online tests were performed by using a Metal Oxide Surge Arrester Test Set (SCAR-10, make-ISA)

•Tests were done according to IEC standard 60099-5 A1 ED. 1.0 Section 6: “Diagnostic indicators of metal-oxide surge arresters in service – Method B1 and B2”

•Algorithms were developed and the LA’s were kept in three categories:• RED Immediately replaced• YELLOW Next assessment within 3 months• GREEN Next assessment after 1 year

Life assessment of Lightning Arrestors

DECISION CRITERIA USED

EXPLOITATION

Exploitation of Relay facilitiesHarmonics Analysis of NDPL distribution System

•9 NDPL grids were covered in this case study.

•Following data pertaining to harmonics was taken from Schneider PM 500 Series meters: -

• Line to line voltage THD.• Phase voltage THD.• Line Current THD.• Instantaneous Loading

All the data was taken from the PM500 (Schneider) meters connected to the C&R panels of all the outgoing feeders at 11 KV side.

Bus PT (potential transformer) gave voltage THD and CT (current transformer) connected to the outgoing feeders gave current THD.

41

Standards for Harmonics LimitationIEEE/IEC

• IEEE 519-1992 Standard: Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems (Current Distortion Limits for 120v-69kv DS)

Table 1: Current Harmonic Limits

Ratio Iscc / Iload

Harmonic oddnumbers (<11)

Harmonic oddnumbers (>35)

THD-i

< 20 4.0 % 0.3 % 5.0 %

20 - 50 7.0 % 0.5 % 8.0 %

50 - 100 10.0 % 0.7 % 12.0 %>1000 15.0 % 1.4 % 20.0 %

42

Standard of Harmonics Limitation

• IEEE 519-1992 Standard: Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems (Voltage Distortion Limits)

Table 2: Voltage Harmonic Limits

Bus Voltage Voltage Harmonic limit as (%) of Fundamental

THD-v (%)

<= 69Kv 3.0 5.0

69 - 161Kv 1.5 2.5

>= 161 Kv 1.0 1.5

Harmonic Measurements•PCC showing THD higher than the permissible limits is investigated thoroughly to obtain the spectrum of voltage and current waveform.

•THD is obtained from energy meters attached to the C&R panels. Examples of such meters are PM500 (Schneider), Ref542+ (ABB), S80 etc.

•Power quality analyzer is used to obtain voltage and current spectrum. Example of such instrument is Fluke power quality analyzer.

•In second phase we would segregate different harmonics and accordingly design mitigation techniques for specific feeders.

Detailed study of ∑kA²

• Data helps in analysis of Residual Life of Breakers.• Predictive maintenance.• Life Extension by swapping of Breakers.• Fault level Studies.

Way Forward• Algorithm development based on Tripping.• Life analysis of the Breakers• Recommendations for future procurements of breaker

Exploitation of Relay facilities

11 KV Trippings details atWAZIRPUR-1 Grid    ∑kASqr.

S No Fdr Name Total 0-2In 2-5In 5-10In10-40In >40In

1 shunt capac -3 253 65 26 12 148 02 b-67 wzp ind area 1468 80 1095 273 20 03 smb 5-a 1167 0 19 202 946 04 c.e.t plant a.v 175 0 14 45 116 05 d.s.i.d.c shed 21 w.i.a 285 0 24 21 240 06 b 32/2 w.i.a 44 0 10 3 31 07 enf office fdr w.i.a 845 0 35 67 743 08 I/C no.-3 2597 103 616 1877 0 09 bus section-2 1228 39 457 130 602 0

10 shunt capac-2 74 41 29 3 0 011 g.i.a -1A w.i.a 583 0 24 30 529 012 bc block w.i.a 745 0 22 67 654 013 c&a w.i.a 1337 0 32 77 1228 014 bb-1 block ashok vihar 279 0 41 39 199 15 kd block-1 283 0 41 21 221 016 smb-3A 451 0 33 0 418 017 I/C-2 1161 63 845 252 0 018 bus section -1 1007 74 210 403 320 019 I/C -1 553 105 266 182 0 0

Detailed study of ∑kA²

Distribution Fault Restoration using FPI’s

NO

Fault occurrenceUpstream Breaker OpensFPI indicate fault

CASE STUDIES

DETAILS OF EVENTS• 11 KV Mithila Vihar feeder tripped along-with 11 KV Incomer

OBSERVATIONS• Total load of the station is around 800 Amps and System is keeping total load on

any of the transformer keeping the other transformer on no load.• Mithila Vihar feeder tripped on over current High set.• 11 KV Incomer-2 tripped on over current High set.• Fault data record of the Incomer show’s that Fault seen by 11 KV Incomer is 9.1

KA while fault seen by Mithila Vihar feeder is 6.2 KA.• It is observed that Nithari feeder was also seen the fault but not tripped due to

isolation of the fault. Protection settings were coordinated and CT Ratio adoption was found correct.

CONCLUSIONAfter going through the tripping events it was observed that both feeders were

getting tripped simultaneously.

Tripping Analysis report for 11 KV Mithila Vihar feeder along-with 11 KV Incomer.

• After going through the fault data record, it is very clear that fault seen by Incomer is always on higher side as compared to the outgoing feeder.

• The tripping in the incomer occurs as the fault current “seen” by the incomer breaker is a summation of the outgoing faults.

• Both the outgoing feeders were routed on the same poles and on same cross arm. Thereby, the occurrences of birdage in both the feeders occur simultaneously.

• We have identified around twenty feeders that emerges from the same bus and have same route, as a corrective action we changed the emerging bus of those feeders.

CASE STUDY (Contd..)

Transformer Tripping on differential protection

OBSERVATION• Stray DC Current component was present in R Phase current at the time of event. • It was also confirmed from the event that DC Ingress has caused the tripping.• It was confirmed that no ingress was there through external cabling. • Even after isolating external circuit, Relay has generated tripping. • Waveform of this particular event was showing that tripping is purely due to DC

Component of the current in CT Circuit. It also shows that after decay of the DC Current Output relay got reset.

CONCLUSION• It is confirmed that Tripping is due to intermittent DC Ingress in R Phase Secondary of

HV CT Circuit especially.• In modular type Duo-bias relay, two separate modules are there for power supply as

Well as CT Circuit. It seems DC is getting mixed up in CT Circuit within the relay.

CORRECTIVE ACTION• Suitable input was given to the OEM for correction in the barrier plate between power

supply module and CT card.

PTR-2 Tripping on differential protection at Badli Grid.

Malfunctioning of Directionality sense

• On analysis of the cases, we found that the open delta voltage from the installed IVT’s was causing the spurious trippings.

• The cause was mainly because of ageing effect of the IVT’s in the circuits.

• Afterwards we started to make open delta with the spare core of PT’s in the yard and extending that to the relays.

CT Saturation leading to differential fault• Earlier transformer tripping on differential leads to a series of transformer tests that are carried out to ascertain the health of transformer.

• In some cases a through fault lead to saturation of CT that causes tripping on differential protection.

• Tests on CT indicated that knee point voltage of PS Class CT Core has got reduced due to Saturation.

• A New feature of the Numerical relay can discriminate CT Saturation.

• After the analysis we ascertained using the Saturation Discrimination function for reliability of differential protection schemes for transformers

CT Saturation leading to differential fault

Thank you.

North Delhi Power Limited