In Servicetesting Hands Onrelayschool2018

2018 Hands-On Relay School

In-Service Testing Bryan Focht Paul Luther

March 12 – 16, 2018 Washington State University Pullman, Washington

Outline • Philosophy of In-Service Testing • Polarity & Metering Conventions • Verifying Currents • Verifying Voltages

• Common Problems & Troubleshooting • Precautions • Electromechanical Relays

Philosophy of In-Service Testing • Testing Methods Prior to Energization • Following Energization of New Equipment – Final step of commissioning testing – Not a substitute for CT / PT circuit testing

• Routine Preventative Maintenance – Verify CTs, PTs and associated circuitry are healthy – NERC PRC-005 mandates specific verifications of BES (Bulk Electric System) components

• Alarming on CT & PT Failure • Microprocessor vs. Electromechanical

Testing Methods Prior to Energization Primary Current Injection

– Inject current through circuit breakers or power transformers & verify resulting secondary values – Verifies CT polarity, ratio, and secondary circuit – Verifying polarity requires a common reference IP = Primary Current IS1 = Secondary Current (CT1) IS2 = Secondary Current (CT2)

CTR1 > CTR2

A

A

IS1 = IP / CTR1

Ip

IS2 IS2 = IP / CTR2

Ip

IS1

Testing Methods Prior to Energization Standard tests using CT tester should catch most errors during commissioning – Polarity Test: Verifies relationship of primary polarity to secondary polarity.

– Ratio Test: Verifies turns on each CT tap matches manufacturer specification.

Testing Methods Prior to Energization Millivolt Drop

– Small battery and load connected at CT secondary terminals – Measure successive voltage drops in expected order to prove circuit layout against schematics

Secondary Injection

– Lift CT secondaries and inject 3-phase current with test set – Verify current in each device in CT circuit Voltage measurements take with respect to ground 3V Flashlight (load in series)

600 mV

Control House 500 mV

0 mV

+

Terminal Blocks Relay or Meter

+

400 mV

300 mV +

200 mV

100 mV

Following Energization of New Equipment – Testing done prior to energization should catch most errors but subsequent activities may compromise the installation, such as: • • • •

CT shorting screws left in place Test switches or isolating terminal blocks left open Blown PT fuses Extra CT grounds

– Routine verification of current, voltage, and relay-calculated quantities is final proof of proper commissioning. – Saving microprocessor-based relay metering screen records is valuable evidence in PRC-005 audits. BLLK-V62-11A, S/N 1160150005 BLUE LAKE

Date: 11/23/2016 Time: 15:30:54.056 Serial Number: 1160150005

I MAG (A) I ANG (DEG)

Phase Currents IA IB IC 401.038 399.660 403.567 -175.14 65.05 -56.52

V MAG (kV) V ANG (DEG)

Phase Voltages VA VB VC 138.154 139.222 138.809 0.13 -119.88 119.74

MAG ANG (DEG)

P (MW) Q (MVAR) S (MVA) POWER FACTOR

FREQ (Hz)

Phase-Phase Voltages VAB VBC VCA 240.227 241.236 239.390 30.25 -90.12 149.86

Sequence Currents (A) I1 3I2 3I0 401.392 10.154 11.765 -175.54 -0.29 -135.67 A -55.22 4.57 55.41 1.00 LEAD 59.98

B -55.44 4.78 55.64 1.00 LEAD VDC1(V)

Sequence Voltages (kV) V1 3V2 3V0 138.728 1.850 0.132 0.00 153.37 121.05

C -55.90 3.65 56.02 1.00 LEAD 132.76

VDC2(V)

3P -166.55 13.00 167.06 1.00 LEAD 133.07

Routine Preventative Maintenance Current and voltage verifications prove CTs and PTs are still performing within specifications and circuitry is not compromised.

NERC PRC-005 mandates specific verifications of BES components.

Alarming on CT & PT Failure PT Failure

– Some relays have loss-of-potential (LOP) algorithm suitable for alarming on compromised PT or secondary circuitry. – Under- or over-voltage elements combined with current detectors minimize nuisance alarming for deenergized PT. (27 AND 50LC) – High negative sequence voltage may indicate rolled phases or reverse rotation. (3V2 >> ) – Alarm for a standing ground on ungrounded or impedancegrounded systems. (3V0 >> )

CT Failure

– High differential current indicates a problematic condition. May be used to alarm and/or desensitize an 87 element to prevent misoperation. (87OP >> ) – High negative sequence current without corresponding negative sequence voltage may indicate loss of phase or rolled phases. (3I2 >> 3V2)

Microprocessor vs. Electromechanical Microprocessor-Based Relays – Built in HMI and metering screens allow for observation of live metering and phasor values. – Typically a backup relay is installed, facilitating isolation of a relay on a live system.

Electromechanical Relays – Requires external test equipment connected at the relay’s interface (e.g., test paddle and 3-phase power analyzer). – Often requires removing CT & PT inputs, compromising relay functionality. – Utilizing meters installed alongside the relays in conjunction with clamp-on ammeters used at the relay’s terminals is a means to avoid compromising protection.

Polarity & Metering Conventions • CT Polarity & Ratio – Dot convention – Primary orientation of bushing and freestanding CTs – CT ratio designations and connections

• PT Polarity & Ratio – Dot convention – Primary connections – PT ratio designations and connections

• Vector & Phasor Diagrams – Vector diagram & CT/PT connection equivalencies

• Metering Conventions – Current/Load Angle – Power Factor

Primary Polarity (H1)

CT Polarity

–

Bushing CT: Orientation of core within the bushing

– –

Bar CT: Terminal into which the primary conductor enters Window CT: Side into which the primary conductor enters

•

Standard convention has primary facing away from breaker or transformer

Secondary Polarity (X1) –

Determined by conductor or terminal with X1 marking

Secondary Non-Polarity (X0) –

Determined by conductor or terminal with X1 marking

CT Polarity Dot Convention – The “dot” indicates the polarity side or terminal – Primary polarity mark indicates which direction the CT is facing – Secondary polarity mark indicates which direction secondary current flows relative to primary – Important with polarity sensitive relays • Directional • Distance • Differential

In one dot and out the other IP

IP

IS

IS

IP

IP

IS

IS

Transformer Nameplate CT Polarity Example

High-side bushing Secondary Polarity Mark Primary Polarity Mark

CT Ratio – – –

CTs are single-ratio (SRCT) or multi-ratio (MRCT) Ratio tables are available on nameplates of transformers, circuit breakers, and standalone CTs Ratio provided in terms of nominal secondary current rating (actual thermal rating is higher) • 5A secondary is common in substation equipment • 1A secondary is used in some applications

– –

5 taps is common (X1 – X2 – X3 – X4 – X5) Full ratio provides best CT performance but small secondary values may go outside of meter or relay accuracy range

One Line Designation Full Ratio 2000-5A CT Type MRBCT Connected Tap 600-5A

Example Connected X2 – X3 CTR = 300 / 5 = 300 : 5 = 60 Is = Ip / CTR Is = 300 Aprim / 60 turns = 3 Asec

PT Polarity Dot Convention – – – –

The “dot” indicates the polarity terminal Primary (H1) and secondary (X1) polarity terminals are in phase Non-polarity terminal is 180° out of phase H0 or X0 reserved for neutral in a 3-phase wye connected PT

Note: PT and VT are equivalent terms.

PT Ratio

PTR = PT Ratio Vsec = Vprim / PTR PTR = Vprim / Vsec

Phasor Diagrams

f = frequency (60 Hz) Φ = Current Angle pf = cos(Φ) Lagging = Inductive Leading = Capacitive

Phasor Diagrams • Length of phasor = RMS magnitude 𝑽𝑽 = 𝑉𝑉𝑟𝑟𝑚𝑚𝑚𝑚 ∠0° 𝑰𝑰 = 𝐼𝐼𝑟𝑟𝑚𝑚𝑚𝑚 ∠𝜙𝜙 = 𝐼𝐼𝑟𝑟𝑚𝑚𝑚𝑚 ∠ − 45°

• • • •

(Note the animated sine wave above is scaled down by factor of 2 for illustrative purposes)

Rotates counter-clockwise at power system frequency (60 Hz) Drawn at time = 0 Shows phase and magnitude relationships Add, subtract, multiply and divide using vector arithmetic

PT Wiring – Vector Diagram Broken Delta Example 1. Begin with power system reference 2. Primary winding connected grounded-wye with nonpolarity terminals grounded 3. Piece together the secondary winding vector diagram with the equivalent primary winding vectors

Power System Reference

Broken Delta Connection (Secondary)

Wye Connection (Primary)

CT Wiring – DAB Vector Diagram DAB Connection – –

Shifts currents by 30° (leads) Used with traditional differential relays on the wye winding of a Delta-Wye power transformers where wye side lags by 30° (typical distribution transformer)

–

Resulting currents are scaled by 3, which must be accounted for with relay tap setting Filters out zero sequence current needed for correct differential operation

–

Power System Reference

B A C B

B

A B C

B +

+

Ia = Ia-ct – Ib-ct Ib = Ib-ct – Ic-ct Ic = Ic-ct – Ia-ct

A B

B

Resulting currents to relays larger by √3 and lead 30° in a balanced system

A Leading 30°

+

C

C

A

C A

C

A

C

CT Wiring – DAC Vector Diagram DAC Connection – –

Shifts currents by -30° (lags) Used with traditional differential relays on the wye winding of a Delta-Wye power transformers where wye side leads by 30° (typical GSU transformer)

–

Resulting currents are scaled by 3, which must be accounted for with relay tap setting Filters out zero sequence current needed for correct differential operation

–

A B C

Power System Reference

+

+

+

A

A

B A C

A

B

B

A

B

B

B

Lagging

A

C

C C

C

30°

Ia = Ia-ct – Ic-ct Ib = Ib-ct – Ia-ct Ic = Ic-ct – Ib-ct

Resulting currents to relays larger by √3 and lag 30° in a balanced system

C

Metering Conventions

Power Quantities

• •

IEEE defines positive power polarity as leaving a source bus towards a load. Note that angle 𝜙𝜙 in a PQ triangle and angle 𝜙𝜙𝑝𝑝𝑝𝑝 in a Voltage/Current plot are complex conjugates (flipped about the real axis per the example below)

𝑺𝑺 = 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑉𝑉𝑉𝑉, 𝑉𝑉𝑉𝑉𝑉𝑉𝑉𝑉 − 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴

𝑸𝑸 = 𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑉𝑉𝑉𝑉𝑉𝑉, 𝑉𝑉𝑉𝑉𝑉𝑉𝑉𝑉 − 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅

𝑷𝑷 = 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 (𝑊𝑊, 𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊𝑊) 𝜙𝜙 = 𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 = 𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 = 𝑟𝑟𝑟𝑟𝑟𝑟 𝑜𝑜𝑜𝑜 𝑑𝑑𝑑𝑑𝑑𝑑 𝑝𝑝𝑝𝑝 = 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹 𝜙𝜙𝑝𝑝𝑝𝑝 = 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 (sometimes called load angle, but leading or lagging must be indicated)

Single-Phase Power Equations 𝑃𝑃2 + 𝑄𝑄2 =

𝑆𝑆 = 𝑉𝑉𝑉𝑉 =

𝑃𝑃 = 𝑝𝑝𝑝𝑝

𝑄𝑄 =

𝑝𝑝𝑝𝑝 =

𝑉𝑉 2 = 𝐼𝐼2 𝑍𝑍 𝑍𝑍

𝑆𝑆 2 − 𝑄𝑄2 = 𝑆𝑆 cos 𝜙𝜙 = 𝑆𝑆 cos 𝜙𝜙𝑝𝑝𝑝𝑝 = 𝑉𝑉𝑉𝑉 cos 𝜙𝜙 = 𝑉𝑉𝑉𝑉 cos 𝜙𝜙𝑝𝑝𝑝𝑝 = 𝑆𝑆 ∙ 𝑆𝑆 2 − 𝑃𝑃 2 = 𝑆𝑆 sin 𝜙𝜙 = −𝑆𝑆 sin 𝜙𝜙𝑝𝑝𝑝𝑝

𝑃𝑃 𝑆𝑆

=

𝑃𝑃 𝑉𝑉𝑉𝑉

= cos 𝜙𝜙 = 𝑐𝑐𝑐𝑐𝑐𝑐𝜙𝜙𝑝𝑝𝑝𝑝 (𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚 𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠 𝑙𝑙𝑙𝑙𝑙𝑙𝑙𝑙/𝑙𝑙𝑙𝑙𝑙𝑙)

𝜙𝜙𝑝𝑝𝑝𝑝 = 𝜙𝜙 ∗ = −𝜙𝜙 (𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐 𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐 − 𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚 𝑏𝑏𝑏𝑏 − 1 𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟 𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎𝑎 − 90° 𝑡𝑡𝑡𝑡 90°)

𝜙𝜙 = tan−1

𝑄𝑄 𝑄𝑄 𝑃𝑃 = sin−1 = cos −1 𝑃𝑃 𝑆𝑆 𝑆𝑆

Three-Phase Power Equations 𝑆𝑆3𝜙𝜙 = 3𝑉𝑉𝐿𝐿𝐿𝐿 𝐼𝐼𝜙𝜙 = 𝑃𝑃3𝜙𝜙 =

𝑄𝑄3𝜙𝜙 = 𝑝𝑝𝑝𝑝 =

𝑃𝑃 𝑆𝑆

𝑃𝑃2 + 𝑄𝑄2 =

2

3𝑉𝑉𝐿𝐿𝐿𝐿 = 3𝐼𝐼𝜙𝜙 2 𝑍𝑍 𝑍𝑍

𝑆𝑆3𝜙𝜙 2 − 𝑄𝑄3𝜙𝜙 2 = 𝑆𝑆3𝜙𝜙 cos 𝜙𝜙 = 3𝑉𝑉𝐿𝐿𝐿𝐿 𝐼𝐼𝜙𝜙 cos 𝜙𝜙 = 𝑆𝑆 ∙ 𝑝𝑝𝑝𝑝 𝑆𝑆3𝜙𝜙 2 − 𝑃𝑃3𝜙𝜙 2 = 𝑆𝑆3𝜙𝜙 sin 𝜙𝜙

=

𝜙𝜙 = tan−1

𝑃𝑃 3𝑉𝑉𝐿𝐿𝐿𝐿 𝐼𝐼𝜙𝜙

= cos 𝜙𝜙 (𝑚𝑚𝑚𝑚𝑚𝑚𝑚𝑚 𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠 𝑙𝑙𝑙𝑙𝑙𝑙𝑙𝑙/𝑙𝑙𝑙𝑙𝑙𝑙)

𝑄𝑄 𝑄𝑄 𝑃𝑃 = sin−1 = cos −1 𝑃𝑃 𝑆𝑆 𝑆𝑆

Verifying Currents • Relay Accuracy Limits at Low Loading • Methods of Current Verification – Additional CTs of the Same Equipment • Relays • Meters • Clamp-on ammeter measuring other wiring

– MW/MVAR Summation Across a Bus (zero sum) – Remote End of Transmission Line • Tapped Load Consideration • Line Charging Consideration

– Hot-Stick Ammeter

Relay Accuracy Limits at Low Loading • Relays tend to be the limiting factory in terms of accuracy rather than CTs • Guaranteed Accuracy Examples (5 A Relays) – Basler BE1-851: 1% @ 0.5 A – SEL-751A: 2% @ 2A – SEL-411L: 0.2% @ 0.5 A

• Microprocessor metering accuracy is reasonable below these specified values but discretion should be exercised at low loading

Methods of Current Verification Additional CTs on the Same Equipment This meter connected to the same CT does not prove accurate current is being delivered from the CT. An error will show up in both devices.

Clamp-on ammeter here to prove accurate current. Must compare in terms of primary current due to mismatched CT ratios.

To summed bus differential circuit

Methods of Current Verification Differential Relays Verify both CTs – Differential Operate Current Less than about 0.03 per unit – Current Magnitudes ILV = IHV * Transformer Ratio ILV = IHV * (VHV / VLV) – Current Angles HV and LV winding currents offset 180° (CT polarity) plus 30° (delta leading) = 210° total expected angle difference – Be mindful of deenergized (no-load) tap and LTC tap positions that affect the transformer ratio. Use measured bus voltages if available. Transformer Ratio 𝐻𝐻𝐻𝐻𝑡𝑡𝑡𝑡𝑡𝑡𝑝𝑝𝑝𝑝𝑝𝑝

𝐿𝐿𝐿𝐿𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛

1 − 𝐿𝐿𝐿𝐿𝐿𝐿 𝑇𝑇𝑇𝑇𝑇𝑇 %

RUBY-WR1-87T1 13:01:47.407 WR1 TRANSF DIFF

Date: 02/19/2015

Time:

Time Source: External

Wdg1 Mag (A pri.) Wdg1 Angle (deg)

IAW1 13.2 121.2

IBW1 13.5 4.0

ICW1 13.6 -117.8

IGW1 0.4 36.1

3I2W1 0.9 -21.1

IAVW1 13.4 0.0

Wdg2 Mag (A pri.) Wdg2 Angle (deg)

IAW2 133.6 -89.8

IBW2 134.0 151.0

ICW2 136.0 31.2

IGW2 1.7 106.3

3I2W2 4.1 165.5

IAVW2 134.5 0.0

Operate

(pu)

IOP1 0.01

IOP2 0.01

IOP3 0.00

Restraint

(pu)

IRT1 0.14

IRT2 0.14

IRT3 0.14

Methods of Current Verification Hot Stick Ammeter

Methods of Current Verification MW/MVAR Summation Across a Bus – – – –

Sum MW of all positions on a bus Sum MVAR if a cap bank or reactor is present Positive power defined flowing from source to load Note the transformer value must be subtracted based on its CT connection MW 9.3 MW

Position Bkr 1 Bkr 2 Bkr 3 XFMR Net MW % Error

MW 3.2 1.8 4.1 -9.3 -0.2 1.1%

11

11

11

3.2 MW

1.8 MW

4.1 MW

1

2

3

Methods of Current Verification Remote End of Transmission Line – – –

Suitable for shorter lines and subtransmission or distribution voltage - Charging current losses due to line shunt capacitance becomes significant at higher voltage and long lines May compare current or MW values Any tapped distribution load must be accounted for 368 A ∠ 1.7°

364 A ∠ -170.7°

CTR = 400 Ia pu = 0.184 A

CTR = 400 Ia pu = 0.182 A

Line Charging Current

MAG (pu) ANG (DEG) THROUGH (pu) CC MAG (pu) CC ANG (DEG)

IA 0.184 1.73 0.184 0.008 -96.67

IB 0.191 -119.61 0.187 0.008 143.44

Local Terminal IC I1 0.187 0.187 117.89 0.00 0.184 0.008 22.90

MAG (pu) ANG (DEG) THROUGH (pu)

IA 0.182 -170.68 0.184

IB 0.191 68.80 0.194

MAG (pu) ANG (DEG)

IA 0.024 -79.58

k alpha (DEG)

87LA 1.000* 180.00*

3I2 0.017 135.83 0.020

3I0 0.005 67.59 0.010

Remote Terminal 1 IC I1 0.188 0.187 -54.67 -172.19 0.185

3I2 0.020 -21.70 0.017

3I0 0.005 -110.69 0.000

IB 0.028 155.09

Differential IC 0.024 29.71

3I2 0.008 35.58

3I0 0.000 -11.10

87LB 1.000* 180.00*

Alpha Plane 87LC 1.000* 180.00*

87LQ 1.000* 180.00*

87LG 1.000* 180.00*

Verifying Voltages • • • •

Phase Rotation 120° Offset Electrically-Connected Buses Across Power Transformers – Expected Angle Shift – Deenergized and LTC Tap Considerations

• Opposing Ends of Transmission Lines

Voltage Phase Rotation and 120° Offset • Grid-connected systems are ABC rotation – ABC = Counter-clockwise phasor rotation – Phase rotation meters may indicate clockwise (know your measurement device’s convention) – ACB systems must swap 2 phases before connecting to ABC system

• Voltage phase separation should not vary significantly from 120° V = V ∠120° c

Va = V ∠0°

Vb = V ∠-120°

Common Problems and Troubleshooting

• • • • • • • •

CT Tap CT Polarity CT Secondary Connections (Wye-DAB-DAC) Extra CT Grounds Full or Partial Current Shunting PT Tap PT Primary and Secondary Connections PT Polarity

Common Problems and Troubleshooting CT Tap – Determining secondary tap is typically derived from a setting sheet or other engineering overview document. – Tap/Ratio availability is typically determined during commissioning. – Shorting screws left in, improper wiring (wrong ratio), and loose wiring hardware are common trouble items. – Improper understanding of CT rating may lead to improper tap selection. An expected 2000:5 CT that is actually a 3000:5 is an example of this.

Common Problems and Troubleshooting CT Polarity – Unexpected metering values are a good way of determining improper secondary polarity on non-differential circuits. – Improper differential secondary polarity will result in an unexpected trip when an external fault occurs, and possibly even load current. – Primary polarity should be determined during commissioning. Many methods are available to prove primary CT polarity. • What is your expected polarity? • Does the company have a standard polarity that is specified in particular devices? • Is this depicted on a drawing or in a standard manual? • If incorrect, typically the repair is invasive and requires factory assistance.

Common Problems and Troubleshooting CT Secondary Connections (Wye-DAB-DAC) – Secondary wiring configurations should be depicted on drawings. – Proper jumper installation is critical to the correct configuration being utilized. – Extra scrutiny should be applied to delta connected CT secondary circuits as polarity and phasing are not as simple to determine as a wye connected circuit.

Common Problems and Troubleshooting Extra CT Grounds – A single ground should be present on a CT circuit. – Testing during commissioning should determine if multiple grounds exist. Do this by lifting the known ground then Megger the CT circuit to ground. – Typically company standards will determine the preferred location of the ground. It should also be depicted on a drawing. – Multiple grounds on CT circuits will sometimes cause significant errant current flow, depending on the location. – This reduces operating current in overcurrent and distance relays and introduces differential current error.

Common Problems and Troubleshooting Full or Partial Current Shunting – Full or partial current shunting around a relay should have been caught during commissioning, but may be caused by wiring problems, or testing methods. – Beware of wiring alternations in CT circuits - the circuit should be retested after any changes have been made.

Common Problems and Troubleshooting PT Tap – Most VTs offer multiple secondary windings and taps. Multiple secondary windings allows for some redundancy between primary and secondary protective relays. – Multiple secondary tap choices allows for different ratios to be utilized at the designers will. – Proper secondary ratios and destinations would be proved during commissioning but improper metering values may indicate a ratio problem.

Common Problems and Troubleshooting PT Connections – Proper secondary circuit configuration should be determined from a drawing and/or engineering request. – Extra care should be exercised when checking out delta connected secondary wiring as phasing and jumpers are common mistakes.

Common Problems and Troubleshooting PT Polarity – Primary and secondary polarity should be determined by factory markings on the PT. – Extra caution should be used if primary polarity is not determined on double bushing style PTs. – Secondary polarity should be determined during commissioning with some type of voltage injection testing on secondary conductors. Continuity testing works as well.

Precautions Affecting Differential Circuits – Inserting & Removing Test Paddles – Protective relay current circuits connected in series with differential relays, particularly relays connected electrically upstream from the differential relays have caused inadvertent operations when a test block, dressed with test leads, has been inserted into the upstream relay test switch. – The action of inserting the test block, with leads connected, diverts just enough current to ground to activate the differential. This has led to procedural changes at many companies, requiring no test leads connected to test blocks upon insertion to test switches.

Precautions Removing Voltages on Distance and VoltagePolarized Relays

– The removal of voltages from distance electromechanical relays that use that voltage to provide restraint can be an issue. • The tripping contacts for most of these style relays should be adjusted to fall towards the non-trip direction but a misadjusted contact will fall towards the trip direction when restraint is lost. • Without the restraint holding the contact steady, the relay is vulnerable to vibration as well.

– The loss of voltage to a microprocessor relay will cause the distance elements to resort to non-directional overcurrent elements when configured. This may result in system miscoordination. – The loss of potential to a voltage polarized relay will result in a non-trip for a fault located on the protected line, as no torque will be created to operate the instantaneous or timeovercurrent elements of the relay.

Electromechanical Relays Stabbing and Measuring with Phase Angle Meter (e.g., Arbiter) – In-service readings taken from electromechanical relays are done two different ways depending on which manufacturer is being tested.

– Westinghouse/ABB utilizes a Type FT test switch built into the relay case.

• Connecting a phase angle meter in series with the test jack will provide a means of measuring the current in the relay. The test jack can be inserted directly into the type FT switch without disrupting protection. • A voltage connection to the phase angle meter will allow watts and vars to be measured. • Care must be taken to not disconnect the test jack from the phase angle meter before removing the test jack from the relay as this will open the CT circuit.

– GE in service current readings are taken utilizing the GE test block.

• The test block must be prepared before it is inserted into the relay. The GE relay paddle is removed and the test block is inserted. • The current circuits are temporarily shunted around the relay while the paddle is removed. • Care must be taken while preparing the test block to insure continuity of the CT circuit. The test leads must be connected to the phase angle meter before insertion into the relay to insure CT circuit continuity. • A voltage connection will allow the meter to read watts and vars.

Electromechanical Relays Red/Green Light Trip Circuit – Trip circuit monitoring is cumbersome with electromechanical relay installations. – There are manufactured red lights with built in circuit monitors that can be remotely reported.