TransformerProtection.pdf

November 14, 2017 | Author: Jeya Kannan | Category: Transformer, Relay, Electric Power Distribution, Electrical Equipment, Power Engineering
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Hands On Relay School Transformer Protection Open Lecture

Hands On Relay School Transformer Protection Open Lecture

• • • •

Class Outline Transformer protection overview Review transformer connections Discuss challenges and methods of current  differential Protection Discuss other protective elements used in  transformer protection

Scott Cooper Eastern Regional Manager Manta Test Systems

[email protected] (727)415-5843 204 37th Avenue North #281 Saint Petersburg, FL 33704

Transformer Protection Overview  Transformer Protection Zones

Types of Protection Mechanical Protection • Analysis of Accumulated Gases – Looks for arcing by‐products

• Sudden Pressure Relays – Orifice allows for normal thermal expansion/contraction.  Arcing  causing pressure waves in oil or gas space overwhelming the orifice  and actuating the relay.

• Thermal – Caused by overload, over excitation, harmonics and geo magnetically  induced currents • Hot spot temperature • Top Oil • LTC Overheating

Types of Protection Relay Protection • Internal Short Circuit – Phase:  87HS, 87T – Ground:  87HS, 87T, 87GD

• System Short Circuit Back Up Protection – Phase and Ground Faults • Buses:  50, 50N, 51, 51N, 46 • Lines:  50, 50N, 51, 51N, 46

Types of Protection Relay Protection • Abnormal Operating Conditions – – – – –

Open Circuits: 46 Overexcitation: 24 Undervoltage: 27 Abnormal Frequency:  81U Breaker Failure:  50BF, 50BF‐N

Phase Differential Overview • •



What goes into a “unit” comes out of  a “unit” Kirchoff’s Law: The sum of the  currents entering and leaving a  junction is (should be) zero Straight forward concept, but not  that simple in practice with  transformers

I1 + I2 + I3 = 0 I1

UNIT

I3

I2

Phase Differential Overview A host of issues presents itself to decrease security and reliability of transformer  differential protection • CT ratio caused current mismatch • Transformation ratio caused current mismatch (fixed taps) • LTC induced current mismatch • Delta‐wye transformation of currents – Vector group and current derivation issues • Zero‐sequence current elimination for external ground faults on wye windings • Inrush phenomena and its resultant current mismatch • Harmonic content availability during inrush period due to point‐on‐wave  switching (especially with newer transformers) • Over‐excitation phenomena and its resultant current mismatch • Internal ground fault sensitivity concerns • Switch onto fault concerns • CT saturation, remnance and tolerance

Phase Differential Overview‐Transformer Basics

Transformer Tap Calculation‐Per Unit Concept Compensation (2) Change in CT Ratio 1:1, Y-Y 4:1, 3Y

1:1, 3Y Ia, Ib, Ic

IA, IB, IC IA', IB', IC'

Ia', Ib', Ic'

IA'*4 = Ia' IB' * 4 = Ib' IC' * 4 = Ic'

Phase Differential Overview‐Transformer Basics

Transformer Tap Calculation‐Per Unit Concept

Compensation (3) Transformer Ratio

2:1, Y-Y

1:1, 3Y

1:1, 3Y Ia, Ib, Ic

IA, IB, IC IA', IB', IC'

Ia', Ib', Ic'

IA' = Ia' / 2 IB' = Ib' / 2 IC' = Ic' / 2

Phase Differential Overview‐Transformer Basics

Transformer Tap Calculation‐Per Unit Concept Compensation (2) Change in CT Ratio

Ia, Ib, Ic

IA, IB, IC IA', IB', IC'

There must be an easier way…..

Ia', Ib', Ic'

Phase Differential Overview‐Transformer Basics

Transformer Tap Calculation‐Per Unit Concept

100MVA IN

100MVA OUT

Phase Differential Overview‐Transformer Basics

Transformer Tap Calculation‐Per Unit Concept

Tap Calculation with Wye CTs

WindingTap =

TransformerVA VL − L ∗ CTR ∗ 3

Tap Calculation with Delta CTs

TransformerVA WindingTap = VL − L ∗ CTR

Phase Differential Overview‐Transformer Basics

Transformer Tap Calculation‐Per Unit Concept

Each measured current is divided by the winding Tap. The result is a percent of rating. These percent of ratings can be compared directly.

Phase Differential Overview‐Transformer Basics

AB connected delta‐wye transformer

Phase Differential Overview‐Transformer Basics •

Subtracting Vectors: Subtract from reference phase vector the connected non-polarity vector…in our example Ia-Ib

c

-b

a

b • •

Can be repeated for B & C, or you can assume –120 and –240 displacement from A for B&C respectively Ib – Ic and Ic – Ia would be the vectors

Phase Differential Overview‐Transformer Basics

AC connected delta‐wye transformer Ia-Ic

Ia Ic-Ib Ia

Ia

Ib-Ia

Ic

Ib

Ib

Ib Ia

Ic-Ib

Ic Ib-Ia Ic

Ic

Ib

Ia-Ic

Phase Differential Overview‐Transformer Basics •

Subtracting vectors: Subtract from reference phase vector the connected nonpolarity vector…in our example Ia-Ic

c

a

b • •

-c Can be repeated for B & C, or you can assume –120 and –240 displacement from A for B&C respectively Ib – Ia and Ic – Ib would be the vectors

Phase Differential Overview‐Transformer Basics Angular Displacement Conventions: • ANSI Y‐Y, Δ‐Δ @ 0°; Y‐Δ , Δ‐Y @ X1 lags H1 by 30° – ANSI makes life easy



Euro‐designations use 30° increments of LAG from the X1 bushing to the  H1 bushings – Dy11=X1 lags H1 by 11*30°=330° or, H1 leads X1 by 30°

– Think of a clock – each hour is 30 degrees

0 11

1 2

10

3 Dy1 = X1 lags H1 by 1*30 = 30, or

9

H1 leads X1 by 30 (ANSI std.)

8

4 7

6

5

Phase Differential Overview‐Transformer Basics

C

A

c

a

b

B

US Standard Dy Example: • H1 (A) leads X1 (a) by 30 • Currents on “H” bushings are delta quantities Assume 1:1 transformer

Phase Differential Overview‐Transformer Basics US Standard Yd Example: •H1 (a) leads X1 (A) by 30 •Currents on “X” bushings are delta quantities C

c

a

B

b

Assume 1:1 transformer

A

Phase Differential Overview •

• •

Applied with variable  percentage slopes to  accommodate CT saturation  and CT ratio errors Applied with inrush and over  excitation restraints Set with at least a 20% pick up  to accommodate CT  performance – Class “C” CT; +/‐ 10% at 20X  rated

• •

If unit is LTC, add another +/‐ 10% May not be sensitive enough  for all faults (low level, ground  faults near neutral)

Phase Differential E‐M Relay Application  •





CT ratios and tap settings are selected to  account for: – Transformer ratios – If delta or wye connected CTs are  applied – Delta increases ratio by 1.73 Delta CTs must be used to filter zero‐ sequence current on all wye transformer  windings Dy transformer connections compensated  by yd CT connections to make the currents  “apples to apples”.

Phase Differential E‐M Relay Application  Zero‐sequence elimination:  In E‐M relays with wye connected transformers,  delta connected CTs are used to remove the ground current. 

Phase Differential Digital Relay Application  Settings compensate for the following: • Transformer ratio • CT ratio • Vector quantities – Which vectors are used – Where the 1.73 factor (√3) is applied • When examining line to line  quantities on delta connected  transformer windings and CT  windings



Zero‐sequence current filtering for  wye windings so the differential  quantities do not occur from  external ground faults

Phase Differential Digital Relay Application 

*1 *1 *2 *2

Angular displacement (IEC and SEL) • IEC (Euro) practice does not  have a standard like ANSI • Most common connection is  Dy11 (low lead high by 30!) • Obviously observation of  angular displacement is  extremely important when  paralleling transformers!

*1 = ANSI std. @ 0° *2 = ANSI std. @ X1 lag H1 by 30°, or “high lead low by 30 ° “

Digital Relay Application

All wye CTs shown, most can retrofit legacy delta CT applications

Benefits of Wye CTs • Phase segregated line currents – Individual line current oscillography – Currents may be easily used for overcurrent  protection and metering – Easier to commission and troubleshoot – Zero sequence elimination performed by  calculation 

Phase Differential Digital Relay Application  Zero‐sequence elimination:  In digital relays with wye connected  transformers and wye connected CTs, ground current must be removed from  the differential calculation. 

•3I0 = [Ia + Ib + Ic] I0 = 1/3 *[Ia + Ib + Ic]

•Used where filtering is required, such as wye winding with wye CTs

Phase Differential Digital Relay Application 

2nd and 4th Harmonics During Inrush

Typical Transformer Inrush Waveform

Phase Differential Digital Relay Application 

Harmonically Restrained Differential Element • Inrush Detection and Restraint – Inrush occurs on transformer energizing as the core magnetizes – Sympathy inrush occurs from adjacent transformer(s) energizing, fault  removal, allowing the transformer to undergo a low level inrush – Characterized by current into one winding of transformer, and not out  of the other winding(s) – This causes the differential element to pickup – Use inrush restraint to block differential element during inrush period

Phase Differential Digital Relay Application 

• Inrush Detection and Restraint – 2nd harmonic restraint has been employed for years – “Gap” detection has also been employed – As transformers are designed to closer tolerances, both 2nd harmonic  and low current gaps in waveform have decreased – If 2nd harmonic restraint level is set too low, differential element may  be blocked for internal faults with CT saturation (with associated  harmonics generated)

Phase Differential Digital Relay Application 

• Inrush Detection and Restraint 4th harmonic is also generated during inrush Odd harmonics are not as prevalent as Even harmonics during inrush Odd harmonics more prevalent during CT saturation Use 4th harmonic and 2nd harmonic together M‐3310/M‐3311 relays use RMS sum of the 2nd and 4th harmonic as  inrush restraint – Result:  Improved security while not sacrificing reliability

– – – – –

Phase Differential Digital Relay Application 

• Overexcitation Restraint

– Overexcitation occurs when volts per hertz  level rises (V/Hz) – This typically occurs from load rejection and  malfunctioning generation AVRs – The voltage rise at nominal frequency causes  the V/Hz to rise – This causes 5th harmonics to be generated in  the transformer as it begins to go into  saturation – The current entering the transformer is more  than the current leaving due to this increase in  magnetizing current – This causes the differential element to pick‐up – Use 5th harmonic level to detect overexcitation

Phase Differential Digital Relay Application  2.0

1.5

1.0

TRIP 87T Pick Up with 5th Harmonic Restraint

Slope 2

87T Pick Up RESTRAIN 0.5

Slope 2 Breakpoint Slope 1 0.5

1.0

1.5

2.0

Phase Differential Digital Relay Application 

• 87T Pick Up – – – –

Class C CTs, use 20% LTC, add 10% Magnetizing losses, add 1% 0.3 to 0.4 pu typically setting

• Slope 1 – Used for low level currents – Typically set for 25%

• Slope 2 “breakpoint” – Typically set at 2X rated current – This setting assumes that any current over 2X rated is a  through fault or internal fault, and is used to desensitize the  element against unfaithful replication

Phase Differential Digital Relay Application 

• Slope 2 – Typically set at 70%

• Inrush Restraint (2nd and 4th harmonic) – Typically set from 15‐20% – Employ cross phase averaging blocking for security

• Over‐excitation Restraint (5th harmonic) – Typically set at  30% – Raise 87T pick up to 0.60 pu during overexcitation – No cross phase averaging needed, as overexcitation is  symmetric on the phases

Phase Differential Digital Relay Application 

• Unrestrained 87H Pick Up – Typically set at 8‐10pu rated current – This value should be above maximum possible inrush current  and lower than the CT saturation current – C37.91, section 5.2.3, states 10pu an acceptable value – Can use data captured from energizations to fine tune the  setting

Phase Differential Digital Relay Application 

CT Issues: • Remnance:  Residual magnetism that causes dc saturation of the  CTs • Saturation:  Error signal resulting from too high a primary current  combined with a large burden • Tolerance:  Class “C” CTs are rated +/‐ 10% for currents x20 of  nominal  – Thru‐faults and internal faults may reach those levels depending on ratio  selected

Phase Differential Digital Relay Application 

CT Issues (cont.) • Best defense is to use high “Class C” voltage levels – C400, C800 – These have superior characteristics against saturation and  relay/wiring  burden

• Use low burden relays – Digital systems are typically 0.020 ohms

• Use a variable percentage slope characteristic to desensitize  the differential element when challenged by high currents that  may cause replication errors

Phase Differential Digital Relay Application 

“Point‐on‐Wave” Considerations During Energization • • •

As most circuit breakers are ganged three‐pole, each phase is closed at a  different angle resulting in less harmonics on one phase and more on the  others Low levels of harmonics may not provide inrush restraint for affected phase – security risk! Most modern relays employ some kind of cross‐phase averaging scheme to  compensate for this issue – – –

Provides security if any phase has low harmonic content during inrush or overexcitation This can occur depending on the voltage point‐on‐wave when the transformer is energized for a  given phase Cross phase averaging uses the average of harmonics on all three phases to determine level

Phase Differential Digital Relay Application 

Improved Ground Fault Sensitivity: • 87T element is typically set with 20‐40% pick up • This is to accommodate Class “C” CT accuracy  during a fault plus the effects of LTCs • That leaves 20‐40% of the winding not covered for  a ground fault • Employ a ground differential element to improve  sensitivity (87GD)

Phase Differential Digital Relay Application 

Switch‐onto‐Fault: • Transformer is faulted on energizing • Harmonic restraint on unfaulted phases may work  against trip decision if cross phase averaging is used – Un‐faulted phase will have no harmonics, other phases  may have high value

• Employ 87HS to protect winding that is being  energized • Employ 87GD on coupled winding if it is wye

Phase Differential Digital Relay Application 

Switch‐onto‐Fault (cont): • Employ 87HS to protect winding that is first energized • 87HS is set above inrush current • If fault is near the bushing end of the winding, the current will be higher  than inrush – Typically 9‐12 pu thru current



87HS does not employ harmonic restraint – Fast tripping on high current faults

Ground Differential Digital Relay Application 

• Use 87GD • IA + IB + IC = 3I0 • If fault is internal,  opposite polarity • If fault is external, same  polarity

IA IB

IC IG

Ground Differential Digital Relay Application 

IG

IA

IA

IB

IB

IC

IC IG

Internal

External

Ground Differential Digital Relay Application 

Restricted Earth Fault Trip Characteristic •

87GD Pick Up – Element normally uses directional comparison between phase  residual current (3I0) and measured ground current (IG) • No user setting

– Pick up only applicable when 3I0 current is below 140mA (5A  nom.) • Pick up = 3I0 - IG

– If 3I0 greater than 140mA, element uses: • –3I0 * IG * cosθ.  It will trip only when the directions of the  currents is opposite, indicating an internal fault • Using direction comparison mitigates the effects of saturation on  the phase and ground CTs

Ground Differential Digital Relay Application 

IA IB

Residual current calculated from individual phase currents. Paralleled CTs shown to illustrate principle.

90

IC IG

IG

3I0

180 -3IO

0

270

IG

Ground Differential Digital Relay Application 

90 -3IO IG 0

180

270

Other Transformer Protection Over current Elements

• Fuses – Small transformers ( 
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