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Protective Relaying for

DERRogerio Scharlach

Schweitzer Engineering Laboratories, Inc.

Basking Ridge, NJ

Overview

• IEEE 1547 general requirements to be

met at point of common coupling (PCC)

• Distributed resource (DR) response to

area electric power system (EPS)

abnormal conditions

Overview

• Distributed generation (DG) impact on

distribution feeders

• Real Life Operation of DR Interconnection

Protection

• Introduction to Symmetrical Components

IEEE 1547 General Requirements

to Be Met at PCC

• Voltage regulation

• Integration with area EPS grounding

• Synchronization

• Inadvertent energization of area EPS

• Monitoring provisions

• Isolation devices

• Interconnection integrity

DR Response to Area EPS

Abnormal Conditions

• Faults

• Reclosing

• Voltage excursions

• Frequency excursions

• Loss of synchronism

• Reconnection to area EPS

DR Response to Area EPS Faults

DR unit shall cease to energize area EPS

for faults on area EPS circuit to

which it is connected

DR Response to Area EPS Reclosing

DR shall cease to energize area EPS

circuit to which it is connected prior to

reclosing by area EPS

DR Response to Voltage Excursions

• Voltage parameters are to be met at PCC

• Interconnection system responds to rms

or fundamental voltage

♦ Phase to phase

♦ Phase to neutral

Voltage Range (% of base voltage) Clearing Time (s)

V < 50 0.16

50 ≤ V ≤ 88 2.00

110 ≤ V ≤ 120 1.00

V ≥ 120 0.16

DR Response to Frequency Excursions

DR shall cease to energize area EPS when

system frequency is in particular range

DR Size Frequency Range (Hz) Clearing Time (s)

≤ 30 kW> 60.5 0.16

< 59.3 0.16

> 30 kW

> 60.5 0.16

< 59.8 to 57.0

(adjustable)

0.16 to 300

(adjustable)

< 57.0 0.16

DR Response to Loss of Synchronism

• In this case, DR response

♦ Applies only to synchronous generators

♦ Is primarily a risk to generators

• Standard addresses this condition as being

of concern only if it results in voltage

fluctuations that violate flicker limitations

DR Reconnection to Area EPS

• Reconnection is delayed up to 5 minutes

after area EPS steady-state voltage and

frequency are restored

• Ranges include

♦ Frequency – 59.3 to 60.5 Hz

♦ Voltage – see ANSI C84.1-1995, Table 1

Power Quality

• Limitation to dc injection

• Limitation of flicker induced by DR

• Harmonics

Islanding

• Unintentional

• Intentional

DG Impact on Distribution Feeders

• Increased fault duty

• Unintentional islanding

• Relay desensitization

• Nuisance tripping

• Automatic reclosing

• Voltage regulation and flicker

• Ferroresonance

Increased Fault Duty

• Is caused by addition of generating sources

and rotating machinery of considerable size

• Affects capability of equipment to carry and

interrupt fault currents

• Requires both local and area EPS

equipment ratings to be reevaluated

Unintentional Islanding

• Occurs when portion of area EPS and DR

become electrically isolated from rest of area

EPS and DR continues to energize island

• Should be avoided for two major reasons

♦ There is potential for negative effects on voltage,

frequency, and power quality

♦ Islanded generator complicates both automatic

reclosing and manual switching

Relay Desensitization

• Available short-circuit current increases with

addition of DR

• Short-circuit current splits between

substation and DR

• Substation short-circuit contribution can be

significantly reduced when compared with

value before addition of DR

Relay DesensitizationFault Current Distribution Without DR

323

R1

R2Substation

F1

Three-Phase 3I0

323 A 198 A

198

Relay DesensitizationFault Current Distribution With DR

199

R1

R2Substation

F1Three-Phase 3I0

199 A 24 A

24

200

246

Substation

Three-Phase 3I0

200 A 246 A

DR 399

270

DR

Nuisance TrippingWithout DR

762

R1

R2Substation

F2

Three-Phase 3I0

762 A 616 A

“616”

Nuisance TrippingWith DR

762

R1

R2Substation

Three-Phase 3I0

762 A 616 A

“616”

768

“0”

Substation

Three-Phase 3I0 – 3E0

768 A 0 A – 0.729 pu

DR

F2

3E0

1530

“616”DR

Operation for Fault in Adjacent Zone

SYS

DR

1

2

3

ISYS

ISYS + IFAULT

IFAULT

IFAULT

Automatic Reclosing

• DR should be disconnected before open

interval expires

♦ By interconnection protection (81U, 81O, 59, 27)

♦ By DTT

• Minimum open or dead time to allow arc

deionization and to avoid restrike is

Automatic Reclosing

• If DR can form sustainable island when

separated from system, restoration

becomes issue

• Utility feeder breaker has to be equipped

with synchronism-check element and / or

live-bus and dead-line logic

• OR combination of both elements works as

permissive for reclosing utility feeder breaker

Automatic ReclosingClose Permissives

• Feeder and bus are in synchronism

• Utility bus is hot and line is dead

DR

Utility

Bus

Live Bus /

Dead Line or

Synchronism

3

3

Multifunction

Relay

C T

1

Temporary

Fault

Real Life Operation of DR

Interconnection Protection

PVArray

IsolationTransformer

NeutralGrounding

Reactor

I VY VZ

Pole-mountedRecloser

Recloser Control

59G

51P

51G

275981

Ø-G Fault

Simplified Single-Line Diagram

380 Vac 13,800 Vac

T C

OverheadDistribution

Feeder

Recloser Control Simplified Trip Logic

27-1

27-2

59-2

59-1

81-1

81-2

81-3

59G

51P

51G

OR

OR

OR

TRIP

RECLOSER

Relay Settings

Element Setting Delay Description

27-1 50% 108.33 ms Definite time undervoltage level 1

27-2 88% 1.950 s Definite time undervoltage level 2

59-1 110% 950 ms Definite time overvoltage level 1

59-2 120% 108.33 ms Definite time overvoltage level 2

81-1 57 Hz 78.95 ms (@ 57 Hz) Definite time underfrequency level 1

81-2 58.5 Hz 102.6 s (@ 58.5 Hz) Definite time underfrequency level 2

81-3 60.5 Hz 74.38 ms (@ 60.5 Hz) Definite time overfrequency

59G 8,200 V 1.33 s Definite time residual ground overvoltage

51P 60 A NA Inverse time phase overcurrent

51G 19.8 A NA Inverse time residual ground overcurrent

Relay Underfrequency Settings

Feeder Fault (C-Ground)

Undervoltage Element Pickup Time

15.62 ms

Undervoltage Element Time Delay

108.33 ms

Recloser Interruption Time

17.71 ms

Total Clearing Time

141.66 ms

Introduction to Symmetrical

Components

• The solution of balanced multi-phase

systems can be accomplished using single-

phase methods

• The method of symmetrical components

allows unbalanced multi-phase systems to

be solved using single-phase methods.

♦ Introduced in 1918 by C.L. Fortescue

Insight

“… it is shown that unbalanced problems can be

solved by the resolution of the currents and

voltages into certain symmetrical relations. When

the constants are symmetrical, that is, when the

system viewed from any phase is similar, then the

symmetrical components of currents do not react

upon each other so that it becomes possible to

eliminate the mutual relations with their attendant

complication in the solution of the problems.”

—C.L. Fortescue

Decomposition of an Unbalancedd

System

Symmetrical Components as a

Function of Phase Quantities

Phase Quantities as a Function of

Symmetrical Components

Phase-to-Ground Fault

Two-Terminal System

+

-

Zero Sequence Network During the Fault

Z0S Z0DR

Z0TR

H

H0

3 x ZN

V0Z

N0

X

I0DR= 0

ΔV0 = I0R* (3 x ZN + Z0TR)

CLOSED CLOSED

CB R

I0S≠ 0

I0S + I0R |V0Z| before trip = 2400 V < 2,735 V (pick up)|V0Z| after trip = 3200 V > 2,735 V (pick up)

ΔV0

Residual Ground Overvoltage

Sample DER Interconnected Through

a Delta/ Wye Transformer

PVArray

IsolationTransformer

I VY VZ

Pole-mountedRecloser

Recloser Control

59G

51P

51G

275981

Ø-G Fault

Simplified Single-Line Diagram

T C

OverheadDistribution

Feeder

Z1S

Z1L

Z1DR

Z1TR

Z2S

Z2L

Z2DR

Z2TR

Z0S

Z0L

Z0DR

Z0TR

CB

I1S= 0

I2S= 0

I0S= 0

I1DR= 0

I2DR= 0

I0DR= 0

I0R= 0

V2

V1

V0

E

What is the

3V0 at the

Recloser

Location

After Utility

Separation?

OPEN

OPEN

OPEN

CLOSED

CLOSED

CLOSED

CB

CB

R

R

R

H

X

H0

Conclusions

• There are several requirements to be met

by DR at PCC location

• DR has to respond to abnormal conditions

of area EPS

• Addition of DR to distribution feeder affects

its protection, voltage regulation, fault duty,

reclosing scheme, and so on

Conclusions

• Event report analysis is a great tool to

validate DER interconnection protection

settings

• Unbalanced phasors can be broken down

into their symmetrical components

• Symmetrical components allow the use of

simple single-phase calculations for

analysis of unbalanced systems

• The resultant symmetrical components can

be recombined into the phase components

Questions?

Questions to the audience

• Please provide 3 examples of DR impacts

on distribution feeders.

• Please provide 3 examples of area EPS

abnormal conditions that the DR has to

respond to.

• Can a DR immediately reconnect following

a successful feeder restoration? If not, how

long is the qualifying time delay? What are

the quantities monitored during the

qualifying time delay?

Questions to the audience

• According to the theory of Symmetrical

Components, an unbalanced set of currents

can be decomposed in three other

components. What are these components?

• How are the sequence networks

interconnected to represent a phase-to-

ground fault?