Short T.A. Electric Power Distribution Handbook

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Distributed Generation 719

itive feedback to make the voltage or frequency unstable if an island is being

driven by generators with this form of anti-islanding. The unstable generator

in an island pushes the voltage or frequency out of range, where standard

voltage or frequency relays trip the generator. Because it uses positive feed-

back, the Sandia method allows several of these inverters to work together.

Other methods may act to cancel each other; some might try to raise fre-

quency while others try to lower it.

With the frequency-shift method, if the inverter detects that the frequency

is increasing (even slightly), the controller injects a current with an even

faster frequency. On a weak system, the current controller starts to control

the frequency; and in this example, the inverter forces high frequency on an

island, which trips the frequency relays.

Fast voltage control devices on distribution circuits may counteract

attempts to change the voltage by inverter-based generators. Most regulators

and capacitor banks are too slow to interfere in this manner. But, other

generators operating in a voltage control mode will hold the island voltage

intact. Rotating generators and voltage-source inverters act to stabilize the

island’s frequency and voltage.

IEEE Std. 929-2000 and UL 1741 (2001) specify an active anti-islanding test

for inverter-based relays designed to test any kind of active anti-islanding

inverter. Under balanced generation and load and a resonant capacitor-

inductor tuned to the fundamental frequency (which tends to hold the fre-

quency), the inverter must disconnect within 2 sec. The test does not verify

the performance of multiple inverter-based generators in parallel (with the

same type of anti-islanding or with different types of anti-islanding). And,

the test does not verify the performance of anti-islanding with rotating

generators or motors in the island.

14.2.4 Relaying Issues

Recent industry standards for distributed generator interconnection have

speciﬁed standard trip thresholds. This is an effort between manufacturers

and utilities to ease the complications of interconnection. IEEE 929 and UL

1741 have recommended the thresholds in Table 14.3. The 929 recommenda-

TABLE 14.3

Standard Trip Thresholds for Distributed Generators per the IEEE Std. 929-2000

and UL 1741 (2001)

Voltage Setting Trip Time

Volts (120-V Nominal) Percent Cycles Seconds

V< 60 V < 50% 6 cycles 0.1 sec

60 £ V< 106 50% £ V< 88% 120 cycles 2 sec

106 £ V £ 132 88% £ V £ 110% Normal Operation Normal Operation

132 < V < 165 110% < V < 137% 120 cycles 2 sec

165 £ V 137% £ V 2 cycles 0.033 sec

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720 Electric Power Distribution Handbook

tions are targeted at photovoltaic systems rated at 10 kW or less. UL 1741

applies to all inverter-based generators.

IEEE 929 speciﬁes the voltage measurements at the point of common

coupling. UL 1741 speciﬁes a test for an inverter-based DG. No mention is

made of the exact measurement location, but it implies measurement at the

generator. UL 1741 speciﬁes line-to-ground voltages for three-phase connec-

tions, and the DG should cease exporting when any of the three voltages

exceeds the limits in Table 14.3. At the time of this writing, IEEE is working

on a standard for all generators, and the trip thresholds are similar; Table

14.4 shows the draft settings.

The main concerns with the standard overvoltage trip thresholds are that

• The 110% trip limit on overvoltages allows generators to create volt-

age in excess of ANSI limits (ANSI C84.1-1995).

• The draft P1547 allows a relatively long time (0.16 sec or 9.6 cycles

for 60 Hz) for overvoltages above 120% to exist. IEEE 929 and UL

1741 both require the generator to cease injecting power within 2

cycles if the relay detects an overvoltage greater than or equal to 138%.

Where should relays measure? Right at the generator is easiest, but not

always best. To avoid islanding problems with large three-phase generators,

measurement on the distribution primary is best. Transformer connections

can distort the voltages and make relaying harder; secondary-side measure-

ment on a delta – wye or wye – delta transformer connection cannot detect

the overvoltages or undervoltages from a neutral shift on the primary. A

second transformer with a delta – wye connection between the utility trans-

former and the generator interconnection point further distorts the voltages.

The distribution primary is usually the most sensitive location for measuring

distribution-system overvoltages and undervoltages.

Overall, the best place for relay monitoring is on the primary using line-

to-ground voltages. Smaller generator applications (< 1 MW) may use other

TABLE 14.4

Trip Thresholds for Distributed Generators

Based on IEEE P1547-D11-2003

Voltage Setting Trip Time

V< 50% 0.16 sec

50% £ V< 88% 2 sec

110% < V < 120% 1 sec

120% £ V 0.16 sec

Note: Base voltages are the nominal voltages stat-

ed in ANSI C84.1. DR £ 30 kW: Maximum

Clearing Time. DR > 30 kW: Default Clear-

ing Time or the utility operator may specify

different voltage settings or trip times to

accommodate utility requirements.

1791_book.fm Page 720 Monday, August 4, 2003 3:20 PM

Distributed Generation 721

measuring locations, but consider the transformer connections to ensure

effective relay sensitivity. Secondary measurements (either at the generator

or at the service entrance) are appropriate for very small generators.

Another one of the questions about relaying set points is whether to use

line-to-line voltages, line-to-ground voltages, or both. Generally, line-to-

ground voltages are more sensitive, so they should be used, but it is not

always straightforward. Figure 14.7 shows where a neutral shift has occurred

on the distribution system to a line-to-ground fault. Phase A has a voltage

sag, and phases B and C have voltage swells due to the neutral shift. This

FIGURE 14.7

Line-to-line and line-to-ground voltages on the primary and secondary of several transformer

connections for an overvoltage due to a neutral shift for a fault on primary phase A. (Copyright

Power Quality. Reprinted with permission.)

Primary Voltages Secondary Volt

=30.0%

=140.4%

=128.6%

=94.5%

=100.0%

=88.7%

=30.0%

=140.4%

=128.6%

=94.5%

=100.0%

=88.7%

=94.5%

=100.0%

=88.7%

=100.0%

=94.5%

=88.7%

=100.0%

=94.5%

=100.0%

=88.7%

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722 Electric Power Distribution Handbook

is a more severe neutral shift than is usual on a four-wire multigrounded

distribution circuit; it could represent an island being driven by distributed

generators. If a grounded-wye – grounded-wye transformer is used, the line-

to-ground voltages on the secondary are most sensitive. If a delta –

grounded-wye transformer is used, the line-to-line voltages on the secondary

are slightly more sensitive (although, overall the ability to sense primary

line-to-ground overvoltages is reduced by the delta – wye connection). A

grounded-wye – delta connection has line-to-ground voltages more sensitive

to the overvoltage (again, the ability to sense primary line-to-ground over-

voltages is reduced because of the transformer connection). The voltages

shown assume that the DG does not change the voltage on the primary or

secondary, when in reality the DG will normally be changing the voltage on

the secondary and maybe even the primary.

One important point is that all three voltages must be measured (whether

they are line-to-line or line-to-ground voltages). If voltages are assumed

balanced and only one of the three voltages is used, sustained overvoltages

could occur on the unmonitored phases.

Power quality disturbances also impact generators because the generator

must trip for voltage excursions. An analysis of EPRI’s Distribution Power

Quality (DPQ) data showed that the number of generator trips at most sites

is not particularly severe. Generators at most sites should have less than ﬁve

trips per year when using the UL 1741/IEEE 929 or IEEE P1547 settings (see

Figure 14.8). Trips become excessive only if the generator undervoltage relay-

ing is set at a very sensitive level.

Distributed generators based on inverters can do much of the interconnec-

tion relaying in the inverter controller. Utilities worry about inverter-based

relays, mainly because

• Inverter-based relays are not utility-grade.

•Testing in the ﬁeld is very difﬁcult. (They do not have external test

points for relay test sets.)

Inverter-based relays do have the advantage that they can perform anti-

islanding relaying as discussed in the previous section.

Many utilities require utility-grade relays for small installations, and essen-

tially all require them for large installations. But, what is a utility-grade relay?

There is no ﬁxed deﬁnition, but normally, they must pass industry standards

(ANSI/IEEE C37.90-1989; ANSI/IEEE C37.90.1-1989; IEEE Std. C37.90.2-

1995). Utility-grade relays are normally more robust than industrial relays

and have test ports for external testing.

Inverter-based generators do not have external test ports for testing. Sep-

aration of the relaying component from the other controller functionalities

is difﬁcult to do because the inverter controller uses the voltage and current

sensing for other control aspects.

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Distributed Generation 723

14.2.5 Self-Excitation

During islanding, the generator can resonate with system capacitor banks

(see Figure 14.9). This series resonance can happen with any type of inter-

connection transformer conﬁguration, with or without ground faults on the

system. The simplest resonance is a series resonance between the generator

subtransient impedance and system capacitors. Load on the island helps

hold the voltage down, so the highest voltages occur under light load.

Transformer saturation is not enough to signiﬁcantly reduce this type of

FIGURE 14.8

Comparison of the number of generator trips with the IEEE 929/UL 1741 voltage/time thresh-

Electric Power Research Institute. 1005917. Distributed Generation Relaying Impacts on Power

Quality. Reprinted with permission.)

FIGURE 14.9

Series resonance between a generator and capacitor bank during islanding.

trips for V<88%

and t>0.05s

trips for

V<88% and t>0.1s

929/1741

0 20 40 60

100

Average number of events per year

exceeding the given criteria

Percent of locations

exceeding the x-axis value

High

voltage

Low impedance,

high current

Voltage

source

Series Resonance

Open

1791_book.fm Page 723 Monday, August 4, 2003 3:20 PM

724 Electric Power Distribution Handbook

overvoltage. This resonance is also referred to as self-excitation, the same

phenomenon seen on induction motors with capacitor banks. It is also similar

to a resonance seen on distribution feeders that feed low-voltage secondary

networks and have capacitor banks. After a fault, the backfeed through the

network transformers can resonate.

The circuit resonates when the power-frequency impedance of the capac-

itor equals the impedance of the inductance. And, overvoltages still occur

even if the impedances do not exactly match. A criteria to determine if self-

excitation may occur is that the ratio of capacitance to inductance is within

a ratio of one to two (in either direction):

0.5 < X

< 2

where

= impedance of the capacitor banks = (kV

)

/(Mvar)

= impedance of the system inductance, which includes the generator

impedance, the transformer impedance, and the line impedance

between the generator and the capacitor bank

Load on the circuit helps hold down the overvoltage. For example, if the

load is entirely resistive (R), the magnitude of the per unit overvoltage at

the capacitor is

For cases where problems might occur, some options are

• Reactance — Change the reactive impedance (generator size or trans-

former impedance).

• Capacitors — Remove or change the size of the capacitor banks.

• Relaying — Rely on the overvoltage relaying to remove the generator

during an overvoltage condition. Use an instantaneous element

(59I), apply relays on each of the three phases, and use potential

transformers for the relays on the primary side of the interconnection

transformer.

During a line-to-ground fault with an ungrounded transformer connection,

a different resonant mode can occur (Dugan and Rizy, 1984). The circuit

resonates with a different combination of impedances. The zero-sequence

capacitance resonates against a combination of the positive- and negative-

sequence impedances and capacitances (see Figure 14.10). This overvoltage

adds to any overvoltage due to a neutral shift.

RX X R X

LC L

-+()

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Distributed Generation 725

The zero-sequence capacitance is most likely from grounded capacitor

banks, but long cable runs may have enough capacitance. The solutions given

above for positive-sequence resonances also help with this zero-sequence

resonance. Another option for this zero-sequence resonance is to unground

capacitor banks (to eliminate the zero-sequence capacitance).

14.2.6 Ferroresonance

A generator in an island can drive the circuit into ferroresonance (Feero and

Gish, 1986; Wagner et al., 1989). The peak voltage during this ferroresonance

can reach three per unit. Both induction and synchronous generators can

FIGURE 14.10

Series resonance between a generator and capacitor banks during a line-to-ground fault on an

ungrounded islanding.

Line-to-ground

Fault

Ungrounded

distributed generator

Utility source

XjKLjKLXjC

KL KL C

=+ =

ww w

11 22 0

/( )

()

1791_book.fm Page 725 Monday, August 4, 2003 3:20 PM

726 Electric Power Distribution Handbook

create ferroresonance, and it can occur with all three phases connected (single

phasing is normally involved with ferroresonance). The resonance can occur

no matter how the generator interconnection transformer is conﬁgured

(although the overvoltage is worse if the ferroresonance occurs simulta-

neously with a neutral shift on an ungrounded island). Four conditions are

necessary for DG islanding ferroresonance to occur:

1. The island driven by the generator must be isolated from the utility.

2. The generator must supply more power than there is load on the

island.

3. The isolated circuit must have enough capacitance to resonate (30

to 400% of the generator rating). This can be due to utility capacitor

banks or from capacitor banks at the generator.

4. A transformer group must be present in the island.

The ferroresonant circuit is very similar to the self-excited case in Figure

14.9, with the only addition being the distribution transformer group. When

the generator and the capacitance resonate, the overvoltage on the distribu-

tion circuit causes the transformer to saturate. The saturated transformer has

a low impedance. Consider it like a switch: when it is saturated, it is a short

circuit; when it is not saturated, it is an open circuit. The switching action

of the saturating transformer causes the chaotic ferroresonant type wave-

form. Ferroresonance tends to widen the range of capacitance over which

the generator can resonate with the capacitor bank.

Solution options for this type of ferroresonance include

• Reconﬁguration — Changing the distribution system characteristics

to change the criteria given above (limit or expand the area that

could island or remove or change the size of the capacitor bank).

• Relaying — Rely on the overvoltage relaying to remove the generator

during an overvoltage condition. Use an instantaneous element

(59I), apply relays on each of the three phases, and use potential

transformers for the relays on the primary side of the interconnection

transformer.

14.2.7 Backfeed to a Downed Conductor and Backfeed Voltages

During a line-to-ground fault where one phase opens (either due to a fuse

operation or a broken conductor), backfeed through a three-phase generator

can cause issues on distribution systems. While this type of backfeed occurs

without distributed generators (see Chapter 4), distributed generators make

backfeed more likely.

With a distributed generator on the load side of the transformer, the back-

feed current and voltage (EPRI 1000419, 2000) is

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Distributed Generation 727

where

A =

= positive-sequence impedance of the generator, W

= negative-sequence impedance of the generator, W

= zero-sequence impedance of the generator and load, W

= fault resistance, W

V = line-to-neutral voltage, V

= line-to-neutral voltage equivalent of the generator, V

Under an open circuit (R

= •), the backfeed voltage is

The presence of the distributed generator strengthens the backfeed current

and voltage. The generator provides a source of voltage, and the impedance

of a rotating generator (especially the low zero-sequence and negative-

sequence impedances) increases the backfeed. An induction generator does

not require supplementary excitation (capacitance) to backfeed under these

circumstances.

Having a 59G ground overvoltage trip relay, a directional (or even nondi-

rectional) ground relay, and phase undervoltage relays should trip the circuit

in most cases of backfeed. It is best if relaying trips the primary-side protec-

tive device (usually this is a breaker) rather than just tripping the generator,

since backfeeds can still occur through the transformer even if the generator

is taken ofﬂine.

14.3 Protection Issues

Figure 14.11 shows a scenario where a distributed generator may falsely

operate an upstream breaker, recloser, fuse, or sectionalizer for a fault just

upstream of the protective device.

The fault current from the generator (and through the upstream protective

device) for a three-phase fault can be found by the following equation:

= V/Z

AZZVZZV

ZZZ RA

VRI

FFF

()33

02 02

012

ZZ ZZ ZZ

01 12 02

AZZVZZV

-+()33

02 02

1791_book.fm Page 727 Monday, August 4, 2003 3:20 PM

728 Electric Power Distribution Handbook

where

= positive-sequence impedance between the generator and upstream

device. This includes the equivalent generator impedance reﬂected to

the primary-side voltage, the transformer impedance, and the line

impedance from the generator to the upstream device.

V = line-to-ground voltage

This assumes that the generator voltage source is the same as the utility

voltage source. A more conservative and appropriate choice is

= 1.1 V/Z

since the internal voltage behind the generator is normally higher than one.

For synchronous generators, use the subtransient reactance, Z

= jX

For a line-to-ground fault, it is more complicated because current can

“route through” the generator impedances. The sequence diagram for this

situation is shown in Figure 14.12. The sequence currents from the gener-

ator are

where

Z' = Z

||Z

+ Z

||Z

+ Z

||Z

, Z

= zero, positive, and negative-sequence impedances upstream

of the fault. This includes the line impedance, the substation

FIGURE 14.11

Power Research Institute. Engineering Guide for Integration of Distributed Generation and Storage

Into Power Distribution Systems. Reprinted with permission.)

Utility source

side

breaker, recloser,

sectionalizer, or fuse

fault

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