Short T.A. Electric Power Distribution Handbook

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Distributed Generation 709

the timing and duration of pulses, the controller can shape the current

supplied to the system. A common three-phase conﬁguration is a three-phase

bridge (the same as Figure 14.3, but with IGBTs instead of thyristors). In a

grid-connected application, a PWM inverter can control the power factor; in

stand-alone, the inverter can operate alone and control voltage. PWM invert-

ers normally have switching frequencies from 1 to 10 kHz. They produce

little low-order harmonics, and the high-frequency harmonics near the

switching frequency can be ﬁltered with relatively small ﬁlters. Generally,

PWM designs have distortion well within IEEE Std. 519-1992.

Self-commutated inverters may be voltage controlled or current controlled.

The voltage-controlled inverter is simpler; the controller creates a reference

voltage. The current-controlled mode is more suitable for distributed gener-

ators; the controller uses the utility voltage as a reference and injects current

at the proper angle (usually at unity power factor). Current-controlled invert-

ers produce little fault current. Overcurrent protection removes current

almost immediately after an overcurrent (manufacturers implement this to

protect their equipment; IGBTs have very limited overcurrent capability).

The current pulse before the controller stops ﬁring is typically less than 2

per unit peak and lasts about 200 to 300 msec.

Self-commutated inverters are used on most smaller inverter-based gen-

erators. Very large units still require line-commutated inverters. With con-

tinued advances in power electronic switching technologies, larger units will

migrate to self-commutated designs.

Many three-phase inverter conﬁgurations are ungrounded, like the design

in Figure 14.3, which raises interfacing issues on grounded distribution

circuits. Often, ungrounded inverter conﬁgurations are interfaced with

grounded systems through a grounded-wye – delta transformer. This is a

grounding transformer; circulating currents in the delta allow the trans-

former to supply unbalanced load. Some inverter conﬁgurations are

grounded, such as those in Figure 14.4. Thyristors are shown, but PWM

inverters with the same conﬁgurations are common. Three single-phase

inverters can also supply grounded three-phase systems.

Whether an inverter or a rotating generator, all energy converter technol-

ogies have interconnection issues, just different ones. Table 14.2 summarizes

some of the most important issues for each major power converter type.

14.1.5 Modeling Small Generators

The simplest load-ﬂow model of distributed generators is as a negative load.

The normal load models include constant power, constant impedance, and

constant current. More accurate representations depend on the type of gen-

erator and its controls.

Since most synchronous DGs operate in a voltage-following mode with a

set injection of real and reactive power, the most accurate model is the

constant power model. In some programs, the power on each phase must

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710 Electric Power Distribution Handbook

FIGURE 14.4

Grounded inverter conﬁgurations.

TABLE 14.2

Power Converter Characteristics from an Interconnection Perspective

Feature

Synchronous

Generator

Induction

Generator Inverter

Ability to operate as

an isolated (stand-

alone) source

Exciter allows it to

operate as a stand-

alone island

Not intended for

stand-alone island

but still can

accidentally self-

excite if isolated with

a capacitor

Self-commutated

voltage source

inverters can

function as islands

Synchronism with

Utility

Must operate as a

synchronous source

Typically operated

with several percent

slip

Must operate as a

synchronous source

Fault contributions 4–8 times rated

current for a few

cycles

4–8 times rated

current for a few

cycles

Usually less than 2

times rated current

and very short

duration

Var injection and

control capability

Yes — by adjusting

exciter can regulate

vars and inject either

leading or lagging

power into system

No var control — is a

lagging source

(capacitors needed to

correct vars)

Some inverters can

vary var output and

provide reactive

support, most

operate near unity

power factor

Response speed to

load changes and var

needs

Exciter and throttle

require some time to

respond

Induction generator

does not have exciter

control. Throttle

response requires

time

Inverter can respond

almost instantly to

detected conditions

to control power and

vars if suitably

designed with energy

storage on bus

Active anti-island No No Yes

Source: EPRI PEAC, “Distributed Generation Course,” 2002.

dc source

Grounded three-phase inverter

Grounded single-phase inverter

dc source

ac output

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Distributed Generation 711

be speciﬁed. A somewhat more accurate model is to keep the total power

constant while the balance of the three phases is determined by the sequence

parameters of the generator (Chen et al., 1991). For induction generators, the

reactive power changes with voltage, but the changes are small enough that

they can be modeled as constant power devices. See Barker and Johnson

(2002) for more on modeling rotating machines for different scenarios.

If a synchronous generator is operated in a voltage-regulating mode, the

best load-ﬂow model is as a voltage-regulating, constant real power device.

The reactive power limits would also need to be speciﬁed.

A constant-power model accurately describes forced-commutated invert-

ers (for microturbines, fuel cells, photovoltaics, etc.), such as those using

pulse-width modulation. The inverters have control loops that control both

real and reactive power. Line-commutated inverters can also be modeled as

a constant power. They are limited in that they can only absorb reactive

power and cannot supply vars to the system.

Fault contributions of rotating generators can be modeled with most dis-

tribution short-circuit programs using the appropriate subtransient and tran-

sient characteristics of the generator. Short-circuit analysis can be done using

a standard short-circuit program. Although the addition of distributed

resources increases the time-varying nature of the fault current, it is not

enough to warrant using a stability or EMTP-type model for fault analysis.

Industrial systems with large local generators are still analyzed properly

with standard short-circuit analysis programs.

When considering the effects on protection coordination with distributed

generators, we can use standard protection programs. With fault contribu-

tions from only one source, curves of two overcurrent devices can be plotted

on a time–current curve that will demonstrate visually the coordination over

a range of currents. With contributions from different sources, it is more

difﬁcult to plot curves in a time–current graph. It is more useful to do a table

of operating times of different devices for faults at different locations.

More complicated transient modeling is sometimes warranted for large

machines or large penetration levels on distribution lines (especially on weak

circuits). Transient simulations provide better answers on possible problems

related to ferroresonance, voltage ﬂicker, stability, and islanding (EPRI TR-

111490, 1998; EPRI TR-112737, 1999).

14.2 Islanding Issues

Islanding is a major interconnection issue. Islanding is a situation where one

or more generators and a portion of the utility system operate separately

from the rest of the utility system. The formation of an unintentional island

is a problem for the utility company. The most important concerns are

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712 Electric Power Distribution Handbook

•Worker and public safety

• Damage to utility and customer equipment due to out-of-phase

reclosure

•Voltage problems

• High overvoltages to utility equipment and customers caused by

neutral shifts or ferroresonance

Distributed generators create danger for workers and the public. Line

crews might work on a section of line that they thought was de-energized.

A distributed generator could energize this line, even though it is discon-

nected from the utility source. The danger also extends to the general public.

Islanded generators may energize downed conductors within public reach

(that might have been de-energized by upstream utility switchgear had the

island not developed).

Once an island forms, it typically drifts out of phase with the utility system

voltage. If the main system is closed into the island, the out-of-phase reclo-

sure may cause damage to the generator, customer loads, and/or utility

switchgear as well as being a signiﬁcant power quality disturbance for cus-

tomers upstream of the island. An island may also prevent the clearing of

fault currents on the system, increasing damage at the location of the fault,

and perhaps burning conductors down.

The most common means to prevent islanding is to use voltage and fre-

quency relays on the generator to trip whenever either of these two param-

eters migrate outside a selected window. This form of islanding protection

is known as passive protection. It prevents islanding in most cases because

when a section of the distribution system and one or more generators sep-

arate together, the output of the generator will not match the load on the

island. For synchronous or induction generators, the voltage and frequency

will drift, which will trip the relays in a short time. Typically the relays are

set to a tight frequency range of perhaps +1 Hz or even +0.5 Hz. Voltage

relays have a bit wider window to allow for typical voltage regulation

excursions on the circuit (+5 to 10% is typical). Later in this chapter, speciﬁc

setting requirements per IEEE standards are discussed.

Synchronous generators, induction generators, self-commutated inverters,

and line-commutated inverters — all can island. Synchronous generators

and self-commutated inverters are most likely to island because they do not

require external excitation. Induction generators and line-commutated

inverters can island if they have external excitation, either from capacitor

banks or from other generators in the island.

14.2.1 Effect of Transformer Connections on Overvoltages

Generators fed from a transformer with an ungrounded high-side connection

can drive a normally grounded utility circuit as an ungrounded island. When

a single line-to-ground fault occurs on the distribution system and the sub-

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Distributed Generation 713

station breaker (or a recloser) opens, the system becomes a three-wire,

ungrounded system driven by the ungrounded generator. The fault moves

the potential of the ground to the phase potential (see Figure 14.5). That

leaves the line-to-neutral voltage on the unfaulted phases equal to the line-

to-line voltage ( = 1.73 times the normal line-to-neutral voltage).

The interconnection transformer conﬁguration and the generator ground-

ing determine if the application is effectively grounded. The most common

transformer conﬁgurations (the connection notation indicates the primary-

side connection, then the secondary-side [generator-side] connection) are

• Delta – grounded wye — Leaves the circuit ungrounded.

• Grounded wye – grounded wye — Can effectively ground the source

if the generator is effectively grounded. Is ungrounded if the gener-

ator is ungrounded.

• Grounded wye – delta — Provides the best way to effectively ground

a generator interconnection, but creates a ground source.

• Grounded wye – delta with a grounding reactor on the high-side wye —

Limits the ground fault source while still maintaining grounding.

Transformer/generator grounding involves a tradeoff. The best grounding

arrangements create sources for ground current that may interfere with

distribution protection. Limiting ground current creates an interconnection

that is not grounded as well (higher overvoltages).

Grounded-wye – grounded-wye transformers are widely used and famil-

iar to utilities. They are often the best connection if the generator is grounded.

If the generator neutral connection is not grounded or does not meet effective

grounding requirements, then the transformer bank does not effectively

FIGURE 14.5

An ungrounded generator connection driving an island with a line-to-ground fault.

Open utility

breaker

Line-to-ground

fault

Island

V = 0

V = 173%

Ungrounded DG source

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714 Electric Power Distribution Handbook

ground the source even though the neutral connections to the transformer

are grounded on both sides. Some rotating machines are not designed to

withstand the forces due to a line-to-ground fault on the generator terminals.

For this reason, they are grounded through an impedance or ungrounded

(so they are not effectively grounded). Some inverters need isolation from

ground and are not designed to operate with a grounded-wye winding on

the inverter side of the transformer. For grounded rotating machines, the

grounded-wye – grounded-wye connection also supplies signiﬁcant zero-

sequence current (it is a grounding source).

Generator installers often prefer the grounded-wye – delta transformer

(with the delta on the generator side). This connection grounds the connection

regardless of the generator grounding (the generator may be ungrounded or

grounded through an impedance to protect it from line-to-ground faults).

Other advantages are reduced harmonics, isolation between the primary and

secondary for ground faults, and a smaller voltage sag seen on the generator

terminals. The main drawback to using the grounded-wye – delta connection

is that it is a grounding bank; it feeds ground faults on the primary. This can

interfere with distribution system coordination and desensitize ground relays,

improperly blow fuses, or falsely operate sectionalizers, reclosers, or breakers.

Large circulating currents in the delta winding on the secondary (usually due

to ground faults) can also damage the interconnection transformer. Adding

a reactor to the neutral connection of the primary-side wye reduces the

grounding transformer effect while still maintaining acceptable grounding.

If generators interface through ungrounded transformer connections, the

preferred way to control overvoltages is with a ground overvoltage relay (a

59G, discussed in the next section).

Some large generators are applied right at distribution primary voltage,

without an interfacing transformer. This has the same effects as using a

grounded-wye – grounded-wye transformer. If the generator is ungrounded,

islanded overvoltages are possible. Solidly grounding the generator grounds

the source.

Arcing ground faults are another possible overvoltage mode on islands

supported by ungrounded generators. On ungrounded systems, intermittent

arcing grounds can create switching surge overvoltages from the restriking

of the arc (see Chapter 13). A system that is designed to be ungrounded has

only line capacitance between the phases and ground. An ungrounded island

has the line capacitance and line-to-ground load. The load may help control

arcing ground faults. If the island has grounded-wye capacitor banks, arcing

ground fault overvoltages may be more likely. This is an area that needs

more study.

14.2.1.1 Overvoltage Relays and 59G Ground Fault Detection

Distributed generators usually have over- and undervoltage relays. A typ-

ical overvoltage relay uses a type 59T time-delay relay with a pickup of 5

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Distributed Generation 715

to 10% above nominal voltage. The time setting should be set above the

normal clearing time of the feeder relays but less than the substation

breaker reclosing time. A reasonable setting is 30 to 60 cycles (ANSI/IEEE

Std. 1001-1988). It is best if an instantaneous element (59I) is also used,

although a higher setting (such as 40% above nominal) may be needed to

prevent excessive nuisance trips. For overvoltages, primary-side measure-

ments are best, especially if the primary winding is ungrounded. Secondary

measurements cannot detect the neutral shift on an ungrounded island

with a ground fault. To detect and trip on overvoltages, every phase must

have a relay, not just on an individual phase and not on an average of the

three phases. Undervoltage relays also provide backup for neutral-shift

overvoltages by detecting the voltage sag on the phase with the line-to-

ground fault.

The 59G relay detects neutral-shift overvoltages with the connection

shown in Figure 14.6. The grounded-wye – broken-delta potential trans-

former arrangement sums the three phase-to-neutral voltages.

The main drawback of relaying schemes is that the overvoltage still occurs;

even a short-duration overvoltage may damage some equipment. The over-

voltage duration is limited by the speed of the relays and breaker. Depending

on the speed of the relaying, these limits may not coordinate with the tem-

porary overvoltage capability of some arresters or sensitive customer equip-

ment. Also, if the relaying fails to operate, the overvoltage could last for

some time. Another disadvantage of this approach is that primary-side

potential transformers are required. Because of this, many utilities avoid

ungrounded transformer connections.

FIGURE 14.6

Ground fault overvoltage detection scheme (59G).

Primary-side PT bank

Grounded wye -- Broken delta

Zero sequence

components in phase

59G

Generator trip signal

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716 Electric Power Distribution Handbook

14.2.1.2 Effectively Grounding a Grounded-Wye – Grounded-Wye

Transformer Connection

Effectively grounded systems limit the overvoltage caused by a neutral shift

to 25% above nominal. In effectively grounded systems the ground fault

current is 60% or more of the available three-phase fault current. A grounded-

wye – grounded-wye transformer is effectively grounded if the generator

applied to it meets effective grounding requirements. The conditions for

effective grounding are approximately (ANSI/IEEE C62.92-1987):

£ 3 and R

£ 1

For effective grounding during islanding for a ground fault on the primary

terminals, the generator must be solidly grounded or the impedance must

be small enough to meet the criteria above. For a rotating generator with a

grounding reactor, the criteria (EPRI 1000419, 2000) is

£ X

+ X

- X

/3 -

where

= generator neutral reactance

= transformer zero-sequence reactance

= transformer positive-sequence reactance

= generator zero-sequence reactance

= generator positive-sequence reactance

14.2.1.3 Sizing a Neutral Grounding Reactor on a Grounded-Wye –

Delta Connection to Maintain Effective Grounding

A grounding reactor added to a grounded-wye – delta transformer limits the

zero-sequence fault contribution and limits the circulating current in the delta

winding. In order to ensure that the connection still maintains an effectively

grounded system during a possible island, the grounding reactor cannot be

too large. The criteria for effective grounding is: X

£ 3. This depends on

the characteristics of the generator and interconnection transformer. For a

primary ground fault at the transformer, the sequence impedances are

= X

+ 3X

= X

+ X

where

= neutral reactance

= transformer zero-sequence reactance

= transformer positive-sequence reactance

= generator positive-sequence reactance

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Distributed Generation 717

To keep the interconnection effectively grounded, limit the size of the

reactor according to (EPRI 1000419, 2000):

£ X

+ X

- X

Note that this only guarantees effective grounding for a fault right at the

grounding transformer. For faults at other points on the feeder, add the zero

and positive-sequence line impedances between the fault location and the

generator to X

and X

If line impedances are considered, then the zero-

sequence line resistance should also be considered. In the equations above,

the resistance portion has been ignored because the X/R ratios on generators

and transformers are high. Another requirement for effective grounding is

that R £ 1. Normally, these are small, so we can ignore them except for a

very large generator on a weak system.

14.2.2 Anti-Islanding Protection

At most sites, voltage and frequency relays are the main protection against

islanding. When a utility protective device opens and leaves an island, nor-

mally, the generation and load will not match. If the generation exceeds the

load, the voltage rises and the generators speed up. The opposite occurs if the

load exceeds the generation. In either case, when voltage or frequency goes

outside of normal limits, voltage or frequency relays should trip the generators.

Over- and undervoltage relays are an important line of defense against

islanding. Typically, this consists of

• Overvoltage time-delay relay (59T) — A pickup of 5 to 10% above

nominal voltage is generally used. The time setting should be set

above the normal clearing time of the feeder relays but less than the

substation breaker reclosing time. A reasonable setting is 1/2 to 1 sec.

• Instantaneous overvoltage element (59I) — An instantaneous overvolt-

age element is recommended (but not always used). A higher setting

(such as 40% above nominal) may be needed to prevent excessive

nuisance trips.

• Undervoltage time-delay relay (27T) — A pickup of 5 to 10% below

nominal voltage is generally used. Similar time settings should be

used as the overvoltage time-delay relay.

• Instantaneous undervoltage relay (27I) — As with the overvoltage

instantaneous element, a loose setting is necessary to prevent nui-

sance trips (30% below nominal is reasonable).

The time-delay relays are time delays; they are not inverse-time relays. If

the voltage on a 59T relay is above the magnitude setting for longer than

the time setting, it trips. If the voltage drops back below the magnitude

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718 Electric Power Distribution Handbook

setting, the timer resets after the given reset time. Many generator-protection

relays allow multiple pairs of magnitude and time-delay settings to achieve

a stair-step voltage-time characteristic.

For overvoltages, it is best if the detecting potential transformers are on

the primary side of the generator transformer (especially if the primary

winding is ungrounded). For example, the neutral shift on an ungrounded

island with a ground fault will not be detected on the secondary side of the

transformer. To detect and trip on overvoltages, individual relays should be

on each of the three phases (not just on an individual phase and not on an

average of the three phases). The undervoltage relays will also provide

backup for neutral-shift overvoltages by detecting the voltage sag on the

phase with the line-to-ground fault.

The over- and underfrequency relay (81U/O) is another line of defense

against islanding. Trip thresholds of ±1% are common. Wide ranges of time

delays are used for a 1% setting: 0.1 sec to many seconds. Some utilities

specify a wider range for the underfrequency setting to allow the generator

to stay in for low-frequency events caused by system-wide disturbances. The

low frequency indicates a need for generation, so it helps to have the dis-

tributed generation remain connected.

Integrated generator relay packages are available from several manufac-

turers. These provide voltage and frequency relays along with other inter-

connection functions such as synchronization (and possibly all of the

generator protection functions as well).

EEI (2000) provides guidance for applying anti-islanding relaying and

other interconnection equipment for several different types of generators

and interconnection transformers.

With voltage and frequency relays, there is still some chance that evenly

balanced generation and load can drive islands. Because voltage and fre-

quency relays are not 100% reliable, some large distribution generators have

transfer-trip protection schemes. Breakers (or reclosers) upstream of the gen-

erator send a trip signal to the generator — if the breaker operates, it trips

the generator. This requires a reliable communication line between the

breaker and the generator.

14.2.3 Active Anti-Islanding

Inverter-based generators can use more sophisticated ways to detect islands.

If the generation and load are almost equal, an island may take some time

to drift in voltage and frequency. Active anti-islanding inverters attempt to

push the voltage and/or frequency out of normal limits. Under normal

conditions, the inverter cannot budge the voltage or frequency; with the

inverter connected to the utility system, the utility system ﬁxes the voltage

and current (assuming the utility system is much bigger than the generation).

The most promising active anti-islanding techniques are the Sandia volt-

age-shift and frequency-shift methods (Stevens et al., 1999). These use pos-

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