Short T.A. Electric Power Distribution Handbook

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Distributed Generation 729

transformer impedance, and the transmission equivalent

impedance

, Z

= zero, positive, and negative-sequence impedance between

the generator and fault. This includes the equivalent genera-

tor impedance reﬂected to the primary-side voltage, the

transformer impedance, and the line impedance from the

generator to the upstream device

The phase relay on the faulted phase sees the following current:

faulted phase

= I

+ I

The ground relay operates on

ground relay

= 3I

While the line-to-ground fault current is normally smaller than the three-

phase fault current, it is important because of

FIGURE 14.12

2000. Electric Power Research Institute. 1000419. Engineering Guide for Integration of Distributed

Generation and Storage Into Power Distribution Systems. Reprinted with permission.)

Substation DGFault

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730 Electric Power Distribution Handbook

• Relay sensitivity — The upstream protective device (breaker, recloser,

or sectionalizer) may have a ground relay that is more sensitive than

the phase relay setting. Even if the ground-fault current is lower,

increased ground-relay sensitivity may cause miscoordination.

• Grounding sources — Two common generator transformer conﬁgu-

rations supply signiﬁcantly more ground fault current; their zero-

sequence impedance is low (see Figure 14.13):

•Grounded-wye – delta transformer connection — This grounding

transformer presents a zero-sequence impedance equal to the

transformer impedance (about 5% of its rating).

•Grounded-wye – grounded-wye transformer connection with a

rotating generator solidly grounded — A rotating generator has

low zero-sequence impedance (5% of its rating). The total zero-

sequence impedance is the transformer impedance plus the gen-

FIGURE 14.13

DG grounding source connections feeding single-phase faults.

Substation

Fault

5% 5% 10%

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Distributed Generation 731

erator impedance (Z

+ Z

ª 5% + 5% = 10%, assuming both the

transformer and generator have the same kVA rating).

To determine whether the upstream device will misoperate, compare the

fault current with the pickup setting of the device. If it exceeds the pickup,

then examine the time-current characteristics of the protective device. If it

is an instantaneous element, then assume it miscoordinates. If the device has

a time-delay characteristic, then compare the operating time for the given

fault current to the operating time of the next upstream device.

If false tripping of utility protective devices is found, there are several

possible remedies. On the generator side, the corrective options are

• Size — Limit the size of the generator to the point where coordination

is achieved.

• Impedance — Increase the impedance of the generator transformer

or generator.

• Ground faults — If miscoordination occurs from ground faults, add

a grounding reactor to the generator (for a grounded-wye –

grounded-wye interconnection).

On the utility side, the options are

• Settings — Use a higher pickup setting on the upstream device or use

a slower characteristic that coordinates with the generator contribu-

tion. Of course, this requires checking to make sure that the distri-

bution circuit is still adequately protected and that the new setting

coordinates with other protective devices on the distribution circuit.

• Instantaneous — Disable the instantaneous element or add a time

delay to the instantaneous element of sufﬁcient length to coordinate.

• Fuses — Use a larger and/or slower fuse.

• Ground faults — If it is a ground-protection issue with a grounded-

wye – delta interconnection transformer, add a primary neutral

reactor.

If the generator is a large rotating unit that is close to the nearby protective

device, then there may be a signiﬁcant offset to the fault waveshape. This

may affect certain protective devices. If the device is close to miscoordinating

given the equations above, then use a more advanced approach with a short-

circuit program that accounts for the offset.

14.3.1 Tradeoff Between Overvoltages and Ground Fault Current

The transformer/generator grounding plays important roles in supplying

ground fault currents and overvoltages that may occur during islanding.

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732 Electric Power Distribution Handbook

Better grounding limits the overvoltage, but the generator supplies more

ground fault current, which may affect coordination.

At one extreme are the sources that form grounding transformers that can

provide signiﬁcant fault current:

• Grounded wye – delta — The zero-sequence impedance of the inter-

connection is the transformer impedance, normally about 5% on its

rating.

• Grounded wye – grounded wye with the generator solidly grounded —

The zero-sequence impedance is about 10% (5% for the transformer

and 5% for the generator).

At the other extreme are ungrounded connections, which provide no

ground fault current but cause an overvoltage of 1.73 per unit on the

unfaulted phases during a ground fault (note that these can feed ground

faults, just not with zero sequence):

• Delta – delta

• Delta – grounded wye

•Grounded wye – grounded wye with the generator ungrounded

Where ground-fault coordination is a problem, in-between approaches are

often best. Adding a grounding reactor to a grounded wye – delta or adding

a grounding reactor to a generator limits the ground-fault current.

It is normally possible to do both — have effective grounding and reason-

ably limit the zero-sequence fault contribution.

Figure 14.14 shows the tradeoffs with overvoltages and grounding for an

example case. The case has a generator with a grounded-wye – delta trans-

former connection on a 12.47-kV circuit, 4 mi (6.4 km) from the substation.

The transformer has a reactor in the grounded-wye primary. The example

assumes a 5% transformer impedance, 20% positive and negative-sequence

reactances for the generator, and a 1.1 per-unit voltage behind the generator

impedance. Reactor size determines the grounding effectiveness. The reactor

impedance is shown as per-unit multiples of the transformer impedance.

Except for very large generators relative to the distribution system capability,

using a reactor can effectively ground the circuit (overvoltages less than 1.25

per unit) and still reasonably limit the zero-sequence current.

Note that a grounded-wye – grounded-wye transformer with the generator

solidly grounded has similar results to the case with a reactor of 0.3 per unit

in Figure 14.14. In this solidly grounded scenario, the generator supplies

signiﬁcant fault current.

14.3.2 Fuse Saving Coordination

The majority of faults on overhead distribution lines are temporary (meaning

the fault will be cleared if power is interrupted and restored). Temporary

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Distributed Generation 733

faults on lateral taps can be cleared by the feeder breaker before the lateral

fuse blows. This is usually done with the instantaneous element of the

breaker relay or recloser in the substation. This practice is known as fault

selective feeder relaying or simply as “fuse saving.” Distributed generators

increase the fault current through the fuse, which may blow the fuse before

the breaker opens.

Locations with lower fault currents are where generators are most likely

to blow fuses. At locations where fault currents are already high, fuses will

not coordinate with a station breaker (so generators will not make the situ-

FIGURE 14.14

Overvoltages and zero-sequence fault contribution for a grounded-wye – delta interconnection

transformer with a neutral reactor for different size generators (the overvoltage remains the

same with size).

5 MVA

2 MVA

0 2 4 6 8 10

200

400

600

800

0 2 4 6 8 10

1.0

1.2

1.4

1.6

Zero-sequence current, A

500 kVA

Reactor neutral impedance

in per unit of the interconnection transformer impedance

Overvoltage, per unit

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734 Electric Power Distribution Handbook

ation worse). Table 14.5 shows this for the commonly used K links. The

smallest fuses that can coordinate during fuse saving are shown given the

fault current from the substation and a distributed generator. The generator

size in the last column is speciﬁcally for a 12.47-kV system with a synchro-

nous generator with X

≤ = 0.2; the generator fault current contributions in

the ﬁrst column of the table can be applied for other applications.

14.4 Power Quality Impacts

14.4.1 Voltage Regulation

Distributed generation often helps voltage on a distribution circuit because

it offsets some of the voltage drop caused by loads. But, distributed gener-

ation can cause voltages outside of ANSI C84.1 limits under the following

scenarios:

• Voltage boost — Distributed generators can cause high voltages

because they inject real power back upstream into the system, caus-

ing a voltage rise.

• Regulator interaction — Distributed generators can interact with line

regulators, which can cause low or high voltages on a circuit depend-

ing on the scenario.

TABLE 14.5

The Smallest K-Link Fuse That Coordinates with a 5-Cycle Breaker with a Fuse-

Saving Scheme with Fault Current Contributions from the Substation and

Distributed Generator(s)

Generator Fault

Current, A

Fault Current Contribution from the Substation, A

Generator

500 1000 1500 2000 2500 3000 3500 4000

0 40K 80K 100K 140K 140K 200K 200K 200K 0

100 50K 80K 140K 140K 140K 200K 200K — 432

200 50K 100K 140K 140K 200K 200K 200K — 864

300 65K 100K 140K 140K 200K 200K 200K — 1296

400 65K 100K 140K 140K 200K 200K 200K — 1728

500 80K 100K 140K 140K 200K 200K 200K — 2160

600 80K 140K 140K 140K 200K 200K — — 2592

700 100K 140K 140K 200K 200K 200K — — 3024

800 100K 140K 140K 200K 200K 200K — — 3456

900 100K 140K 140K 200K 200K 200K — — 3888

1000 100K 140K 140K 200K 200K 200K — — 4320

Note: No line impedance between the generator and the fault.

Assuming V

= 12.47 kV and generator X

" = 20%.

Integration of Distributed Generation and Storage Into Power Distribution Systems. Reprinted with

permission.

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Distributed Generation 735

Distributed generators can inﬂuence distribution voltage regulation. Even

if the generator is in a “voltage following” mode, it still inﬂuences voltage

by injecting power. In many cases this is beneﬁcial but can cause low or high

voltages, depending on the scenario. Comfort et al. (2001) showed an exam-

ple where a 5-MW combustion turbine raised the voltage to 130 V (1.086%)

3 mi from the substation on a 12.5-kV circuit.

There are also concerns with generators causing high voltages on distri-

bution circuits because of reverse power ﬂow. It is possible to estimate the

effect of a generator by using the standard voltage drop equations with

reverse power ﬂow. The voltage drop along a feeder due to a load is approx-

imately equal to

drop

ª I

· R + I

· X

where

drop

= voltage drop along the feeder, V

R = line resistance, W

X = line reactance, W

= line current due to real power ﬂow (negative for a generator inject-

ing power), A

= line current due to reactive power ﬂow (negative for a capacitor), A

Distributed generators raise voltage the most where X/R ratios are low.

The real power portion causes the largest voltage rise when the line resis-

tance is high. If the generator injects vars like a capacitor or has local capac-

itors, the voltage rise is worse.

Note that this approximation is no substitute for a proper load ﬂow. It

does not fully model the response of the load to the change in voltage, and

it does not consider regulator response. It is useful for a ﬁrst cut at estimating

whether the voltage rise due to the generator might be a problem.

If voltage rise is a problem, there are several options:

• Size — Limit the size of the generator to below the level necessary

to cause problems.

• Relocation — Relocate the generator to a more suitable location on

the distribution circuit.

• Vars — Have the generator absorb more reactive power (by remov-

ing local capacitors or operating a synchronous generator or self-

commutated inverter at reduced power factor). This is the opposite

of what is normally done. Reducing the power factor of the generator

causes voltage drop to counter the real-power voltage rise.

• Operation time — Limit the operation of the generator to peak periods

of the day (when the voltage drop along the circuit tends to be

highest). This is not an exact solution since the highest voltages at

a particular point on a feeder do not always coincide with light load.

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736 Electric Power Distribution Handbook

High voltages can occur at heavy load (especially close to a voltage

regulator or capacitor bank on the distribution feeder).

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

generator during high voltages. This may work out ﬁne if the high

voltage conditions are infrequent.

• Impedance — A utility option would be to reduce the resistance of

the lines and transformers from the substation bus to the generator.

This would be done by using larger conductors on lines and cables

and specifying lower copper losses on transformers. Another option

is to build an express feeder to the generator.

• Regulation equipment — Another utility-side option is to add regula-

tion equipment (capacitors or regulators) to counteract the voltage

rise from the distributed generator.

Normally, the utility only needs to consider the service voltage, but utility

engineers may become involved with cases of high voltage within the facility.

ANSI C84.1 voltage standards account for voltage drop within a facility in

the utilization voltage standard — they do not account for a voltage rise that

generators cause.

Figure 14.15 shows a scenario where a generator just downstream of a

regulator can cause low voltage on the end of the circuit due to the regula-

tor’s line drop compensation controller. The power injected by the generator

fools the regulator into not raising voltage as much as it should.

Many regulators have a special concern — with reverse power, they ratchet

to the extreme tap, causing high or low voltage (EPRI TR-105589, 1995). Most

distribution regulators are bi-directional — they measure voltage on both

sides of the regulator, and power ﬂow determines which side the regulator

uses for compensation. Bi-directional regulators are meant for distribution

system locations where the source may change directions, commonly nor-

mally-open loops that can be reconﬁgured. The regulator always tries to

regulate the voltage on the downstream side, determined by the direction

of power ﬂow. If a downstream distributed generator injects enough real

power to reverse power ﬂow on the regulator, the regulator thinks the source

has moved to the other side. It tries to regulate voltage on the upstream side

of the regulator (V

in Figure 14.16). If the measured voltage is higher than

the setpoint, the regulator changes its tap to try to lower the voltage. Nothing

happens to the voltage upstream of the generator (V

) since the utility source

holds the voltage constant. The regulator keeps trying to lower the voltage,

moving from tap to tap until the regulator ratchets all the way to the limit,

trying to lower voltage as much as possible.

What the regulator did was raise the voltage downstream of the regulator.

It raised the voltage when the feeder voltage was already high — to the

maximum amount. If the feeder voltage is lower than the regulator setpoint,

the opposite occurs: the regulator ratchets to the extreme tap setting that

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Distributed Generation 737

causes even lower voltage downstream of the regulator. These scenarios may

lead to voltage outside of ANSI C84.1 limits.

If the size of the generator or generators is less than 10% of the load at the

regulator, problems are unlikely. If the size exceeds this simple screening

criteria and the generator is close to the regulator, then more detailed study

is warranted. If problems are found, options include the following:

• Remove LDC — Remove the line drop compensation on the regulator.

Generally, the voltage setpoint must be raised to provide a good

voltage proﬁle on the circuit (if so, check that the end of the circuit

does not have high voltages due to the generator).

• Settings — Reduce the line drop compensator settings and raise the

voltage setpoint a smaller amount. This moves the regulator constant

voltage point closer to the regulator. The key is the location of the

constant voltage point (also called the load center — the ﬁctitious

point on the feeder where voltage is held constant). Generators

upstream of this point lower the voltage downstream of this point.

Generators downstream of the constant voltage point are okay.

• Advanced controls — If problems are due to reverse power ﬂow (on

bi-directional regulators), advanced regulator controllers are avail-

able to change operating mode during reverse power ﬂow to pre-

vent the regulator from dropping to the lowest tap. If power

FIGURE 14.15

A generator just downstream of a regulator that leads to low voltage at the end of the feeder.

of Distributed Generation and Storage Into Power Distribution Systems. Reprinted with permission.)

Feeder

Substation

side

End of feeder

Voltage

End of feederRegulator

Regulator

ANSI Range A Lower Limit

Peak load (no DG)

Peak load (with DG)

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738 Electric Power Distribution Handbook

reverses, some controllers can block tap changes or move to the

neutral position.

• Relocation — Relocate the generator to upstream of the regulator, or

relocate the regulator to downstream of the generator.

• Equipment — Add additional regulators or switched capacitors

downstream of the generator.

• Automation — Use an automated distribution scheme to control the

regulator based on data from other locations on the circuit.

Another consideration with regulators (and switched capacitor banks) is

unwanted interaction with generators (especially ﬂuctuating sources). Wid-

ening the regulator bandwidth setting helps avoid this. Increasing the time

delay may also help prevent excessive regulator tap changes.

In addition to upsetting regulation, distributed generators have potential

for signiﬁcantly improving voltage proﬁles and voltage regulation. Genera-

tors inject real power, and many types can vary reactive power (capacitively

or reactively). Distributed generators could be operated in a voltage regula-

tion mode where voltage is regulated at the point of common coupling (or

FIGURE 14.16

Misoperation of a bi-directional regulator due to reverse power ﬂow.

power flow

Regulator fed from source 1: regulates V

Regulator fed from source 2: regulates V

Generator downstream of a regulator: tries to regulate V

If V

is higher than the setpoint: it ratchets to the highest boost

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