Short T.A. Electric Power Distribution Handbook

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Distributed Generation 739

at some other point). This is a complex application that requires signiﬁcant

analysis to avoid problems.

14.4.2 Harmonics

Distributed generators must adhere to strict industry standards for harmonic

injection. Table 14.6 shows the industry limits on harmonics, the same limits

imposed on the largest loads. PWM-based inverters and rotating generators

can meet these limits, so harmonic problems should be rare. Line-commu-

tated inverters normally need ﬁltering to meet these limits. For these limits,

IEEE P1547-D11-2003 deﬁnes the current as the greater of the local system

maximum current without the generator (15 or 30 min demand) and the

generator rated current (transformed to the primary if needed).

Even though most generators do not produce signiﬁcant harmonics, they

can still be involved with harmonic problems. Generators have higher

impedances to harmonics than the normal utility connection. Synchronous

generators have about a 20 to 25% impedance to harmonics on its full-load

rating. Compare that with a utility-source of the same size with an imped-

ance of about 5% (approximately the service transformer impedance). If a

high-harmonic load switches from the utility supply to a generator supply,

the voltage distortion is worse, because the generator supply is not as stiff

as the utility supply. The most prominent problem this causes is for load

served by UPSs. High voltage distortion causes the UPSs to switch to battery,

which drains the battery, possibly causing an interruption to the sensitive

load on the UPS.

Calculate the voltage at the nth frequency with

= n ◊ X ◊ I

where X = X

for positive or negative-sequence harmonics, X = X

for zero-

sequence harmonics, and I

is the harmonic current generated at the nth

harmonic. Use superposition to calculate the harmonic voltage distortion

due to multiple loads.

The classic model for the impedance to harmonics is the negative-sequence

impedance. It is used for positive- and negative-sequence harmonics. Arse-

neau et al. (1979) showed that a constant impedance that linearly increases

TABLE 14.6

IEEE Harmonic Current Distortion Limits for Generation in Percent

(IEEE P1547-D11-2003 and IEEE Std. 519-1992)

Individual Harmonics

Total Demand

Distortionn < 11 11 ££

££

n < 17 17 ££

££

n < 23 23 ££

££

n < 35 35 ££

££

4.0 2.0 1.5 0.6 0.3 5.0

Note: Even harmonics are limited to 25% of the odd harmonic limits.

1791_book.fm Page 739 Monday, August 4, 2003 3:20 PM

740 Electric Power Distribution Handbook

with frequency is relatively accurate. The negative-sequence impedance is

" + X

")/2. The direct-axis subtransient reactance is also a common

approximation. Normally, this is accurate since X

" and X

" are usually close

to each other. If no other information is available, use X

= 25%.

EPRI PEAC tests of generators with different X

" and X

" showed that X

is a better approximation for generators supplying single-phase power-sup-

ply load (EPRI 1005922, 2001; Langley et al., 2002). Single-phase power-

supply load draws a burst of current near the voltage crest; from the gener-

ator’s point of view, it is not a harmonic but more like a fault every half

cycle. So, only the direct-axis impedance plays a role. Now, if a resonance

occurs, the quadrature axis is expected to play more of a role, making voltage

distortion worse since (X

" + X

")/2 is larger than X

Generators have a low impedance to the third harmonic and other zero-

sequence harmonics. It is well known that balanced in-phase third-harmonic

values are zero sequence (so V

for voltages and I

for currents).

All harmonics that are multiples of three are zero sequence; 1, 4, 7 … are

positive sequence, and 2, 5, 8 … are negative sequence.

A low zero-sequence harmonic impedance is usually an advantage in that

it keeps the voltage distortion low for third-harmonic load currents. One

problem is occasionally seen when two generators in parallel feed load and

are separated from the utility. Generators also create harmonics. If the gen-

erators have different characteristics or are loaded differently, a third-har-

monic current can circulate on the neutral between the generators. This can

trip one or both generators on high neutral current. The circulating current

is pronounced when one generator has a 3/4-pitch stator winding (which

acts as a harmonic voltage source that is relatively high in third harmonics)

and the other generator has a 2/3-pitch stator winding (which has a low

impedance to harmonics).

14.4.3 Flicker

Large generators on weak distribution systems can generate voltage ﬂicker.

If it is large enough, any generator can cause a noticeable voltage change at

starting or stopping. Voltage ﬂicker is worse with generators that have vary-

ing power outputs, such as

• Reciprocating engines — Poor fuel or maintenance may result in mis-

ﬁring cylinders. Misﬁring leads to a ﬂuctuating power output. Very

large, low-rpm engines have a slow enough beat that the power

output ﬂuctuates under normal operations.

• Wind turbines — Tower shading causes ﬂicker. As a blade passes the

tower holding the turbine, the torque produced by the blade drops,

so the power output drops.

Starting of induction generators also causes voltage ﬂicker, just like starting

an induction motor. Slower power changes normally do not cause ﬂicker

1791_book.fm Page 740 Monday, August 4, 2003 3:20 PM

Distributed Generation 741

problems. For example, although photovoltaic power output varies signiﬁ-

cantly as clouds cover and then reveal the sun, the sunlight intensity change

is slow enough that it does not cause severe ﬂicker.

The ﬂicker from reciprocating engines depends on the rotational speed of

the generator and the quality of the fuel supply. Anderson and Mirheydar

(1995) showed a case where misﬁring cylinders caused voltage ﬂicker on a

12-kV circuit and analyzed this problem in detail. Poor fuel was the cause

— methane recovered from a former landﬁll.

The frequency of oscillations determines how severe the ﬂicker is, with

oscillations in the range of 5 to 10 Hz being most noticeable. The frequency

of oscillation of the power stroke of a reciprocating engine operating in

hertz is

(for 60 Hz only; for 50 Hz, divide by 25 instead of 30)

where

N = number of cylinders

rpm = rotational speed of the generator, rev/min

k =

For all but the very slowest generators with few cylinders, the frequency

of this power stroke beat is fast enough; it cannot cause ﬂicker. But, if cylin-

ders misﬁre, the frequency of power oscillation with the misﬁre in hertz is

For many common generators, the power oscillation frequency with mis-

ﬁring cylinders lies right in the range where it is very noticeable. A 4-cycle

900-rpm engine produces ﬂicker at 7.5 Hz, at the most sensitive part of the

voltage ﬂicker curve. An 1800-rpm engine is better (and fortunately more

standard); these produce ﬂicker at 15 Hz; although this can still cause prob-

lems, it is on the less sensitive part of the voltage ﬂicker curve.

The main way to prevent reciprocating engine ﬂicker is controlling the

fuel quality and performing proper maintenance to minimize misﬁring.

Most of the experience with ﬂicker and wind turbines comes from Europe

where wind turbines have higher penetration levels (and the higher-voltage

lamp ﬁlament makes ﬂicker worse). Gerdes and Santjer (1996) found that

ﬂicker is not a problem on most wind turbines if

> 100

N rpm

◊

2 for two - cycle engine

4 for a four - cycle engine

rpm

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742 Electric Power Distribution Handbook

where

= wind turbine rated load current

= three-phase short-circuit current at the point of common coupling

Their measurements found most problems where the short-circuit ratio was

less than 40, but there were large differences between wind turbines. Some were

ﬁne even at weak locations with a short-circuit ratio as low as 10, but the worst

performers caused ﬂicker even with a short-circuit ratio of over 90. Variations

in performance were mainly due to aerodynamic and mechanical differences.

There are several possible generator-side remedies for reducing the ﬂicker

caused by generators. These are not normally done, but some options include

• Controls — Use internal controls to regulate real power output to

slow down the rate of output change. For example, many inverters

and rotational generators include soft-start functions that allow them

to slowly ramp power up over many seconds rather than step the

power on.

• Storage — Use a battery or other energy-storage device to help reduce

power output swings.

• Vars — Use changes in reactive power to offset the changes in real

power. PWM inverters can change the reactive power output, so the

generator could operate lagging when the unit is producing full real

power and change to a leading power factor (to increase voltage)

when the unit is not producing any real power. Synchronous gen-

erators with fast exciters may also be able to correct for ﬂicker.

• Size — Limit the size of the generator to prevent ﬂicker.

Solutions based on individual types of generators include

• Wind turbines — Choose a design that reduces the effect of tower

shading.

• Reciprocating engines — Use proper fuel grades, and keep the engine

tuned up.

• Induction generators — Use a reduced-voltage starter that uses a

method such as an autotransformer, extra impedance, solid-state elec-

tronic voltage reduction, or transformer reconnection from wye dur-

ing starting to delta during normal operation. Alternately, use a self-

starter to get the generator up to speed before connecting to the grid.

Other solutions for ﬂicker include any of the standard techniques dis-

cussed in Chapter 11 for reducing voltage ﬂicker from ﬂuctuating loads.

A ﬁnal consideration for voltage ﬂicker is that a large generator located

on a weak system may improve the voltage ﬂicker caused by adjacent ﬂuc-

tuating loads. The generator control algorithm determines how effectively

it can correct voltage. A constant-voltage control with a fast response (such

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Distributed Generation 743

as a synchronous generator with a fast exciter regulating voltage or a PWM

inverter) is most likely to respond to ﬂicker. Of course, a large generator

located on a weak system is more likely to have other issues, such as its own

ﬂicker, voltage-regulation problems, and islanding problems.

14.4.4 Other Impacts on Power Quality

Distribution systems normally do not have stability issues. That may change

with large penetration of generators. The largest concern is with faults that

cause the distributed generators to trip (since they have sensitive voltage

sag settings). Miller et al. (2001) found that with a 40% penetration of gen-

eration on a circuit, motor load on the circuit could stall, causing a voltage

collapse on the circuit.

Large penetration of distributed generators may also impact bulk system

stability. Miller (2002) performed simulations of the U.S. western grid and

found that a 20% penetration of distributed generation seriously erodes

stability when the distributed generators trip off quickly because of voltage

or frequency relays. Another concern with the bulk system stability is with

active anti-islanding inverters. Signiﬁcant penetration of these will degrade

the overall system stability.

Large synchronous generators on a distribution system might require

changes to reclosing practices. Because of the danger of reclosing into an

island that is out of phase, the reclosing delay might have to be extended.

Many utilities use an immediate reclose attempt, which means there is no

intentional delay. Circuit breakers typically reclose in about one-third to one-

half of a second. This may not give the generator time to clear, especially in

a near-island situation. Extending the reclose time on utility breakers and

reclosers gives the generator more time to clear.

As an alternative to extending the time before reclose, a voltage-supervis-

ing relay can block reclosing on a circuit breaker until the line voltage is dead.

14.4.5 High Quality Power Conﬁgurations

To enhance reliability, most conﬁgurations of generators only help with long-

duration interruptions, not with voltage sags, not with momentary interrup-

tions. Figure 14.17 shows two conﬁgurations that use continuously running

generators to supply critical loads with higher-quality power. The basic idea

is to use a static switch for fast transfers between the utility and the generator.

The basic conﬁgurations are

• On-line conﬁguration: The generator supplies some or all of the load.

If a sag or interruption hits the utility supply, a static switch opens

up, and the generator supplies all of the load.

• Off-line conﬁguration: The load normally runs off of the generator. If

the generator fails, a static transfer switch operates and switches the

load to the utility input.

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744 Electric Power Distribution Handbook

In both of these cases, the generator must match the load quickly. This is

difﬁcult, as many generation technologies have limited load-following capa-

bility. Some of the ways of matching generation to the load are as follows:

• Shed load by tripping load breakers to match the load to the generator.

• Use some sort of power electronics with short-term energy storage

to dynamically correct for mismatches to give the generator time to

match the load.

Also consider that the generator must supply motor starting current if the

critical load has motors.

14.5 Generator Reliability

Generator reliability is important when the distributed generator is critical:

stand-alone customer systems, micro-grids, generation applied to relieve

peak loading (it does not help if it is ofﬂine). Figure 14.18 shows that indi-

FIGURE 14.17

Generator conﬁgurations supplying protection against short-duration as well as long-duration

tremely Reliable Power Delivery Systems. Reprinted with permission.)

Static transfer switch configuration

Utility input

Static transfer

switch

Critical load

Static switch configuration

Utility input

Static switch or

fast mechanical switch

Critical load

1791_book.fm Page 744 Monday, August 4, 2003 3:20 PM

Distributed Generation 745

vidual generators typically have availabilities ranging from 90 to 97%. This

is much lower than the availability of typical electric utility supplies. A 97%

availability is 11 days interrupted per year. The Gold Book (IEEE Std. 493-

1997 based on Smith et al., 1990) cites failure rates of 32.9, 11.8, and 15 failures

per year for diesels with auxiliary support systems, diesels packaged as

units, and gas turbines.

As a supplement to a utility connection, a generator can greatly increase

the reliability to the end user. Consider a utility supply with an availability

of 99.966% (3.5 h of down time annually). If a generator with an availability

of 97% (11 days of unavailability) is paralleled, the total availability of the

parallel sources improves to 99.9988% (1-[1-0.97][1-0.99966]) or an average

of 6 min of down time per year. Without the utility, designing a reliable

supply becomes more difﬁcult.

Without a utility supply, any critical application needs redundant gener-

ators. Assuming that an individual generator has 97% availability, Table 14.7

shows availabilities for several combinations of generators. This data is

repeated as a graph in Figure 14.19 showing the number of nines of avail-

ability (a 99.9% availability is three nines, a 99.99% availability is four nines)

against the generation capacity and notations showing the conﬁguration.

FIGURE 14.18

Generator availability. (Data from [GRI, 1993; IEEE Std. 493-1997; International Fuel Cells, 2001].

Power Delivery Systems. Reprinted with permission.)

85 90 95 100

Recip. engines < 60 kW

Recip. engines, 80-800 kW

Recip. engines, > 800 kW

Gas turbines, 1-5 MW

Gas turbines, 5-25 MW

Gas turbines, >25 MW

Diesel auxiliary

Diesel package

Gas turbine

With utility

Standalone

[Gas Research Institute, 1993]

Gold Book [IEEE Std. 493-1997]

Fuel cell [International Fuel Cells, 2001]

Generator availability, percent

1791_book.fm Page 745 Monday, August 4, 2003 3:20 PM

746 Electric Power Distribution Handbook

The binomial distribution shows the failure probabilities for r out of n gen-

erators. The probability of exactly r successes in n trials with a probability

of success p (Billinton and Allan, 1984) is

So, for an example with p = 0.97, and three total generators, the probabil-

ities of a given numbers of generators being out of service are

Maintenance plays a key role in the reliability of generators. Not counting

down time for maintenance, the availability of generators jumps from 97%

TABLE 14.7

Conﬁgurations of Redundant Generators

Number of

Units Needed

Total Number

of Units Notation Capacity

System

Availability

11N100% 0.97

12N+1 200% 0.9991

13N+2 300% 0.999973

14N+3 400% 0.99999919

22N100% 0.941

23N+1 150% 0.9974

24N+2 200% 0.99989

25N+3 250% 0.9999960

26N+4 300% 0.99999986

33N100% 0.912

34N+1 133% 0.9948

35N+2 167% 0.99974

36N+3 200% 0.999988

44N100% 0.885

45N+1 125% 0.9915

46N+2 150% 0.99950

47N+3 175% 0.999974

48N+4 200% 0.9999987

55N100% 0.858

56N+1 120% 0.988

57N+2 140% 0.99914

58N+3 160% 0.999949

59N+4 180% 0.9999972

510N+5 200% 0.99999986

Units Out of Service

Probability of the Given Number

of Units Out of Service

0 0.97

= 0.912673

1 (r = 2, n = 3) 3 (0.97)

(1–0.97) = 0.084681

2 (r = 1, n = 3) 3 (0.97) (1–0.97)

= 0.002619

3 (1–0.97)

= 0.000027

Sum = 1.0

PCp p

rn r

rnr

rnr rnr

=-=

()

!( )!

()11

1791_book.fm Page 746 Monday, August 4, 2003 3:20 PM

Distributed Generation 747

to 99% (see Table 14.8). If maintenance can be performed at non-critical times,

the reliability of the installation improves greatly.

The availabilities in Figure 14.19 are theoretical and do not include over-

lapping or common-mode failures. For generators, several factors contribute

to common-mode failures:

FIGURE 14.19

Theoretical availability with different generation conﬁgurations. The graph assumes an individ-

ual unit is 97% available. The k + n notation means k generators are needed to meet the peak

1007281. Analysis of Extremely Reliable Power Delivery Systems. Reprinted with permission.)

TABLE 14.8

Generator Availabilities, Percent

Including

Maintenance

Excluding

Maintenance

Diesel auxiliary 97.1 98.9

Diesel package 96.8 99.1

Gas turbine 97.2 99.4

Source: IEEE Std. 493-1997, IEEE Recommended Practice for the Design of

Reliable Industrial and Commercial Power Systems (Gold Book); Smith, C. A.,

Donovan, M. D., and Bartos, M. J., “Reliability Survey of 600 to 1800 kW

Diesel and Gas-Turbine Generating Units,” IEEE Transactions on Industry

Applications, vol. 26, no. 4, pp. 741–55, July/August 1990.

100 150 200 250 300 350 400

1234567

Generation capacity, percent of needed generation

Number of nines of availability

1+0

1+1

1+2

1+3

2+0

2+1

2+2

2+3

2+4

3+0

3+1

3+2

3+3

4+0

4+1

4+2

4+3

4+4

5+0

5+1

5+2

5+3

5+4

5+5

100 150 200 250 300 350 400

1234567

1791_book.fm Page 747 Monday, August 4, 2003 3:20 PM

748 Electric Power Distribution Handbook

• Fuel supply — Continuously run generators likely have a common

supply of natural gas. Backup generators are more likely to have

independent tanks for supply. Units with dual-fuel capability can

reduce the likelihood of this failure mode.

• Controls — Generators may have common controls for starting.

• Space — If generators are in close proximity, failure of one may

require adjacent units to be shut down.

• Design ﬂaws — Common design ﬂaws may fail all units under the

right conditions.

Good design, especially with redundant supporting systems, helps mini-

mize the probability of common-mode failures, and periodic testing helps

minimize hidden failures. And because maintenance is such a large compo-

nent of down time, coordinating maintenance among parallel units and

scheduling for non-critical times helps reduce the chance of failures.

References

Anderson, P. M. and Mirheydar, M., “Analysis of a Diesel-Engine Driven Generating

Unit and the Possibility for Voltage Flicker,” IEEE Transactions on Energy Con-

version, vol. 10, no. 1, pp. 37–47, March 1995.

ANSI C84.1-1995, American National Standards for Electric Power Systems and Equipment

— Voltage Ratings (60 Hz).

ANSI/IEEE C37.90-1989, IEEE Standard for Relays and Relay Systems Associated with

Electric Power Apparatus.

ANSI/IEEE C37.90.1-1989, IEEE Standard Surge Withstand Capability (SWC) Tests for

Protective Relays and Relay Systems.

ANSI/IEEE C62.92-1987, IEEE Guide for the Application of Neutral Grounding in Elec-

trical Utility Systems. Part I — Introduction.

ANSI/IEEE Std. 1001-1988, IEEE Guide for Interfacing Dispersed Storage and Generation

Facilities with Electric Utility Systems.

Arseneau, R., Hill, E. F., Szabados, R., and Ferry, D., “Synchronous Motor Impedances

Measured at Harmonic Frequencies,” IEEE/PES Summer Power Meeting, Van-

couver, Canada, 1979.

Barker, P. P. and De Mello, R. W., “Determining the Impact of Distributed Generation

on Power Systems. I. Radial Distribution Systems,” IEEE Power Engineering

Society Summer Meeting, 2000.

Barker, P. P. and Johnson, B. K., “Power System Modeling Requirements for Rotating

Machine Interfaced Distributed Resources,” IEEE Power Engineering Society

Summer Meeting, 2002.

Billinton, R. and Allan, R. N., Reliability Evaluation of Power Systems, Pitman Advanced

Publishing Program, 1984.

CEA 128 D 767, Connecting Small Generators to Utility Distribution Systems, Canadian

Electrical Association, 1994.

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