HARD TO FIND INFORMATION ABOUT
DISTRIBUTION SYSTEMS
(Contains Hard to Find I, II, III, IV, and V with index)
Volume 1
Jim Burke
distjimb@aol.com
109 Dorchester Pines Court
Cary, NC 27511
© Jim Burke
September 18, 2006
2
Table of Contents
I.
PREFACE.................................................................................................................................................. 6
II.
SYSTEM CHARACTERISTICS AND PROTECTION ....................................................................... 7
A. INTRODUCTION ..................................................................................................................................... 7
B. FAULT LEVELS ...................................................................................................................................... 7
C. LOW IMPEDANCE FAULTS .................................................................................................................... 8
D. HIGH IMPEDANCE FAULTS ................................................................................................................... 8
E. SURFACE CURRENT LEVELS ................................................................................................................. 9
F. RECLOSING AND INRUSH ....................................................................................................................... 9
G. COLD LOAD PICKUP ........................................................................................................................... 10
H. CALCULATION OF FAULT CURRENT .................................................................................................. 11
I. RULES FOR APPLICATION OF FUSES ................................................................................................... 12
J. CAPACITOR FUSING ............................................................................................................................ 13
K. CONDUCTOR BURNDOWN ................................................................................................................... 14
L. DEVICE NUMBERS .............................................................................................................................. 15
M. PROTECTION ABBREVIATIONS ........................................................................................................... 16
N. SIMPLE COORDINATION RULES ......................................................................................................... 17
O. LIGHTNING CHARACTERISTICS ......................................................................................................... 18
P. ARC IMPEDENCE ................................................................................................................................. 19
III.
TRANSFORMERS ................................................................................................................................. 20
A.
B.
C.
D.
IV.
SATURATION CURVE ........................................................................................................................... 20
INSULATION LEVELS ........................................................................................................................... 20
Δ-Y TRANSFORMER BANKS ................................................................................................................ 21
TRANSFORMER LOADING ................................................................................................................... 21
INSTRUMENT TRANSFORMERS ..................................................................................................... 23
A. TWO TYPES ......................................................................................................................................... 23
B. ACCURACY .......................................................................................................................................... 23
C. POTENTIAL TRANSFORMERS .............................................................................................................. 23
D. CURRENT TRANSFORMER .................................................................................................................. 24
E. H-CLASS .............................................................................................................................................. 24
F. CURRENT TRANSFORMER FACTS ....................................................................................................... 24
G. GLOSSARY OF TRANSDUCER TERMS.................................................................................................. 26
V.
RULES OF THUMB FOR UNIFORMLY DISTRIBUTED LOADS ................................................ 28
VI.
CONDUCTORS AND CABLES ........................................................................................................... 29
A. CONDUCTOR CURRENT RATING ........................................................................................................ 29
B. FACTS ON DISTRIBUTION CABLE........................................................................................................ 29
C. IMPEDANCE OF CABLE........................................................................................................................ 30
VII.
DSG – GENERAL REQUIREMENTS ................................................................................................. 31
VIII.
DANGEROUS LEVELS OF CURRENT ............................................................................................. 32
IX.
CAPACITOR FORMULAS .................................................................................................................. 33
3
X.
EUROPEAN PRACTICES .................................................................................................................... 35
A.
B.
C.
D.
XI.
PRIMARY ............................................................................................................................................. 35
RELAYS ................................................................................................................................................ 35
EARTH FAULT PROTECTION .............................................................................................................. 36
GENERAL............................................................................................................................................. 36
POWER QUALITY DATA ................................................................................................................... 38
A. MOMENTARIES ................................................................................................................................... 38
B. SAGS .................................................................................................................................................... 38
C. POWER QUALITY ORGANIZATIONS.................................................................................................... 38
XII.
ELECTRICITY RATES ........................................................................................................................ 40
XIII.
COSTS ..................................................................................................................................................... 42
A. GENERAL............................................................................................................................................. 42
XIV.
RELIABILITY DATA............................................................................................................................ 44
XV.
INDUSTRIAL AND COMMERCIAL STUFF .................................................................................... 45
XVI.
MAXWELL’S EQUATIONS ................................................................................................................ 49
Hard to Find - Part II
XVII.
INTRODUCTION .................................................................................................................................. 50
XVIII.
CONTENTS ............................................................................................................................................ 50
XIX.
DISTRIBUTED RESOURCES.............................................................................................................. 51
XX.
RELIABILITY ........................................................................................................................................ 53
1.
2.
3.
4.
5.
6.
7.
TYPICAL EQUIPMENT FAILURE RATES .......................................................................................... 53
PRIMARY OUTAGE RATES .............................................................................................................. 53
EFFECT OF MAJOR EVENTS ............................................................................................................ 53
INDICE DEFINITIONS ....................................................................................................................... 54
VOLTAGE SAGS ............................................................................................................................... 55
INTERRUPTION SURVEY .................................................................................................................. 55
LOADING .......................................................................................................................................... 55
XXI.
MODERN PHYSICS .............................................................................................................................. 56
XXII.
LOADING ............................................................................................................................................... 57
1.
2.
3.
4.
5.
6.
TRANSFORMER LOADING BASICS ................................................................................................... 57
EXAMPLES OF SUBSTATION TRANSFORMER LOADING LIMITS ..................................................... 58
DISTRIBUTION TRANSFORMERS ..................................................................................................... 59
AMPACITY OF OVERHEAD CONDUCTORS....................................................................................... 59
EMERGENCY RATINGS OF EQUIPMENT .......................................................................................... 60
MISCELLANEOUS LOADING INFORMATION .................................................................................... 60
XXIII.
COMPUTER JARGON 101 .................................................................................................................. 63
XXIV.
DECIBELS .............................................................................................................................................. 65
4
XXV.
FAULTS AND INRUSH CURRENTS .................................................................................................. 66
XXVI.
CUSTOM POWER DEVICES .............................................................................................................. 67
XXVII. COST OF POWER INTERRUPTIONS ............................................................................................... 68
XXVIII. COST OF SECTIONALIZING EQUIPMENT ................................................................................... 69
XXIX.
MAINTENANCE OF EQUIPMENT .................................................................................................... 70
XXX.
MAJOR EVENTS ................................................................................................................................... 71
XXXI.
LINE CHARGING CURRENT............................................................................................................. 72
XXXII. OVERCURRENT RULES ..................................................................................................................... 73
Hard to Find - Part III
XXXIII. INFORMATION ON GROUNDING…………………..……………………………….………..76
XXXIV. RELIABILITY TRENDS……………..……………………………..…………………………….77
.XXXV. LOAD SURVEY RESULTS……………………………………………………………………….78
XXXVI. LIGHTNING DAMAGE SURVEY………………………………………………………………..79
XXXVII. SUBSTATION VOLTAGE REGULATION……………………………………………..……..80
XXXVIII. WAYS WE SCARE OURSELVES………………………………………………………………81
XXXIX. COST OF POOR POWER QUALITY……………………………………………………………82
XXXX. WINDPOWER UPDATE……………………………………………………………………….......82
XXXXI. FAULT IMPEDANCE………………………………………………………………………….….83
XXXXII. EXPLANATION OF VOLTAGE RATINGS……………………………………………………86
Hard to Find – Part IV
XXXXIII. STRAY VOLTAGE..……………………………………………..……...………………………..88
XXXXIV. AIRLINE CABIN ANNOUNCEMENTS……………..………………………………………….90
XXXXV. POWER QUALITY REVISITED……………..…………………….……………………………..92
XXXXVI. APPLICATION OF CAPACITORS..………………………………………..…...………………97
Hard to Find – Part V
(Grounding, BPL and other miscellaneous topics…page 103)
INDEX………….116
Burke
Bio…………………………………………………………………..…………………………………………..119
5
I.
Preface
There have been little tidbits of information I have accumulated over the past 40 years that have helped
me understand and analyze distribution systems. I have pinned them to my wall, taped them to my
computer, stuffed them in my wallet and alas, copied them for my students. Much of them are hard, if
not impossible, to find in any reference book. A large percentage of them could also be classified as
personal opinion so they should be used carefully. For whatever, I hope they are as useful to you as
they have been to me.
Over the many years, this document has taken on a life of its own. There have been many suggestions
and much help from so many distribution engineers that it is impossible to thank all of you. From the
new topics such as “stray voltage” and “grounding” to the many surveys we’ve all done together
(lightning, loading, etc) and finally the less serious sections like “Ways We Scare Ourselves” and “
Airline Cabin Announcements”, this has been a lot of fun to work on.
Jim Burke – 8/05
6
II. System Characteristics and Protection
A. Introduction
The distribution system shown below illustrates many of the features of a distribution system making it
unique. The voltage level of a distribution system can be anywhere from about 5 kV to as high as 35 kV
with the most common voltages in the 15 kV class. Areas served by a given voltage are proportional to
the voltage itself indicating that, for the same load density, a 35 kV system can serve considerably
longer lines. Lines can be as short as a mile or two and as long as 20 or 30 miles. Typically, however,
lines are generally 10 miles or less. Short circuit levels at the substation are dependent on voltage level
and substation size. The average short circuit level at a distribution substation has been shown, by
survey, to be about 10,000 amperes. Feeder load current levels can be as high as 600 amperes but
rarely exceed about 400 amperes with many never exceeding a couple of hundred amperes.
Underground laterals are generally designed for 200 amperes of loading but rarely approach even half
that value. A typical lateral load current is probably 50 amperes or less even during cold load pickup
conditions.
B. Fault Levels
There are two types of faults, low impedance and high impedance. A high impedance fault is
considered to be a fault that has a high Z due to the contact of the conductor to the earth, i.e., Zf is high.
By this definition, a bolted fault at the end of a feeder is still classified as a low impedance fault. A
summary of findings on faults and their effects is as follows:
138 kV Distribution
Substation Transformer
ISC = 10,000 A
13.8 kV
Feeder Breaker
Peak Load = 600 Amps
Three Phase, 4-Wire,
Multigrounded Fuse Cutout
S
Normally Open Tie Switch
Distribution
Transformers
4-15 Holmes/Transformer
Single Phase Sectionalizer
Fixed Capacitor Bank
Three Phase Recloser
R
Switched Capacitor
Bank (=600 kVAR)
Faulted Circuit Indicator
FCI
FCI
Normally Open Tie
Underground Lateral
Normally Open Tie
Pothead
Elbow Disconnect
7
Figure 1. Typical distribution system
C. Low Impedance Faults
Low impedance faults or bolted faults can be either very high in current magnitude (10,000 amperes or
above) or fairly low, e.g., 300 amperes at the end of a long feeder. Faults able to be detected by normal
protective devices are all low impedance faults. These faults are such that the calculated value of fault
current assuming a "bolted fault” and the actual are very similar. Most detectable faults, per study data,
do indeed show that fault impedance is close to 0 ohms. This implies that the phase conductor either
contacts the neutral wire or that the arc to the neutral conductor has a very low impedance. An EPRI
study performed by the author over 10 years ago indicated that the maximum fault impedance for a
detectable fault was 2 ohms or less. Figure 2, shown below, indicates that 2 ohms of fault impedance
influences the level of fault current depending on location of the fault. As can be seen, 2 ohms of fault
impedance considerably decreases the level of fault current for close in faults but has little effect for
faults some distance away. What can be concluded is that fault impedance does not significantly
affect faulted circuit indicator performance since low level faults are not greatly altered.
FAULT LEVEL vs. DISTANCE
Fault Current in Amps
10000
Bolted Fault
1000
Z Fault = 2 Ohms
100
0
5
10
15
20
DISTANCE IN MILES (FROM SUBSTATION)
Figure 2. Low impedance faults
D. High Impedance Faults
High impedance faults are faults that are low in value, i.e., generally less than 100 amperes due to the
impedance between the phase conductor and the surface on which the conductor falls. Figure 3, shown
below, illustrates that most surface areas whether wet or dry do not conduct well. If one considers the
fact that an 8 foot ground rod sunk into the earth more often than not results in an impedance of 100
ohms or greater, then it is not hard to visualize the fact that a conductor simply lying on a surface cannot
be expected to have a low impedance. These faults, called high impedance faults, do not contact the
neutral and do not arc to the neutral. They are not detectable by any conventional means and are not to
be considered at all in the evaluation of FCIs and most other protective devices.
8
REINFORCED
CONCRETE
E. Surface Current Levels
Current Level in Amperes
20
WET GRASS
DRY GRASS
DRY SOD
40
WET SAND
60
WET SOD
DRY ASPHALT , CONCRETE OR DRY SAND
80
0
Type of
Figure 3. High impedance fault current levels
F. Reclosing and Inrush
On most systems where most faults are temporary, the concept of reclosing and the resulting inrush
currents are a fact of life. Typical reclosing cycles for breakers and reclosers are different and are shown
below in Figure 4.
"Fast" Operations
(Contacts Closed)
"Time Delay" Operations
(Contacts Closed)
Fault
Current
Load Current
2 Sec
2 Sec
Recloser
Lockout
2 Sec
(Contacts
Open)
(Contacts
Closed)
Fault
Initiated
Time
Reclosing Intervals
(Contacts Open)
Line Recloser
Isc
30
Cycles
5
Seconds
15
Seconds
30
Seconds
Dead Time
Current vs. Time
Feeder Breaker Reclosing
Figure 4. Reclosing sequences
9
These reclosing sequences produce inrush primarily resulting from the connected transformer kVA. This
inrush current is high and can approach the actual fault current level in many instances. Figure 5 shows
the relative magnitude of these currents. What keeps most protective devices from operating is that the
duration of the inrush is generally short and as a consequence will not melt a fuse or operate a time
delay relay.
G. Cold Load Pickup
Cold load pickup, occurring as the result of a permanent fault and long outage, is often maligned as the
cause of many protective device misoperations. Figure 6, shown below, illustrates several cold load
pickup curves developed by various sources. These curves are normally considered to be composed of
the following three components:
P.U. of Full Load
30
25
20
15
10
5
0
Transformers
Laterals
Feeders
Location
Figure 5. Magnitudes of inrush current
1)
2)
3)
Inrush – lasting a few cycles
Motor starting – lasting a few seconds
Loss of diversity – lasting many minutes.
When a lateral fuse misoperates, it is probably not the result of this loss of diversity, i.e., the fuse is
overloaded. This condition is rare on most laterals. Relay operation during cold load pickup is generally
the result of a trip of the instantaneous unit and probably results from high inrush. Likewise, an FCI
operation would not appear to be the result of loss of diversity but rather the high inrush currents. Since
inrush occurs during all energization and not just as a result of cold load pickup, it can be concluded
that cold load pickup is not a major factor in the application of FCls.
10
%
Figure 6. Cold-load inrush current characteristics for distribution circuits
H. Calculation of Fault Current
Ε
Line Faults Line-to-neutral fault =
3 • 2• Ζl
Where Zℓ is the line impedance and 2Zℓ is the loop impedance assuming the impedance of the phase
conductor and the neutral conductor are equal (some people use a 1.5 factor).
Line-to-Line Faults =
Ε
2Ζl
Transformer Faults Line-to-neutral or three phase =
Ε
3 • ΖΤ
Line-to-Line =
Ε
2( Ζ Τ + Ζ l )
where
ZT =
Ζ l = RL2 + Χ 2L
Z T % • 10 • E 2
kVA
11
I. Rules for Application of Fuses
1)
Cold load pickup -
2)
"Damage" curve - 75% of minimum melt
3)
Two expulsion fuses cannot be coordinated if the available fault current is great enough
to indicate an interruption of less than .8 cycles.
4)
“T” - SLOW and "K” - FAST
5)
Current limiting fuses can be coordinated in the sub-cycle region.
6)
Capacitor protection:
•
•
•
7)
12
after 15 minute outage, 200% for.5 seconds
140% for 5 seconds
after 4 hrs, all electric 300% for 5 minutes
The fuse should be rated for 165% of the normal capacitor current. The fuse should
also clear within 300 seconds for the minimum short circuit current.
If current exceeds the maximum case rupture point, a current limiting fuse must be
used.
Current limiting fuses should be used if a single parallel group exceeds 300 KVAR.
Transformer
•
Inrush - 12 times for .1 sec.
•
25 times for .01 sec.
•
Self protected - primary fuse rating is 10 to 14 times continuous when secondary
breaker is used.
•
Self protected - weak link is selected to be about 2 1/2 times the continuous when
no secondary breaker is used (which means that minimum melt is in the area of 4 to
6 times rating).
•
Conventional - primary fuse rated 2 to 3 times.
•
General Purpose current limiting - 2 to 3 times continuous.
•
Back-Up current limiting - the expulsion and CLF are usually coordinated such that
the minimum melt I2t of the expulsion fuse is equal to or less than that of the back up
CLF.
8)
Conductor burn down - not as great a problem today because loads are higher and
hence conductors are larger.
9)
General purpose - one which will successfully clear any current from its rated maximum
interrupting current down to the current that will cause melting of the fusible element in
one hour.
10)
Back up - one which will successfully clear any current from its rated maximum
interrupting down to the rated minimum interrupting current, which may be at the 10
second time period on the minimum melting time-current curve.
11)
CLF - approximately 1/4 cycle operation; can limit energy by as much as 60 to 1.
12)
Weak link - in oil is limited to between 1500 and 3500 amperes.
13)
Weak link - in cutout is limited to 6000 to 15000 asymmetrical.
14)
Lightning minimum fuse (12T-SLOW), (25K-FAST).
15)
Energy stored in inductance = ½ Li2
16)
The maximum voltage produced by a C.L. fuse typically will not exceed 3.1 times the
fuse rated maximum voltage.
17)
The minimum sparkover allowed for a gapped arrester is 1.5 x 1.414 = 2.1 times
arrester rating.
18)
General practice is to keep the minimum sparkover of a gapped arrester at about 2.65 x
arrester rating.
19)
MOVs do not have a problem with CLF “kick voltages.”
J. Capacitor Fusing
1)
Purpose of fusing:
a.
b.
c.
d.
e.
2)
to isolate faulted bank from system
to protect against bursting
to give indication
to allow manual switching (fuse control)
to isolate faulted capacitor from bank
Recommended rating:
a. The continuous-current capability of the fuse should be at least 165 percent of
the normal capacitor-bank (for delta and floating wye banks the factor may be
reduced to 150 percent if necessary).
b. The total clearing characteristics of the fuse link must be coordinated with the
capacitor “case bursting” curves.
3)
Tests have shown that expulsion fuse links will not satisfactorily protect against violent
rupture where the fault current through the capacitor is greater than 5000 amperes.
4)
The capacitor bank may be connected in a floating wye to limit short-circuit current to
less than 5000 amperes.
5)
Inrush - for a single bank, the inrush current is always less than the short-circuit value
at the bank location.
13
6)
Inrush - for parallel banks, the inrush current is always much greater than for a single
bank.
7)
Expulsion fuses offer the following advantages:
a. they are inexpensive and easily replaced.
b. offers a positive indication of operation.
8)
Current limiting fuses are used where:
a. a high available short circuit exceeds the expulsion or non-vented fuse rating.
b. a current limiting fuse is needed to limit the high energy discharge from adjacent
parallel capacitors effectively.
c. a non-venting fuse is needed in an enclosure.
9)
The fuse link rating should be such that the link will melt in 300 seconds at 240 to 350
percent of normal load current.
10)
The fuse link rating should be such that it melts in one second at not over 220 amperes
and in .015 seconds at not over 1700 amperes.
11)
The fuse rating must be chosen through the use of melting time-current characteristics
curves, because fuse links of the same rating, but of different types and makes have a
wide variation in the melting time at 300 seconds and at high currents.
12)
Safe zone – usually greater damage than a slight swelling.
a. Zone 1 - suitable for locations where case rupture/or fluid leakage would
present no hazard.
b. Zone 2 - suitable for locations which have been chosen after careful consideration
of possible consequences associated with violent case ruptures.
c. Hazardous zone – unsafe for most applications. The case will often rupture
with sufficient violence to damage adjacent units.
13)
Manufacturers normally recommend that the group fuse size be limited by the 50%
probability curve or the upper boundary of Zone 1.
14)
Short circuit current in an open wye bank is limited to approximately 3 times normal
current.
15)
Current limiting fuses can be used for delta or grounded wye banks provided there is
sufficient short circuit current to melt the fuse within ½ cycle.
K. Conductor Burndown
Conductor burndown is a function of (1) conductor size (2) whether the wire is bare or covered (3) the
magnitude of the fault current (4) climatic conditions such as wind and (5) the duration of the fault
current.
If burndown is less of a problem today than in years past it must be attributed to the trend of using
heavier conductors and a lesser use of covered conductors. However, extensive outages and hazards
to life and property still occur as the result of primary lines being burned down by flashover, tree
branches failing on lines, etc. Insulated conductors, which are used less and less, anchor the arc at one
14
point and thus are the most susceptible to being burned down. With bare conductors, except on multigrounded neutral circuits, the motoring action of the current flux of an arc always tends to propel the arc
along the line away from the power source until the arc elongates sufficiently to automatically extinguish
itself. However, if the arc encounters some insulated object, the arc will stop traveling and may cause
line burndown.
With tree branches falling on bare conductors, the arc may travel away and clear itself; however, the arc
will generally re-establish itself at the original point and continue this procedure until the line burns down
or the branch falls off the line. Limbs of soft spongy wood are more likely to burn clear than hard wood.
However one-half inch diameter branches of any wood, which cause a flashover, are apt to burn the
lines down unless the fault is cleared quickly enough.
Figure 7 shows the burndown characteristics of several weatherproof conductors. Arc damage curves
are given as arc is extended by traveling along the phase wire, it is extinguished but may be reestablished across the original path. Generally, the neutral wire is burned down.
Figure 7. Burndown characteristics of several weatherproof conductors
L. Device Numbers
The devices in the switching equipment are referred to by numbers, with appropriate suffix letters (when
necessary), according to the functions they perform. These numbers are based on a system which has
been adopted as standard for automatic switchgear by the American Standards Association.
15
Device No.
Function and Definition
11
CONTROL POWER TRANSFORMER is a transformer which
serves as the source of a-c control power for operating a-c devices.
24
BUS-TIE CIRCUIT BREAKER serves to connect buses or bus
sections together.
27
A-C UNDERVOLTAGE RELAY is one which functions on a given
value of single-phase a-c under voltage.
43
TRANSFER DEVICE is a manually operated device which transfers
the control circuit to modify the plan of operation of the switching
equipment or of some of the devices.
50
SHORT-CIRCUIT SELECTIVE RELAY is one which function
instantaneously on an excessive value of current.
51
A-C OVERCURRENT RELAY (inverse time) is one which functions
when the current in an a-c circuit exceeds a given value.
52
A-C CIRCUIT BREAKER is one whose principal function is usually
to interrupt short-circuit or fault currents.
64
GROUND PROTECTIVE RELAY is one which functions on failure
of the insulation of a machine, transformer or other apparatus to
ground. This function is, however, not applied to devices 51N and
67N connected in the residual or secondary neutral circuit of
current transformers.
67
A-C POWER DIRECTIONAL OR A-C POWER DIRECTIONAL
OVERCURRENT RELAY is one which functions on a desired value
of power flow in a given direction or on a desired value of
overcurrent with a-c power flow in a given direction.
78
PHASE-ANGLE MEASURING RELAY is one which functions at a
predetermined phase angle between voltage and current.
87
DIFFERENTIAL CURRENT RELAY is a fault-detecting relay which
functions on a differential current of a given percentage or amount.
M. Protection Abbreviations
CS -Control Switch
X - Auxiliary Relay
Y - Auxiliary Relay
YY - Auxiliary Relay
Z - Auxiliary Relay
1)
To denote the location of the main device in the circuit or the type of circuit in which the device is
used or with which it is associated, or otherwise identify its application in the circuit or
equipment, the following are used:
N – Neutral
SI - Seal-in
16
2)
To denote parts of the main device (except auxiliary contacts as covered under below), the
following are used:
H - High set unit of relay
L - Low set unit of relay
OC - Operating coil
RC - Restraining coil
TC - Trip coil
3)
To denote parts of the main device such as auxiliary contacts (except limit-switch contacts
covered under 3 above) which move as part of the main device and are not actuated by external
means. These auxiliary switches are designated as follows:
“a" - closed when main device is in energized or operated position
"b” - closed when main device is in de-energized or non-operated position.
4)
To indicate special features, characteristics, the conditions when the contacts operate, or are
made operative or placed in the circuit, the following are used:
AERHRMTDCTDDOTDO-
Automatic
Electrically Reset
Hand Rest
Manual
Time-delay Closing
Time-delay Dropping Out
Time-delay Opening
To prevent any possible conflict, one letter or combination of letters has only one meaning on
individual equipment. Any other words beginning with the same letter are written out in full each
time, or some other distinctive abbreviation is used.
N. Simple Coordination Rules
3Ø Main
Time Overcurrent Pickup
2x Load
2x Load (Minimum)
1Ø Lateral
2x Full Load
(Minimum)
2x Full Load
(Minimum)
Figure 8. “Burke 2X rule”
17
There are few things more confusing in distribution engineering than trying to find out rules of
overcurrent coordination, i.e., what size fuse to pick or where to set a relay, etc. The patented (just
kidding) Burke 2X Rule states that when in doubt pick a device of twice the rating of what it is you're
trying to protect as shown in Figure 8. This rule picks the minimum value you should normally consider
and is generally as good as any of the much more complicated approaches you might see. For various
reasons, you might want to go higher than this, which is usually OK. To go lower, you will generally get
into trouble. Once exception to this rule is the fusing of capacitors where minimum size fusing is
important to prevent case rupture.
O. Lightning Characteristics
1)
Stroke currents
a.
b.
c.
Maximum - 220,000 amperes
Minimum - 200 amperes
Average-10,000 to 15,000 amperes
2)
Rise times – 1 to 100 microseconds
3)
Lightning polarity - approximately 95% are negative
4)
Annual variability (Empire State Building)
a. Maximum number of hits
b. Average
c. Minimum
50
21
3
5)
Direct strokes to T line - 1 per mile per year with keraunic levels between 30 and 65.
6)
Lightning discharge currents in distribution arresters on primary distribution lines
(composite of urban and rural)
Max. measured to date –
I% of records at least
5% of records at least
10% of records at least
50% of records at least
7)
approx. 40,000 amps
22,000 amps
10,500 amps
6,000 amps
1,500 amps
Percent of distribution arresters receiving lightning currents at least as high as in Col. 4.
Table 2
18
Col. 1
Urban Circuits
Col. 2
Semi-urban Circuits
Col. 3
Rural Circuits
Col. 4
Discharge Circuits
20%
35%
45%
1,000 amps
1.6%
7%
12%
5,000 amps
.55%
3.5%
6%
10,000 amps
.12%
.9%
2.4%
20,000 amps
.4%
40,000 amps
8)
Number of distribution arrester operations per year (excluding repeated operations on
multiple strokes).
Average on different systems - range
Max. recorded
Max. number of successive
operations of one arrester
during one multiple lightning
stroke -
.5 to 1.1 per year
6 per year
12 operations.
P. Arc Impedence
While arcs are quite variable, a commonly accepted value for currents between 70 and 20,000 amperes
has been an arc drop of 440V per foot, essentially independent of current magnitude.
Zarc =
440 l / I
l = length of arc (in feet)
I = current
Assume:
IF = 500 amperes = I
Arc length = 2 ft.
Zarc =
440 • 2/5000
= .176 ohms
∴ Arc impedance is pretty small.
19
III.
Transformers
A. Saturation Curve
Figure 9
B. Insulation Levels
The following table gives the American standard test levels for insulation of distribution transformers.
Table 3
Windings
Bushings
Impulse Tests
Bushing Withstand Voltages
(1.2 x 50 Wave)
Chopped Wave
Insulation
Class and
Nominal
Bushing
Rating
Minimum Time to
Full
60-cycle One-
60-cycle 10-
Impulse 1.2 x 50
Dielectric
Flashover
Wave
minute Dry
second Wet
Wave
Tests
kV
kV
kV
Microseconds
kV
kV (Rms)
kV (Rms)
kV (Crest)
1.2
10
36
1.0
10
10
6
30
21
20
60
5.0
19
69
1.5
60
8.66
26
88
1.6
75
27
24
75
1.8
95
35
30
95
70
60
150
15.0
34
110
25.0
40
145
1.9
125
34.5
70
175
3.0
150
95
95
200
3.0
250
120
120
250
3.0
350
175
175
350
46.0
69.0
20
Lowfrequency
95
140
290
400
C. Δ-Y Transformer Banks
The following is a review of fault current magnitudes for various secondary faults on a Δ-Y transformer
bank connection:
Figure 10. Δ-Y transformer banks
D. Transformer Loading
When the transformer is overloaded, the high temperature decreases the mechanical strength and
increases the brittleness of the fibrous insulation. Even though the insulation strength of the unit may
not be seriously decreased, transformer failure rate increases due to this mechanical brittleness.
•
Insulation life of the transformer is where it loses 50% of its tensile strength. A transformer
may continue beyond its predicted life if it is not disturbed by short circuit forces, etc.
•
The temperature of top oil should never exceed 100 degrees C for power transformers with
a 55 degree average winding rise insulation system. Oil overflow or excessive pressure
could result.
•
The temperature of top oil should not exceed 110C for those with a 65C average winding
rise.
•
Hot spot should not exceed 150C for 55C systems and 180C for 65C systems. Exceeding
these temperature could result in free bubbles that could weaken dielectric strength.
•
Peak short duration loading should never exceed 200%.
21
•
Standards recommend that the transformer should be operated for normal life expectancy.
In the event of an emergency, a 2.5% loss of life per day for a transformer may be
acceptable.
•
Percent Daily Load for Normal Life Expectancy with 30°C Cooling Air
Table 4
Duration of
Peak load
Hours
0.5
1
2
4
8
22
Self-cooled with % load before peak of:
50%
189
158
137
119
108
70%
178
149
132
117
107
90%
164
139
124
113
106
IV.
Instrument Transformers
A. Two Types
1) Potential (Usually 120v secondary)
2) Current (5 amps secondary at rated primary current)
B. Accuracy
3 factors will influence accuracy:
1) Design and construction of transducer
2) Circuit conditions (V, I and f)
3) Burden (in general, the higher the burden, the greater the error)
C. Potential Transformers
IN
OU
RCF=
True Ratio
Marked Ratio
(RCF generally >1)
E2
Zb
Burden is measured in VA ∴ VA =
Assume:
10:1
R
X
10V
True Ratio =
10
.9
.9v
= 11.1
⇒ RCF =
Marked Ratio =
Zb
10
1
11.1
10
= 1.11
= 10
23
Voltage at secondary is low and must be compensated by 11% to get the actual primary voltage using
the marked ratio.
D. Current Transformer
True Ratio = Marked Ratio X RCF
True Ratio
∴RCF =
Marked Ratio
E. H-Class
Vs is fixed
Is varies
Nearly constant ratio error in %
Burdens are in series
e.g. 10H200 ⇒ 10% error @ 200V
∴ 20 (5 amp sec) = 100 amps ⇒ Zb = 200/100 = 2Ω
⇒ 5 amps to 100 amps has ≤ 10% error if Zb = 4Ω
OR
If Zb = 4Ω
200V/4Ω
= 50 amp (10 times normal)
H-class – constant magnitude error (variable %)
L-class – constant % error (variable magnitude)
Example:
True Ratio = Marked Ratio X RCF
Assume Marked is 600/5 or 120:1 at rated amps and 2 ohms
5 amp
2Ω
1.002 and 1.003 are from
manuf. chart
@ 100% amps True = 120 X 1.002 X 5 secondary
primary = 600 X 1.002 = 601.2
@ 20% amps True = 600 X .2 X 1.003 = 120.36 (Marked was 120)
F. Current Transformer Facts
1)
Bushing CTs tend to be accurate more on high currents (due to large core and less saturation)
than other types.
2)
At low currents, BCT's are less accurate due to their larger exciting currents.
3)
Rarely, if ever, is it necessary to determine the phase-angle error.
24
4)
Accuracy calculations need to be made only for three-phase and single-phase to ground faults.
5)
CT burden decreases as secondary current increases, because of saturation in the magnetic
circuits of relays and other devices. At high saturation, the impedance approaches the dc
resistance.
6)
It is usually sufficiently accurate to add series burden impedance arithmetically.
7)
The reactance of a tapped coil varies as the square of the coil turns, and the resistance varies
approximately as the turns.
8)
Impedance varies as the square of the pickup current.
9)
Burden impedance are always connected in wye.
10)
"Ratio correction factor” is defined as that factor by which the marked ratio of a current
transformer must be multiplied to obtain the true ratio. These curves are considered standard
application data.
11)
The secondary-excitation-curve method of accuracy determination does not lend itself to general
use except for bushing-type, or other, CT's with completely distributed secondary leakage, for
which the secondary leakage reactance is so small that it may be assumed to be zero.
12)
The curve of rms terminal voltage versus rms secondary current is approximately the
secondary-excitation curve for the test frequency.
13)
ASA Accuracy Classification:
a. Method assumes CT is supplying 20 times its rated secondary current to its burden.
b. The CT is classified on the basis of the maximum rms value of voltage that it can
maintain at its secondary terminals without its ratio error exceeding a specified amount.
c.
"H" stands for high internal secondary impedance.
d. "L" stands for low internal secondary impedance (bushing type).
e. 10H800 means the ratio error is l0% at 20 times rated voltage with a maximum
secondary voltage of 800 and high internal secondary impedance.
f.
Burden (max) - maximum specified voltage/20 x rated sec.
g. The higher the number after the letter, the better the CT.
h. A given l200/5 busing CT with 240 secondary turns is classified as l0L400: if a 120-turn
completely distributed tap is used, then the applicable classification is 10L200.
i.
For the same voltage and error classifications, the H transformer is better than the L for
currents up to 20 times rated.
25
G. Glossary of Transducer Terms
Voltage Transformers - are used whenever the line voltage exceeds 480 volts or whatever lower
voltage may be established by the user as a safe voltage limit. They are usually rated on a basis of 120
volts secondary voltage and used to reduce primary voltage to usable levels for transformer-rated
meters.
Current Transformer - usually rated on a basis of 5 amperes secondary current and used to reduce
primary current to usable levels for transformer-rated meters and to insulate and isolate meters from
high voltage circuits.
Current Transformer Ratio - ratio of primary to secondary current. For current transformer rated 200:5,
ratio is 200:5 or 40: 1.
Voltage Transformer Ratio - ratio of primary to secondary voltage. For voltage transformer rated
480:120, ratio is 4:1, 7200:120 or 60:1.
Transformer Ratio (TR) - total ratio of current and voltage transformers. For 200:5 C.T. and 480:120
P.T., TR = 40 x 4 = 160.
Weatherability - transformers are rated as indoor or outdoor, depending on construction (including
hardware).
Accuracy Classification - accuracy of an instrument transformer at specified burdens. The number
used to indicate accuracy is the maximum allowable error of the transformer for specified burdens. For
example, 0.3 accuracy class means the maximum error will not exceed 0.3% at stated burdens.
Rated Burden - the load which may be imposed on the transformer secondaries by associated meter
coils, leads and other connected devices without causing an error greater than the stated accuracy
classification.
Current Transformer Burdens - normally expressed in ohms impedance such as B0.1,B-0.2,B-0.5,B0.9,or B-1.8.Corresponding volt-ampere values are 2.5, 5.0, 12.5, 22.5, and 45.
Voltage Transformer Burdens - normally expressed as volt-amperes at a designated power factor.
May be W, X, M, Y, or Z where W is 12.5 V.A. @ 0. 1Opf; X is 25 V.A. @ 0.70pf, M is 35 V.A. @ 0.20 pf,
Y is 75 V.A. @ 0.85pf and Z is 200 V.A. @0.85 pf. The complete expression for a current transformer
accuracy classification might be 0.3 at BO. 1, B-0.2, and B-0. 5, while the potential transformer might be
0.3 at W, X, M, and Y.
Continuous Thermal Rating Factor (TRF) - normally designated for current transformers and is the
factor by which the rated primary current is multiplied to obtain the maximum allowable primary current
without exceeding temperature rise standards and accuracy requirements. Example - if a 400:5 CT has
a TRF of 4.0, the CT will continuously accept 400 x 4 or 1600 primary amperes with 5 x 4 or 20 amperes
from the secondary. The thermal burden rating of a voltage transformer shall be specified in terms of
the maximum burden in volt-amperes that the transformer can carry at rated secondary voltage without
exceeding a given temperature rise.
Rated Insulation Class - denotes the nominal (line-to-line) voltage of the circuit on which it should be
used. Associated Engineering Company has transformers rated for 600 volts through 138 kV.
Polarity - the relative polarity of the primary and secondary windings of a current transformer is
indicated by polarity marks (usually white circles), associated with one end of each winding. When
26
current enters at the polarity end of the primary winding, a current in phase with it leaves the polarity end
of the secondary winding. Representation of primary marks on wiring diagrams are shown as black
squares.
Hazardous Open-Circulating - operation of CTs with the secondary winding open can result in a high
voltage across the secondary terminals which may be dangerous to personnel or equipment. Therefore,
the secondary terminals should always be short circuited before a meter is removed from service. This
may be done automatically with a by-pass in the socket or by a test switch for A-base meters.
27
V. Rules of Thumb for Uniformly Distributed Loads
It is very helpful to be able to perform a quick sanity check of system conditions "usually in your head" to
develop a "feel" for whether there might be a problem. Three very helpful rules assuming a uniformly
distributed load are as follows:
1)
Capacitor placement - "2/3 rule"
2/3 L
2/3 kVAR
Figure 11. Optimum capacitor placement
"Optimum placement of capacitors at 2/3 the distance of the line, sizing the bank to meet 2/3 of
the feeder VAR needs."
2)
Losses - "1/3 rule”
1/3 L
100% Load
Figure 12. Equivalent losses
"Place all the load at 1/3 the distance to obtain the same losses as an evenly distributed load."
3)
Voltage drop - "1/2 rule"
1/2 L
100% Load
Figure 13. Equivalent voltage drop
"Place 100% of load at 1/2 point on the feeder to obtain the same voltage drop as the voltage at
the end of the feeder for a uniform distribution load."
28
VI. Conductors and Cables
A. Conductor Current Rating
Table 5
Wire Size
Amps
6
4
2
1/0
2/0
3/0
4/0
336
397
565
795
55
75
105
145
170
200
240
330
370
480
620
B. Facts on Distribution Cable
1)
Cable replacement occurs usually after 2 or 3 failures.
2)
TRXLPE and EPR use is increasing.
3)
Conduit is on the rise but most cable is direct buried.
4)
About 60% of all cable is still going in direct buried.
5)
Most common method to find fault is radar with a thumper, followed by a thumper by
itself then an FCI.
6)
Most utilities use an insulating jacket type, followed by the use of the semi-conducting
jacket.
7)
30% use fiber optics in the underground system for telephone, SCADA, computer-tocomputer, video, etc.
8)
Jacketed EPR has good record.
9)
HMWPE and non-jacketed XLPE have bad records.
29
C. Impedance of Cable
Impedance of the main feeder is:
1)
.122 + j .175 ohms/mile (12kV, 1000 KCM)
2)
.119 + j .190 ohms/mile (35kV, 1000 KCM)
Impedance of the lateral feed is:
1)
.502 + j .211 ohm/mile (12kV, 4/0, 3∅)
2)
.500 + j .238 ohm/mile (34kV, 4/0, 3∅)
3)
1.445 + j .552 ohms/mile (12kV, #4, 1∅)
4)
1.607 + j .595 ohms/mile (34kV, #4, 1∅)
Table 6
30
VII. DSG – General Requirements
1)
Voltage - Customer shall not cause voltage excursions. Any voltage excursions must
be disconnected within 1 second.
2)
Flicker - 2% at the dedicated transformer.
3)
Frequency - < 5% Hz and removed in < .2 seconds
4)
Harmonics - < 5% - sum of squares
5)
Faults - Remove DSG in < 1 second for utility fault
6)
Power factor - ≥ .85
31
VIII. Dangerous Levels of Current
Figure 14. Effect of Current on Humans
32
IX. Capacitor Formulas
Nomenclature: C = Capacitance in μF
1)
V = Voltage
A = Current
K = 1000
Capacitors connected in parallel: CTotal = C1 + C2 + C3 + - -
2)
Capacitors connected in series:
CTotal =
C1 x C2
C1 + C2
For two capacitors in series
CTotal =
1
+
1 + 1
C1
C2
3)
4)
5)
For more than two capacitors in series
1
C3
+ --
Reactance – Xc (Capacitive)
a.
Xc =
106
(2πf)C
b.
Xc =
2653
C
b.
Xc =
at 60HZ (1μF = 2653 Ω)
KV2 x 103
KVAR
Capacitance – C
a.
C=
b.
C=
106
(2πf) Xc
KVAR x 103
(2πf)(KV)2
Capacitive Kilovars
a.
KVAR =
(2πf)C (KV)2
103
b.
KVAR =
103 (KV)2
Xc
33
6)
Miscellaneous
a.
Power Factor =
Tan θ
34
KVAR
KW
Cos θ
KW
KVA
X. European Practices
A. Primary
European
Generator
EHV
400 kV
500 kV
765 kV
345 kV
500 kV
765 kV
Distribution System
MV
33 kV
22 kV
11 kV
HV
36 kV to
300 kV
34.5 kV
69 kV
115 kV
138 kV
230 kV
34.5 kV
24.9 kV
13.8 kV
13.2 kV
12.47 kV
380/222V
416/240V
120/240V
208/120V
United States
Figure 15. European / US Voltage Levels
Secondary
Europe
U.K.
U.S.
380Y/220V, 3-Phase, 4-Wire
416Y/240V, 3Ø, 4-Wire
208Y/120V, 3Ø, 4-Wire
&
1Ø, 120/240V, 3-Wire
Figure 16. European Secondary
B. Relays
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
TMS - Time multiplier setting (similar to time dial)
CTU - Earth fault relay set between 1 % and 16 % of rated current
CDG 11 - Standard overcurrent relay
CDG 13 - Very inverse
CDG 14 - Extremely inverse relay
CTU 12 - Definite time relay
35
C. Earth Fault Protection
ƒ
ƒ
ƒ
Based on the premise that all loads are 3 phase and balance
Considers the effect of line capacitance mismatch
Uses residual current
D. General
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
Autoreclosure on overhead is normal
Use normally open loop most of the time
Even on a 3-wire system there may be some unbalance due to capacitors which must be
considered when setting the earth relay
Conventional relays will not operate for unearthed systems
For ungrounded systems:
‰
current and voltage unbalance must exceed a predetermined amount
‰
phase angle must occur within a specified range (makes capacitor application difficult)
‰
I (fault) is highly influenced by the capacitance of the network
Maximum fault levels allowed are:
Table 7
KV
33
22
11
ƒ
ƒ
ƒ
kA
25
20
20
11-kV system is mostly radial and underground
33-kV system is looped and mostly underground
Most 4l5-volt transformers are l00 kVA or less and about 50% loaded
Table 8 - Distribution System Design Comparison
U.S.
120/240
1-phase transformers heavily overloaded – 25
kVA typical.
4 homes/transformer fairly typical
Higher load density
Fuses are typically expulsion
36
Europe
380 Wye/220, 4-wire.
416 Wye/240, 4-wire (UK)
Residential units in 300-500 kVA range No
overload
100 to 200 dwellings per transformer 3-phase
xfrms >> $ 1-phase 5 to 10 radial, 3-phase, 4-wire
secondary feeds, per transformer
Less load per home than U.S.
Fuses are current limiting
132 kV
33 kV
Zig-Zag Resistance
Grounded
No Fuses
Clearing Time 5-8 Cycles
Distance (sometimes) and Overcurrent
Zone 1-5-8 Cycles
Zone 2-30-33
33 kV
11 kV
Uniground
Figure 17. 33 kV/11 kV Distribution
37
XI. Power Quality Data
A. Momentaries
Typical number of customer momentaries caused by the utility system ≈ 5
Typical number of customer momentaries for all causes ≈ 10
B. Sags
Typical number of customer sags caused by the utility system ≈ 50
Typical number of customer sags for all causes ≈ 350
*Voltage below .9 PU of nominal
C. Power Quality Organizations
Committee/Standard
Activity
Characterizing Power Quality/Power Quality Indices/General Power Quality
Power Quality Standards coordinating committee
SCC-22
IEEE 1159
Monitoring Power Quality
IEEE 141
Red Book
IEEE 241
Gray Book
Coordinates all power quality standards activities
A number of task forces addressing different aspects of power
quality monitoring requirements and definitions
General guidelines for industrial commercial power systems
General guidelines for commercial power systems
Harmonics
IEEE P519A
Filter Design Task Force
Task Force on Harmonic Limits for Single Phase
Equipment
Developing application guide for applying harmonic limits
Guidelines for harmonic filter design
Developing guidelines for applying harmonic limits at the
equipment level
Voltage Sags/Momentary Interruptions
IEEE 493
Gold Book
IEEE 1346
Industrial and commercial Power system Reliability
Evaluating compatibility of power systems for industrial
process controllers
Steady State Regulation, Unbalance, and Flicker
ANSI C84.1
IEEE Flicker Task Force
Voltage rating for power systems and equipment
Developing a coordinated approach for characterizing flicker
Wiring and Grounding/Powering Sensitive Equipment
IEEE 1100 Emerald Book
National Electric Code
IEEE 142
Green Book
Guidelines for powering and grounding sensitive equipment
Safety requirements for wiring and grounding
Industrial and commercial Power System grounding
Transients
OEEEA NSI C62
Guides and standards on surge protection
Distribution Systems/Custom Power Solution
IEEE 1250 Distribution Power Quality Working
Group
IEEE 1409
Custom Power Task Force
38
Guide on equipment sensitive to momentary voltage variations
Developing guidelines for application of power electronics
technologies for power quality improvement on the distribution
system
D. Categories and Typical Characteristics of Power System Disturbances
Table 9
Transients
Impulsive
Oscillatory
nsec to msec
3 msec
Typical Voltage
Magnitude
na
0.8 pu
Short Duration
Variations
Instantaneous Sag
.5 – 30 cycles
0.1 – 0.9 pu
Instantaneous Swell
Momentary
Interruption
Momentary Sag
Momentary Swell
Temporary
Interruption
Temporary Sag
Temporary Swell
.5 – 30 cycles
1.1 – 1.8 pu
0.5 cycles – 3 sec
Less than 0.1 pu
30 cycles – 3 sec
30 cycles – 3 sec
0.1 – 0.9 pu
1.1 – 1.4 pu
3 sec – 1 min
Less than 0.1 pu
3 sec – 1 min
3 sec – 1 min
0.1 – 0.9 pu
1.1 – 1.4 pu
Sustained Interruption
Longer 1 minute
0.0 pu
Undervoltage
Overvoltage
Longer 1 minute
Longer 1 minute
Steady state
Steady state
Steady state
Steady state
Steady state
Steady state
Intermittent
0.8 – 0.9 pu
1.1 – 1.2 pu
.5 – 2%
.05 – 2%
0 – 20%
0 – 20%
NA
0 – 1%
0.1 – 7%
Less than 10 sec
NA
Typical Duration
Categories
Long Duration
Variations
Voltage Imbalance
Waveform Distortion
Voltage Fluctuations
Power Frequency
Variations
DC Offset
Harmonics
Inter-harmonics
Notching
Noise
39
XII. Electricity Rates
Table 10
For Medium Size Commercial and Industrial
Utility
Commercial $/kWh
Industrial $/kWh
A
B
C
D
E
F
G
$0.1067
$0.1761
$0.1672
$0.1482
$0.1328
$0.1279
$0.1690
$0.0899
$0.0732
$0.1058
$0.0998
$0.1039
$0.0720
$0.0950
Table 11
Twelve Most Expensive Companies Investor-Owned Electric Utilities
Dec.'91 - Feb.'92
Company
State
National Rank
Long Island Lighting Co.
New York
$0.156
1
Philadelphia Electric Co.
Pennsylvania
$0.152
2
Pennsylvania Power Co.
Pennsylvania
$0.148
3
Duquesne Light Co.
Pennsylvania
$0.146
4
Consolidated Edison Co.
New York
$0.137
5
Western Mass. Electric Co.
Massachusetts
$0.137
6
Hawaii Electric Co.
Hawaii
$0.136
7
Nantucket Electric Co.
Massachusetts
$0.135
8
Commonwealth Electric Co.
Massachusetts
$0.131
9
Orange & Rockland Utilities Inc.
New York
$0.130
10
Citizens Utilities Co. – Kauai Div.
Hawaii
$0.125
11
United Illuminating Co.
Connecticut
$0.124
12
*For monthly residential sales of 500 kWh.
Source:
40
Avg. Cost $/kWh*
National Association of Regulatory Utility Commissioners
Table 12
Twelve Least Expensive Companies Investor-Owned Electric Utilities
Dec.'91 - Feb.'92
Company
State
Washington Water Power Co.
Idaho
Avg. Cost $/kWh*
National Rank
$0.041
191
Pacific Power & Light Co.
Washington
$0.043
192
Washington Water Power Co.
Washington
$0.044
189
Idaho Power Co.
Oregon
$0.047
188
Idaho Power Co.
Idaho
$0.047
187
Kentucky Utilities Co.
Kentucky
$0.051
186
Portland General Elec. Co.
Oregon
$0.052
185
Puget Sound Power & Light Co.
Washington
$0.053
184
Potomac Electric Power Co.
Dist. of Col.
$0.054
183
Minnesota Power & Light Co.
Minnesota
$0.054
182
Pacific Power & Light Co.
Oregon
$0.055
181
Kingsport Power Co.
Tennessee
$0.056
180
*For monthly residential sales of 500 kWh.
Source:
National Association of Regulatory Utility Commissioners
41
XIII. Costs
A. General
1)
Annual system capacity:
Generation:
Transmission:
Distribution:
Total:
2)
Cost of capacitors (installed)
Substations:
Line:
Padmounted:
3)
$ 704/kW
$ 99/kW
$ 666/kW
$1469/kW
$ 9/kVAR
$ 5.5/kVAR
$ 21/kVAR
Transformers (installed)
a. Single phase padmounts (installed)
12.5 kV (loop feed)
34.5 kV (loop feed)
25 kVA
$2552
$3119
50 kVA
$2986
$3931
75 kVA
$3591
$4725
100 kVA
$4972
$5728
b. Three Phase Padmounts
12.5 kV (loop feed)
34.5 kV (loop feed)
75 kVA
$ 7,749
$10,584
150
$ 9,450
$11,605
300
$11,718
$15,574
500
$13,608
$20,034
750
$21,357
$21,377
1000
$25,515
$28,350
1500
-
$40,824
2500
-
$50,841
NOTE: Above costs include necessary cable terminations, pads, misc. material and transformer,
but no primary or secondary cable.
42
4)
Substation costs (includes land, labor, and material)
a.
b.
c.
d.
e.
5)
115-13.2kV, 20/37.3 MVA, 4 feeder substation
35-12.5 kV, 12/16/20 MVA, 2 feeder substation
115-35kV, 60/112 MVA, 5 feeder substation
230-13.2 kV, 27/45 MVA, 5 feeder substation
230-34.5 kV, 60/112 MVA, 5 feeder substation
$3,348,000
$1,026,000
$4,050,000
$3,960,000
$5,040,000
Miscellaneous costs:
a. Cable (approximate)
•
•
•
•
•
•
•
•
6)
$
90/ft
$
38/ft
$
63/ft
$ 2,698
$ 2,822
$ 20,871
$ 11,203
$ 11,367
Cost of replacing cable:
a.
b.
7)
Mainline, conduit
Mainline, D.B.
Lateral, conduit
Install transformer
Change out transformer
Install - 3∅ switch
Replace - 3∅ switch
Install - 1∅ fuse switch
1∅ - $180/ft.
3∅ - $360/ft.
Elbows (installed) - $111 each
43
XIV. Reliability Data
Table 13
Failure Rate Data
Component
Primary Cable (polyethylene)
Secondary Cable (polyethylene)
Transformers, single phase, padmounted
Transformers, three-phase, padmounted
Transformers, single phase, subsurface
Switches, oil, subsurface
Switches, air, padmounted
Fuse cabinet, single phase, padmounted
Fuse cabinet, three-phase, padmounted
Primary splices, rubber molded
Elbows:
Rubber molded, loadbreak
Rubber molded, non-loadbreak
Tees, 600 amp
Typical values for customer based indices are:
•
•
•
44
SAIDI - 96 min/yr.
SAIFI - 1.18 interruptions/yr.
CAIDI - 81.4 min/yr.
Failure Rate
6/100 mi-yr (conductor miles)
10/100 mi-yr (circuit miles)
0.4%/yr
0.62%/yr
0.3%/yr
0.12%/yr
0.12%/yr
0.1%/yr
0.2%/yr
.01%/yr
.06%/yr
.06%/yr
.02%/yr
XV. Industrial and Commercial Stuff
Introduction
Utility engineers have historically needed to know a lot about their own system and very little about their
customers system and loads. Competitive times and the emphasis on power quality have forced the
utility engineer to venture to the "other side of the meter" to address the power related concerns and
problems of specific industrial processes and components. The purpose of this section is to address
some of the more commonly encountered terminology, equipments and problems that the utility
distribution engineer generally has a hard time finding.
Motors
a.
Major Categories of Motors
Alternating Current Types
Three-Phase
Induction
Synchronous
Single-Phase
Induction-Run, Capacitor Start
Induction-Run, Split Phase Start
Shaded-Pole
Universal (Commutator)
Repulsion
Direct Current Types
Shunt-Characteristic:
Shunt-Characteristic:
Series-Characteristic:
Compound Wound
b.
Electromagnetic Field
Permanent Magnet Field
Series Field Only
KVA/Hp Conversions (at full load)
Induction 1 - 100 Hp
Induction 101 - 1000 Hp
Induction > 1000 Hp
Synchronous 0.8 pf
Synchronous 0.9 pf
Synchronous 1.0 pf
KVA I HP
1.0
0.95
0.9
1.0
0.9
0.8
45
c.
Reduced-voltage Starters
Table 14
Reduced-Voltage Starter Type
Autotransformer – 50% tap
Autotransformer – 65% tap
Autotransformer – 80% tap
Wye-delta
Part-Winding
Primary Resistor – 80% tap
Primary Resistor – 65% tap
Line Current As % Of Full-Voltage Starting
30%
47%
69%
33%
70%
80%
65%
d. Characteristics of Motors
DC Motors
• Advantage of DC Motor is that the torque-speed characteristic can be varied over
a wide range and still have high efficiency
• 3 Basic Types - Shunt, Series and Compound
• Shunt - In this motor the field current is independent of the armature having been
diverted (shunted) through its own separate winding. Increasing the field current
actually causes the motor to slow down. Torque and power however are higher.
• Series - The series motor is identical in construction to the shunt motor except the
field is connected in series with the armature. At startup, armature current is high,
so flux is high and torque is high. If load decreases, speed goes up. Series
motors are for high torque, low speed applications such as the starter motor of a
car or the motors used for electric locomotives.
• Compound - A compound motor carries both a series field and a shunt field. The
shunt field is always stronger. As load increases, the shunt field remains the same
but the series field increases. At no load it looks like a shunt motor.
The diagram shown below illustrates the basic characteristics of these motors:
Figure 18 - Typical speed versus load characteristics of various dc motors
46
Induction Motors
•
•
•
•
Most frequently used in industry (simple, rugged and easy to maintain)
Essentially constant speed from 0 to full load
Not easily adapted to speed control
Parts:
¾ Stationary stator
¾ Revolving rotor (slip ring at end)
¾ Conventional 3 phase winding
¾ Squirrel-cage windings (copper bars shorted at end)
The characteristics of the induction motor are illustrated below:
Figure 19
Synchronous Motors
•
•
•
•
•
The most obvious characteristic of a synchronous motor is its strict
synchronism with the power line frequency.
Its advantage to the industrial user is its higher efficiency and low cost in large
sizes
Biggest disadvantage is added complications of motor starting.
A synchronous motor is identical to a generator of the same rating.
Synchronous motors are only selected for applications with relatively
infrequent starts since starting is more difficult and usually requires the use of
induction (squirrel cage) motor.
e. Adjustable-Speed Drives
•
•
•
Adjustable speed drives have the advantage of being both efficient and reliable
Used for compressors, pumps, and fans that have variable-torque requirements
Six basic types:
• DC drive with DC motor
• Voltage-source inverter with induction motor
• Slip-energy recovery system with wound-rotor motor
• Current-source inverter with induction motor
• Load-commutated inverter with synchronous motor
• Cycloconverter drive for either a synchronous or an induction motor
The figure, shown below, is a one line diagram for a typical current-source inverter. The
current-source inverter has a phase controlled rectifier that provides a DC input to a six-step
inverter. The reactor provides some filtering. Control of the inverter serves to regulate current
and frequency, rather than voltage and frequency as with the voltage-source inverter.
47
Figure 20 – Typical current-source inverter (A) and one with a 12-pulse
power conversion unit (B) required by larger motors
48
XVI. Maxwell’s Equations
When in doubt, you can always go back and derive whatever you need to know using Maxwell’s
equations (that's what my professor told me ……. right!!!!!!!!) So here goes:
Gauss’ law for electric fields
Q
∫∫ E • dA = ε
0
Gauss’ law for magnetic fields
∫∫ B • d A = 0
Generalized Ampere’s law
∫ B • ds = μ I + μ ε
0
0 0
d
E • dA
dt ∫∫s
Faraday’s law
∫ E • ds =
d
B • dA
dt ∫∫s
Got that!!!!!!!!
49
Hard to Find….Part II
XVII. Introduction
Since Part I was a huge success, I decided to write Part II to address issues I’m seeing as a result of deregulation. As usual, many of the topics are completely unrelated and it is questionable if they have
anything to do with the major theme. They are simply things that I see from time to time that keep
cropping up and I forget where the reference material I found on that topic might be. So, I put them
here!!!!
As usual, some things in this document are not guaranteed. I have tried to find good sources for the
majority of this material. Personally, I only write what I believe and try very hard to make it correct, as
well as useful
Finally, a note to the “New Engineer”: Computer programs are useful but understanding stuff is a lot
better!!!!!
XVIII. Contents
Part II is meant to supplement the original document. Part I is the “blue collar” stuff that makes the
traditional distribution engineer impossible to replace. Part II addresses some old issues (that needed
some updating) and some new issues (that have become important in this de-regulated environment).
Anyway, I hope they are some use to you. Some of the topics covered are:
•
•
•
•
•
Distributed Resources
Reliability
Modern Physics
Communications
Custom Power
•
•
•
•
•
Maintenance
Decibels
Computer Jargon 101
Equipment Loading
Cost of Interruption
XIX. Distributed Resources
•
Interesting Points
•
Fuel cells need to be replaced
every 5 years
•
Gas fire combined cycle plants
have efficiencies approaching 60%
•
Niche markets for DG may
approach 5% of new capacity
•
Microturbines range from 25 kW
to approximately 50 kW. The early
models operated for about 2000
hours before being pulled from
service.
- Microturbine efficiency is about
20 to 30%. They lose
efficiency due to size and the
need to compress gas. The
larger units approach 40%.
Some spin at 96,000 rpm.
• Fuel cells benefit from modularity,
quiet operation, efficiency, and low
pollution. Most fuel cells require an
external reforming device to
produce hydrogen for the stack.
Efficiency of the direct fuel cell is
about 50 to 55% while with a
reformer is about 35% to 40%.
Availability is considered good at
98% (This translates into about 7
days out of service per year
compared to most US customers
seeing only 2 hours out per year).
Fuel cells need to be derated by
50% after less than a year (4000
hours).
• PV - Not a serious option
• Wind - done fairly well but suffers
from low capacity and mechanical
problems.
• Aeroderivative Gas Turbines offer
efficiencies of more than 40% and
are proven and reliable.
• Reciprocating Engines – Durable,
reliable, low cost and proven. Some
models push efficiencies of 45%.
Emissions are a concern but
solvable. Water injection, used by
Caterpillar to showed reductions in
pollution of as much as 50%.
•
DR Efficiencies
•
Gas fired combined cycle – 60%
•
Microturbines – 20% to 40%
•
Fuel Cells – 35% to 55% (derate by 50% after 4000 hours)
•
Aero-derivative Gas Turbines 40%
•
Reciprocating Engines – 45%
•
Technical Specifications
•
Disconnect from utility:
•
Within 6 cycles if voltage falls
below 50%
•
Within 2 seconds if voltage
exceeds 1.37 per unit
•
Within 6 cycles if frequency if
frequency raises above 60.3 Hz or
falls below 59.3 Hz
•
Inverter should not inject dc current
in excess of 0.5% of full rated
output
•
Must disconnect in 10 cycles for
potential “islanding” situation.
51
Hard to Find….Part II
•
DR Costs
Wind Systems
Fuel Cells
Solar (home, installed)
Solar panels
Batteries
Backup Generator
Inverter
UPS
Motor/Generator
SMES
Capacitor
Flywheel
Microturbines
Reciprocating Engine
$2000 per peak kW
$3500 per kW
$62,000 per kW
$600 per kW
$100 per kW
$300 per kW
$600 per kW
$1500 per kW
$400 per kW
$250 per kW
$50 per kW
$300 per kW
$600 per kW
$500 per kW
Examine your DG options closely.
Mistakes could be costly!!
Reliability
1. Typical Equipment Failure Rates
Cable Primary
Cable Secondary
Switch (Loop)
Elbow
Splice
Fuse (transformer)
Circuit Breaker
Bus
Station Transformer
Overhead Line
Distribution Transformer
Lateral Cable
.03
.11
.05
.0067
.0068
.005
.0066
.22
.02
.2
.005
.1
2. Primary Outage Rates
Frequency
XX.
0.45
0.4
0.35
0.3
0.25
0.2
0.15
0.1
0.05
0
5 kV
15 kV
25 kV
Lightning
Tree
Equip.
Other
Total
Cause
3. Effect of Major Events
Major Event
Included
YEAR SAIDI SAIFI MAIFI
1990 202
2.3
1.6
1991 360
2.4
1.7
1992 225
1.9
1.5
1993 161
1.7
1.4
1994 153
1.7
1.3
1995 187
2.8
2.3
1996 168
1.9
1.6
1997 560
2.8
1.8
1998 230
2.4
2
Major Events
Excluded
SAIDI SAIFI MAIFI
145
1.8
1.4
143
1.8
1.5
150
1.7
1.4
151
1.6
1.2
149
1.6
1.1
145
1.5
1.4
147
1.6
1.2
166
1.8
2.4
140
1.7
1.7
53
4. Indice Definitions
SAIFI [system average interruption
frequency index (sustained interruptions)].
The system average interruptions
frequency index is designed to give
information about the average frequency of
sustained interruptions per customer over a
predefined area. In words, the definition is:
total number of customer
Interruptions
total number of customers
SAIFI =
Values of these indices vary widely
depending on many factors, including
climate (snow, wind, lightning, etc.), system
design (radical, looped, primary selective,
secondary network, etc.), and load density
(urban, suburban and rural). Typical
values seen by utilities in the United States
are:
served
SAIDI
SAIFI
To calculate the index, use the following
equation:
110 min/yr
min/yr
CAIDI
1.4 int/yr
79
SAIDI (system average interruption
SAIFI =
∑N
i
NT
duration index). This index is commonly
referred to as Customer Minutes of
Interruption or Customer Hours, and is
designed to provide information about the
average time the customers are
interrupted. In words, the definition is:
Σ customer interruption durations
SAIDI =
total number of customers served
To calculate the index, use the following
equation:
CAIDI (customer average interruption
SAIDI =
∑r N
i
total number of customers interruptions
To calculate the index, use the following
equation:
∑r N
∑N
i
i
54
Total number of customers
served
NT
Σ customer interruption durations
CAIDI =
Total number of customer
MAIFI E = momentary interruption events
i
duration index). CAIDI represents the
average time required to restore service to
the average customer per sustained
interruption. In words, the definition is:
CAIDI =
Some utilities are already measuring
indices to reflect system disturbances,
other than interruptions, that cause
sensitive loads to misoperate. One of
these, the momentary average interruption
event frequency index,
(MAIFI) is an index to record momentary
outages caused by successful reclosing
operations of the feeder breaker or line
recloser. This index is very similar to
SAIFI, but it tracks the average frequency
of momentary interruption events. In
words, the definition is:
i
=
SAIDI
SAIFI
To calculate the index, use the following
equation:
MAIFI e =
∑ ID N
e
i
NT
(Typical value for MAIFI is 6 interruptions
per year).
5. Voltage Sags
SARFI %V =
∑N
Typical values of SARFI:
i
NT
where %V = rms voltage threshold 140, 120,
110, 90, 80, 70, 50, 10
N i = number of customers experiencing rms
< % V for variation i (rms > % V for % V >
100)
N T = Total number of system customers
SARFI 90 – 50
SARFI 70 – 20
SARFI 50 – 10
SARFI 10 – 5
Typical number of sags for all causes = 350
Typical number of momentaries for all causes =
10
6. Interruption Survey
•
•
•
•
•
•
65% report information to regulators
37% calculate MAIFI
83% feel indices should be calculated separately from generation and transmission
76% feel that scheduled interruptions should be calculated separately
70% have major event classifications
94% use computer programs to generate reliability indicies
7. Loading
Increased loading of equipment will take life out of the equipment and could ultimately contribute to
equipment failure. The following are some important considerations when overloading equipment, especially
transformers:
• Insulation life of a transformer is when it loses 50% of its insulation strength.
• The temperature of top oil should never exceed 110C for transformers having a 65C average
winding rise.
• Peak short duration loading should never exceed 200%.
• Hot spot should never exceed 180C for 65C systems due to the possibility of free bubbles that
could weaken insulation strength. Under normal conditions, hot spot should not exceed 130C.
• Transformers should be operated for normal life expectancy.
• A 2.5% loss of life per day may be acceptable in the event of an emergency.
55
XXI. Modern Physics
Too often, distribution engineers are told they’re behind the times. So I’ve included a few tidbits so you can
impress your friends with your range of knowledge. You never know when you might need the following:
•
Big Bang – The progression of the “Big Bang” is considered to be as follows:
• 0 to 10^-43 seconds - ?????????
• 10^-43 seconds – Quantum Gravity
• 10^-12 seconds – Quantum Soup
• 10^-16 seconds – Protons and Neutrons form
• 1 minute – Helium formed
• 5 minutes – Helium complete
• 500,000 years – Atoms form – Background radiation (COBE)
•
Forces – There are now considered to be 3 forces which are as follows:
• Gravity
• Strong (color)
• Electro-weak
•
Color Charge – The so called “color force” does not fall off with distance and is as follows:
•
Red
• Blue
•
Green
Quarks – Quarks are the fundamental particles (called fermions) of nature. There are 6:
• Up Quark
• Down Quark
• Charmed Quark
• Strange Quark
• Top Quark
• Bottom
• Quark
•
56
Hard to Find….Part II
XXII. Loading
Probably no area of distribution engineering causes more confusion then does loading. Reading
the standards does not seem to help much since everyone appears to have their own
interpretation. Manufacturers of equipment are very conservative since they really never know
how the user will actually put the product to use so they must expect the worst. On the other
hand, many users seem to take the approach that since it didn’t fail last year with traditional
overloading values, it won’t fail this year either. In fact, it won’t fail until after retirement. Heck!
“Save a Buck and Get a Promotion”. The author of this document is not a psychology major and
frankly has no idea of what the thinking was when much of the following was produced. The
material that follows, however, was taken from sources with excellent reputation. Use it with
caution!
1. Transformer Loading Basics
•
All modern transformers have insulation systems designed for operation at 65C
average winding temperature and 80C hottest-spot winding rise over ambient in an
average ambient of 30C. This means:
•
65C average winding rise + 30C ambient = 95C average winding
temperature
•
80C hottest spot rise + 30C ambient = 110C hottest spot
(OLD system: 55C winding rise + 30C ambient = 85C average winding temperature
• 65C hotttest spot + 30C ambient = 95C hottest spot)
•
•
•
•
•
•
•
•
•
Notice that 95C is the average winding temperature for the new insulation system
and the hottest spot for the old. A source of immense confusion for many of us.
The temperature of the top oil should not exceed 100C. Obviously, top oil
temperature is always less than hottest spot.
The maximum hot-spot temperature should not exceed 150C for a 55C rise
transformer or 180C for a 65C rise transformer.
Peak .5 hour loading should not exceed 200%
The conditions of 30C ambient temperature and 100% load factor establish the basis
of transformer ratings.
The ability of the transformer to carry more than nameplate rating under certain
conditions without exceeding 95C is basically due to the fact that top oil temperature
does not instantaneously follow changes in transformer load due to thermal storage.
An average loss of life of 1% per year (or 5% in any emergency) incurred during
emergency operations is considered reasonable.
Most companies do not allow normal daily peaks to exceed the permissible load for
normal life expectancy.
The firm capacity is usually the load that the substation can carry with one supply line
or one transformer out of service.
•
•
“Emergency 24 Hour Firm Capacity” usually means a loss of life of 1% but is
sometimes as much as 5% or 6%.
The following measures can be used for emergency conditions lasting more than 24
hours:
•
Portable fans
•
Water spray
•
Interconnect cooling equipment of FOA units.
•
Use transformer thermal relays to drop certain loads.
2. Examples of Substation Transformer Loading Limits
The following is an example of maximum temperature limits via the IEEE for a 65C rise
transformer:
IEEE Normal Life Expectancy
105C
120C
Top Oil Temperature
Hotspot Temperature
This next example shows the loading practice of various utilities for substation transformers:
Normal
Condtions
Top Oil
Hotspot
Utility
A
95
125
Utility
B
110
130
Emergency
Top Oil
Hot Spot
110
140
110
140
Utility
C
95
120
Utility
D
95
110
110
140
110
130
Utility
E
95
120
Utility
F
110
140
110
140
110
140
Utility
G
110
120
110
140
What happens when the hotspot is raised from 125C to 130C? This is shown as follows:
Maximum Hotspot
125
130
% Loss of Life, Annual
0.3366
0.5372
An example of the effect of load cycle (3 hour peak with 70% pre-load for 13 hours and 45%
load for 8 hours) and ambient on transformer capability via the ANSI guide is shown below:
Peak Load for Normal Life
Expectancy
10C Ambient
30C Ambient
Transformer
Type
20000 - OA
30,000
15000/2000 – 28,700
OA/FA
27,500
12000/16000/
20000
–
OA/FA/FOA
20000 – FOA
27,500
58
Emergency Peak Load with 24Hour Loss of Life
0.25%
1.0%
24,200
23,800
28,400
27,500
32,000
30,700
23,200
26,800
29,700
23,200
26,800
29,700
The following is the effect on transformer ratings for various limits of top oil temperature:
MVA
50
55
59
Normal Rating
New Rating
Emergency Rating
Top Oil Temperature
95C
105C
110C
3. Distribution Transformers
The loading of distribution transformers varies more widely than substation units. Some utilities
try to never exceed the loading of the transformer nameplate. Others, particularly those using
TLM, greatly overload smaller distribution transformers with no apparent increase in failure rates.
An example of one utilities practice is as follows:
KVA
25
50
75
100
Padmounted
Install Range Removal Point
0-40
55
41-69
88
70-105
122
106-139
139
Submersible
Install Range Removal Point
0-34
42
35-64
79
65-112
112
113-141
141
4. Ampacity of Overhead Conductors
In part 1 of the Hard-to-Find, I listed some conservative ratings for conductors per the
manufacturer. The table below shows the rating of conductors via a typical utility:
Conductor
Size
1/0
2/0
3/0
4/0
267
336
397
ACSR
Normal
Emergency
319
365
420
479
612
711
791
331
379
435
496
641
745
830
All Aluminum
Normal
Emergency
318
369
528
497
576
671
747
334
388
450
523
606
705
786
59
5. Emergency Ratings of Equipment
The following are some typical 2 hour overload ratings of various substation equipment. Use at
your own risk:
Station Transformer
Current Transformer
Breakers
Reactors
Disconnects
Regulators
140%
125%
110%
140%
110%
150%
6. Miscellaneous Loading Information
The following is some miscellaneous loading information and thoughts from a number of actual
utilities:
a. Commercial and Industrial Transformer Loading
Transformer Load Limit
Load Factor %
0-64
130%
65-74
125%
75-100
120%
b. Demand Factor
Lights – 50%
Air Conditioning – 70%
Major Appliances – 40%
c. Transformer Loading
• Distribution transformer life is in excess of 5 times present guide levels
• Distribution guide shows that life expectancy is about 500,000 hours for 100C
hottest-spot operation, compared to 200,000 hours for a power transformer.
Same insulation system.
• Using present loading guides, only 2.5% of power transformer thermal life is
used up after 15 years.
• Results of one analysis showed that the transition from acceptable to
unacceptable risk (approximately an order of magnitude) was accompanied (by
this utility) by only a 8.5% investment savings and a 12% increase in transformer
loading.
• Application of transformers in excess of normal loading can cause:
• Evolution of free gas from insulation of winding and lead conductors.
• Evolution of free gas from insulation adjacent to metallic structural
parts linked by magnetic flux produced by winding or lead currents
may also reduce dielectric strength.
• Operation at high temperatures will cause reduced mechanical
strength of both conductor and structural insulation.
• Thermal expansion of conductors, insulation materials, or structural
parts at high temperature may result in permanent deformations
that could contribute to mechanical or dielectric failures.
• Pressure build-up in bushings for currents above rating could
result in leaking gaskets, loss of oil, and ultimate dielectric failure.
60
•
•
•
•
•
•
•
•
•
•
•
•
Increased resistance in the contacts of tap changers can result
from a build-up of oil decomposition products in a very localized high
temperature region.
• Reactors and current transformers are also at risk.
• Oil expansion could become greater that the holding capacity of the
tank.
Aging or deterioration of insulation is a time function of temperature,
moisture content, and oxygen content. With modern oil preservation
systems, the moisture and oxygen contributions to insulation deterioration
can be minimized, leaving insulation temperature as the controlling
parameter.
Distribution and power transformer model tests indicate that the normal life
expectancy at a continuous hottest-spot temperature of 110C is 20.55
years.
Input into a transformer loading program should be:
• Transformer characteristics (loss ratio, top-oil rise, hottest spot rise,
total loss, gallons of oil, weight of tank and fittings.
• Ambient temperatures
• Initial continuous load
• Peak load durations and the specified daily percent loss of life
• Repetitive 24 hour load cycle if desired
Maximum permitted loading is 200% for power transformer and 300% for a
distribution transformer.
Suggested limits of loading for distribution transformers are:
• Top-oil – 120C
• Hottest - spot – 200C
• Short time (.5 hour) – 300%
Suggested limits for power transformers are:
• Top-oil – 100C
• Hottest-spot – 180C
• Maximum loading – 200%
Overload limits for coordination of bushings with transformers is:
• Ambient air – 40C maximum
• Transformer top-oil – 110C maximum
• Maximum current – 2 times bushing rating
• Bushing insulation hottest-spot – 150C maximum
Current rating for the LTC are:
• Temperature rise limit of 20C for any current carrying contact in oil
when carrying 1.2 times the maximum rated current of the LTC
• Capable of 40 breaking operations at twice rate current and KVA
Planned loading beyond nameplate rating defines a condition wherein a
transformer is so loaded that its hottest-spot temperature is in the
temperature range of 120C to 130C.
Long term emergency loading defines a condition wherein a power
transformer is so loaded that its hottest-spot temperature is in the
temperature range of 120C to 140C.
The principle gases found dissolved in the mineral oil of a transformer are:
• Nitrogen: from external atmosphere or from gas blanket over the
free surface of the oil
• Oxygen: from external atmosphere
• Water: from moisture absorbed in cellulose insulation or from
decomposition of the cellulose
• Carbon dioxide: from thermal decomposition of cellulose insulation
61
•
•
62
Carbon monoxide: from thermal decomposition of cellulose
insulation
• Other Gases: may be present in very small amounts (e.g. acetylene)
as a result of oil or insulation decomposition by overheated metal,
partial discharge, arcing, etc. These are very important in any
analysis of transformers, which may be in the process of failing.
Moisture affects insulation strength, power factor, aging, losses and the
mechanical strength of the insulation. Bubbles can form at 140C which
enhance the chances of partial discharge and the eventual breakdown of the
insulation as they rise to the top of the insulation.. If a transformer is to be
overloaded, it is important to know the moisture content of the insulation,
especially if it’s an older transformer. Bubbles evolve fast so temperature is
important to bubbles formation but not time at that temperature. Transformer
insulation with 3.5% moisture content should not be operated above
nameplate for a hottest spot of 120C. Tests have shown that the use of
circulated oil for the drying process takes some time. For a processing time
of 70 hours the moisture content of the test transformers was reduced from
2% to 1.9% at temperature of 50C to 75C. Apparently only surface moisture
was affected. A more effective method is to remove the oil and heat the
insulation under vacuum.
XXIII. Computer Jargon 101
There’s a lot of new terminology out there for the distribution engineer to assimilate these days.
This section outlines some of the terms and concepts we see with the emphasis these days on
data and voice communications.
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.
28.
29.
30.
31.
32.
Telecommunications is defined as the exchange of information, usually over a
significant distance and using electronic equipment for transmission.
The PBX, is a private business exchange. It is the most advanced customerpremises equipment telecommunications solution. A PBX acts like a mini-central
office. Almost all are digital.
Asynchronous Transmission means each device must be set to transmit and
receive data at a given speed, known as a data rate. This type of transmission is
also known as start-stop transmission because it uses start and stop bits.
Synchronous Transmission normally involves large blocks of characters, and
special sync characters which are used to adjust to the transmitters exact speed.
The organizations which have the most impact on data communications are:
ANSI, IEEE, EIA, ECSA, NIST, ISO
RS-232-C is one of the most common interfaces for data communications in use
today. It is an EIA standard defining exactly how ones and zeros will be
transmitted.
DDS is AT&T’s Dataphone Digital Services which provides digital circuits for data
transmission speeds of 2400, 4800, 9600, 56 kbps and 64 kbps.
T-1 carrier service transmits at 1.544 Mbps an carries approximately 24 channels.
ISDN is the Integrated Services Digital Network
For Fiber Optic cable, data rates can exceed a trillion bits per second.
Satellite bandwidth can be up to many Mbps.
Baseband is a single data signal transmitted directly on a wire.
Broadband transmits data using a carrier signal.
Buffering is holding data temporarily, usually until it has been properly sequenced,
as in packet switching networks, or until another device is ready to receive it, as in
front-end processors.
Polling is the method used by a host computer or front end processor to ask a
terminal if it has data to send.,
Selecting is the method used by a host computer to ask a terminal if it is ready to
receive data.
A Front End Processor can perform:
Error detection
Code conversion
Protocol conversion
Data conversion
Parallel/Series conversion
Historical logging
Statistical logging
Security Measures:
Secure transmission facility
Passwords
Historical and Statistical Logging
Closed user group
Firewalls
Encryption and decryption
Secret keys
63
33.
34.
35.
36.
37.
38.
39.
64
Communications architectures and protocols enable devices to communicate
in an orderly manner, defining precise rules and methods for communications and
ensuring harmonious communications among them.
In Packet Switching Networks, the data is separated into packets or blocks, and
sent through the packet switching network to the destination.
A Local Area Network is a privately owned data communications system that
provides reliable, high speed, switched connections between devices in a single
building, campus or complex.
Client/Server - rather than running all applications on a single mainframe, users
can access programs on servers attached to a LAN when a common database or
resource is important. Bridges are used to extend LAN’s beyond its usual distance
limitation.
Bridges are used to connect two or more networks that use similar data
communications.
Routers interconnect LAN’s and do not require all users to have unique addresses
(as do bridges).
Gateways connect networks using different communications methods.
XXIV. Decibels
Here’s some interesting information on decibels:
Decibels
1
2
3
4
5
6
7
8
9
1 db
30 db
70 db
100 db
120 db
Power Change
1.25
1.58
2.0
2.5
3.15
4.0
5.0
6.3
7.9
Decibels
10
11
12
13
14
15
20
30
40
Power Change
10.0
12.6
15.8
20.0
25.1
31.6
100
1000
10000
= lowest sound that can be heard
= whisper
= human voice
= loud radio
= ear discomfort
65
XXV. Faults and Inrush Currents
The following are some observations of the author based on many years of monitoring. The
following statistics are real and based on actual measurements:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
66
Voltage unbalance is generally less than 1%
Harmonics at the substation are generally less than 1 or 2%
40% of faults occur in adverse weather
Average line-to-ground fault current was 1530 amps.
Faults generally lasted 10 cycles with 2 seconds the maximum
Essentially there is no fault impedance (see HtoF #1)
Voltage rise during a fault was about 4% at the substation and 35% on the feeder
Average fuse I^2*t was 227,000 amp^2 sec, with the highest being 800,000 amp^2
sec
What you calculate is what you get.
79% of all faults involve only one phase
Most faults occur with 5% of peak voltage so offset is minimal
Average DC offset was 1.1 with a time constant of 2.81 milliseconds
Inrush
• Inrush average was 2500 amps. And max. was 5700 amps.
• Peak offset was 5.3 per unit and average time constant was 3 cycles
Cold Load Pickup looks like inrush.
XXVI. Custom Power Devices
Custom Power Devices are devices rated above 600 volts that are used to increase power
quality. Though not widely used, these devices are available to the industry to reduce the impact
of distribution disturbances, primarily sags. A few of these devices are described as follows:
•
•
•
•
•
Distribution Static Compensator (DSTATCOM) – The DSTATCOM is a power
electronic device that responds in less than a cycle. It shields customers from
voltage sags and surge problems cause by sudden load changes on the system.
Dynamic Voltage Restorer (DVR) – The DVR system is a series-connected
power electronic device that restores voltage quality delivered to a customer
when the line-side voltage deviates. The device supplies the elements missing
from the waveform in less than one cycle.
Medium-Voltage Sub-Cycle Transfer Switch (SSTS) – This device provides
power quality to customers that are served radially and have access to an
alternative power source. Switching between the preferred and alternative
source is done wthin 0ne-sixteenth of a second.
Solid-State Breaker (SSB) – This is a fast acting sub-cycle breaker which
instantaneously operates to clear an electrical fault from the power system. In
combination with other electronic devices, the SSB can prevent excessive fault
currents from developing and improve PQ.
Static Var Compensator (SVC) – This device uses capacitors, an inductor, and
a set of solid-state switches to provide power factor correction or voltage
regulation. Constant power factor and constant line voltage are possible using
the device.
67
XXVII. Cost of Power Interruptions
The cost of an interruption is probably one of the most difficult to assess. On the one hand, when
the perception is that the utility will pay the costs from commercial and industrial customers are
always high via survey data. On the other hand, when the cost of correction of the problem is
determined to be the customer’s responsibility, the costs are much lower. The following are
some of these survey costs. Use with caution:
Type of Industrial
/Commercial
Electrical Products
Crude Petroleum
Machinery
Paper Products
Logging
Printing and Publishing
Primary Textiles
Transportation
Textile
Automotive
General Merchandise
Household Furniture
Personal Services
Entertainment
68
Cost per peak
KW
$7.60
$240.30
$6.70
$6.60
$1.80
$5.20
$15.10
$37.40
$15.10
$36.90
$26.20
$34.70
$0.30
$20.70
XXVIII. Cost of Sectionalizing Equipment
The following are some approximate costs of equipment used for sectionalizing:
•
•
•
•
•
•
Fuse Cutout
Gang Operated Switch
Disconnect Switch
OCR
DA Load Break
DA Recloser
$1300
$5500
$2500
$9000
$33,000
$40,000
69
XXIX. Maintenance of Equipment
Some of the diagnostic and assessment techniques used for utility equipment is as follows:
TRANSFORMERS
Overall dielectric –
DGA,
onlineVHF/UHF PD
SWITCHGEAR
Drive – contact
position, constant
velocity,
vibrational
analysis, trip-coil
current
Tap Changer –
dynamic resistance,
drive power
Secondary
System – trip-coil
current
Bushing – loss
angle, capacitance
Overall Dielectric
– online PD,
vacuum leak
testing
CABLE
PD Techniques –
0.1 Hz off-line
detection and
localization,
online VHF
detection,
single/double
sided localization
in point to point
cables and
branched
networks
Diel
Spectrosocopy –
loss angle,
capacitance
GENERATORS
Stator/Rotor
Windings – insulator
resistance,
conductor
resistance
,polarization index,
loss angle,
capacitance P”D
measurement, high
voltage tests, video
endoscopy
Core – no load
losses
Paper - furfural
analysis
Transformer Lifetime from furfural analysis:
•
•
•
•
•
•
70
Lifetime primarily determined by mechanical condition of paper insulation
Degree of polymerization (DP) measure for mechanical strength
DP decreases from about 1200 (new) to 250 (end of life)
DP determined from correlation with product of furfural and CO-concentrations
Decay curve from accelerated aging study
Lifetime time prediction from (series) of DP values
XXX.
Major Events
In the area of reliability indicies some utilities are allowed to exclude major events (storms, etc.).
The concern in the industry is what constitutes a major event. There are many definitions. The
two most popular are:
• 10% of the system is out of service for usually 24 hours
• Exclusion of events outside 3 sigma. This definition is based on Chebyshevs
Inequality (you needed to know that right!). Anyway, outages a utility may have
during the year have a probability distribution. This concept basically says that
events not within 3 standard deviations of the mean can be excluded. For reference,
approximately 56% of events are within 1 standard deviation, 75% are within 2
standard deviations and 89% are within 3 standard deviations. So this would mean
approximately 10% could be excluded.
71
XXXI. Line Charging Current
I’m asked about once a year how much capacitance a line has. Always have trouble finding an
answer so I’m putting it here. Charging KVA (3 phase) can be approxiated by the formula:
Charging KVA = 2.05 (kV)^2/Z, where Z is the characteristic impedance of the line. Some
approximations, which may be helpful, are as follows:
kV
15
25
35
115
230
500
72
Overhead
(kVAR)
1
3
6
66
265
1,250
Underground
(kVAR)
10
30
60
660
2,650
12,500
XXXII. Overcurrent Rules
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
Hydraulically controlled reclosers are limited to about 10,000 amperes for the 560
amp coil and 6000 amperes for the 100 amp coil.
Many companies set ground minimum trip at maximum load level and phase trip at 2
times load level.
A K factor of 1 (now used in the standards) means the interrupting current is constant
for any operating voltage. A recloser is rated on the maximum current it can interrupt.
This current generally remains constant throughout the operating voltage range.
A recloser is capable of its full interrupting rating for a complete four-operation
sequence. The sequence is determined by the standard. A breaker is subject to
derating.
A recloser can handle any degree of asymmetrical current. A breaker is subject to an
S factor de-rating.
A sectionalizer is a self-contained circuit-opening device that automatically isolates a
faulted portion of a distribution line from the source only after the line has been deenergized by an upline primary protective device.
A Power Fuse is applied close to the substation ( 2.8 to 169kV and X/R between 15
and 25)
A Distribution Fuse is applied farther out on the system (5.2 to 38kV and X/R between
8 and 15).
The fuse tube (in cutout) determines the interrupting capability of the fuse. There is an
auxiliary tube that usually comes with the fuse that aids in low current interruption.
Some expulsion fuses can handle 100% continuous and some 150%.
Type “K” is a fast fuse link with a speed ratio of melting time-current characteristics
from 6 to 8.1 (speed is the ratio of the 0.1 minimum melt current to the 300 second
minimum melt current. Some of the larger fuses use the 600 second point.
Type “T” is a slow fuse link with a speed ratio of melt time-current characteristics from
10 to 13.
After about 10 fuse link operations, the fuse holder should be replaced.
Slant ratings can be used on grounded wye, wye, or delta systems as long as the lineto-neutral voltage of the system is lower than the smaller number and the line-to-line
voltage is lower than the higher number. A slant rated cutout can withstand the full
line-to-line voltage whereas a cutout with a single voltage rating could not withstand the
higher line-to-line voltage.
Transformer fusing – 25@0.01, 12@0.1, 3@10sec.
Unsymmetrical Transformer Connections ( delta/wye):
Fault Type
Multiplying Factor
Three-phase
N
Phase-to-phase
.87 (N)
Phase-to-Ground
1.73 (N)
Where N is the ratio of Vprimary/Vsecondary
( Multiply the high side device current points by the appropriate factor)
K Factor for Load Side Fuses
a. 2 fast operations and dead time 1 to 2 seconds = 1.35
K Factor for Source Side Fuses
a. 2 fast-2 delayed and dead time of 2 seconds = 1.7
b. 2 fast-2 delayed and dead time of 10 seconds = 1.35
c. Sometimes these factor go as high as 3.5 so check
Sequence Coodination – Achievement of true “trip coordination” between an upline
electronic recloser and a downline recloser, is made possible through a feature known
as “sequence” coordination. Operation of sequence coordination requires that the
73
26.
27.
28.
29.
30.
upline electronic recloser be programmed with “fast curves” whose control response
time is slower that the clearing time of the downline recloser fast operation, through the
range of fault currents within the reach of the upline recloser: Assume a fault beyond
the downline recloser that exceeds the minimum trip setting of both reclosers. The
downline recloser trips and clears before the upline recloser has a chance to trip.
However, the upline control does see the fault and the subsequent cutoff of fault
current. The sequence coordination feature then advances its control through its fast
operation, such that both controls are at their second operation, even though only one
of them has actually tripped. Should the fault persist, and a second fast trip occur,
sequence coordination repeats the procedure. Sequence coordination is active only
on the programmed fast operations of the upline recloser. In effect, sequence
coordination maintains the downline recloser as the faster device.
Recloser Time Current Characteristics
a. Some curves are average. Maximum is 10% higher.
b. Response curves are the response of the sensing device and does not include
arc extinction.
c. Clearing time is measured from fault initiation to power arc extinction.
d. The response time of the recloser is sometimes the only curve given. To obtain
the interrupting time, you must add approximately 0.045 sec to the curve
(check…they’re different)
e. Some curves show max. clearing time. On the new electronic reclosers, you
usually get a control response curve and a clearing curve.
f. Zl-g = (2Z1 + Z0)/3
The “ 75% Rule” considers TCC tolerances, ambient temperature, pre-loading and
pre-damage. Pre-damage only uses 90%.
A back-up current limiting fuse with a designation like “12K” means that the fuse will
coordinate with a K link rated 12 amperes or less.
Capacitor Fusing:
a. The 1.35 factor may result in nuisance fuse operations. Some utilities use 1.65
b. Case rupture is not as big a problem as years ago due to all film designs.
c. Tank rupture curves may be probable or definite in nature. Probable means
there is a probability chance of not achieving coordination. Definite indicates
there is effectively no chance of capacitor tank rupture with the proper 0%
probability curve.
d. T links are generally used up to about 25 amperes and K link above that to
reduce nuisance fuse operations from lightning and in
Line Impedance – Typical values for line impedance (350kcm) on a per mile basis are
as follows:
Cable UG
Spacer
Tree Wire
Armless
Open
31.
32.
33.
34.
35.
Zpositive
.31 + j0.265
.3 + j0.41
.3 + j0.41
.3 + j0.61
.29 +j0.66
Z0
1.18 + j0.35
1.25 + j2.87
1.25 + j2.87
.98 + j2.5
.98 + j2.37
1A-3B is a necessary when sectionalizers are used downstream from the recloser.
Vacuum reclosers have interrupting ratings as high as 10 to 20kA.
Highest recloser continuous ratings are 800 and 1200 amperes.
Sectionalizer actuating current should be <80% of backup device trip current.
Interrupting ratings of cutouts are approximately 7 kA to 10 kA symmetrical.
74
36.
37.
38.
39.
40.
41.
42.
43.
44.
45.
46.
47.
48.
49.
50.
51.
52.
53.
54.
55.
56.
57.
58.
59.
60.
61.
62.
63.
64.
65.
K Factor can mean a “voltage range” factor or a “shift factor” caused by the recloser
heating up the fuse.
Sectionalizer counts should normally be one count less than the operations to lockout
of the breaker or recloser
Sectionalizer memory time must be > than cumulative trip and reclose time.
Fuses melt at about 200% of rating.
Sectionalizers have momentarr ratings for 1 second and 10 seconds.
25% Rule for fuses includes pre-load, ambient temperature, and pre-damage.
Characteristics of Chance Sectionalizers include:
100 amp continuous
160 amp actuating
2 counts
12,000 amp momentary
4,000 amp @ 1 second
2500 amp @ 10 second
0.3 amp detector threshold
Minimum time delay = 80 ms
Reset time approximately 25 seconds
Minimum duration of current impulse approximately 1 to 3 cycles.
Short time curves are 20% of the normal curve ( in time).
Long time curves are 10 times the normal
The PCD2000 incorporates a 32 bit microprocessor and a 16 bit microprocessor.
The PCD has the following relays:
27 – Undervoltage
32 – Directional Power
46 – Negative Sequence
50 – Instantaneous
51 – Inverse Time
59 – Overvoltage
67 – Directional Overcurrent
79 – Reclosing
81 - Frequency
75
Jim Burke – 12/10/04
XXXIII. Hard to Find Information on Grounding
I’m not sure anyone really understands grounding. There are a number of things in life
that are simply not going to be crystal clear in my lifetime and this is one of them. Here are some
interesting bits of wisdom that might help you out in trying to make sense of so many conflicting
you hear. As a great philosopher once said, “Don’t let knowledge interfere with your
education”. One final thing…as usual, none of this is guaranteed!
ƒ NESC (IEEE C2-1997) requires:
9 Neutral must be continuous
9 Does not allow earth as a sole conductor
9 Does not require specific grounding resistance for multigrounded systems
9 Multi-grounded systems achieve their performance by having many grounds
9 Requires that surge arrester conductors be at least #6 copper or #4 aluminum
9 Requires grounds at transformers and customer meters
ƒ A good approximation for a 10 foot ground rod is that the resistance in ohms equals the
ground resistivity in ohm-meters divided by 3. For an 8 foot ground rod, divide by 2.5.
ƒ Soil resistivity is the resistance of a certain volume of soil. Normally, resistivity is
specified in ohm-meters. The resistance between opposite faces of a cube of soil (e.g. 1
meter on a side) is its resistivity.
ƒ Being wet decreases contact resistance by a factor of about 10.
ƒ The current that kills is about .1 amps. Very high currents actually have less chance of
killing you, so be careful.
ƒ We lean against trees that touch high voltage wires all the time and nobody dies. There
is an explanation for this.
ƒ Over half the world uses a non-effectively grounded system and it works. This in itself
should make you question whether good grounding is an absolute requirement for
performance. It depends!!
ƒ If you put electrodes across your head with 110 volts across them you will draw about
1100 milliamperes (apparently not much in there to cause resistance). If you put the
same voltage between your hand and your foot, you will probably draw less than 1 mA. If
you’re wet this could go up to about 100 mA. I guess the conclusion you can draw from
this is “If you have a low resistance brain and like to play with 110 volts in the shower,
you deserve to die”. This is probably the reason why they tell you, in those operating
instructions, not to take your toaster in the shower.
ƒ Butt Plate resistance is generally greater than 5 times more than that of a ground rod.
ƒ Electrode diameter does not significantly affect ground rod resistance…but depth does!
ƒ Space ground rods at least 10 feet apart to get maximum effectiveness.
ƒ Substation Ground resistance should be less than about 5 ohms. Having a lower
resistance does not mean the substation is safer. Substation grounding is more
dependent on the design of the ground mat (see IEEE Guide for Safety-AC Substation
Grounding’’, ANSI/IEEE 80-1986). There is no simple relationship between the resistance
76
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
of the substation grounding as a whole and the maximum shock current a person might
be exposed to.
One of the problems of ungrounded systems was that as the systems grew, faults were
no longer self clearing due to the large capacitive currents.
When doing soil resistivity measurements (4-Point Measurement), the distance
between electrodes should be 20 times the electrode depth. The depth of the resistivity
measurement is equivalent the distance between electrodes.
For a multigrounded system a fault about 2 miles from the substation produces the
highest overvoltage on the unfaulted phases of about 135%.
Moisture Content in the soil dramatically affects soil resistivity. Soil with no water has 2
million times as much resistivity as soil with 30% moisture content.
Temperature changes between 68 degrees and 14 degrees F, change the resistivity of
soil by a factor of about 40.
Length is more important than width for a ground rod
The resistance of an 8 foot ground rod for one utility varied between 40 ohms and 1150
ohms.
To measure ground resistance for an 8 foot ground rod, the distance to the furthest test
electrode should be about 72 feet (3 point test….middle conductor is at 45 feet).
20 ground rods produce a ground rod resistance about 1/10th of a single ground rod
Magnitude of swells depends on system grounding
Delta systems have good characteristics and they are not grounded
Current split between the earth and the neutral conductor during faults is about 50/50
A broken conductor can create an overvoltage of about 1.8 per unit during a line-toground fault
High impedance faults almost always have a fault impedance above 100 ohms.
Ground rod resistance does not significantly affect fault current levels
Fault levels should be calculated with 0 ohms fault impedance
Shield wires need low ground resistances and arresters do not.
Severe Stray Voltages exist at about 7 volts. 1 to 2 milliamperes (about 0.5 to 2 volts)
can cause significant behavioral change in cows
Good Grounding is Important for:
- Lightning surge dissipation
- Level of swells
Good Grounding does not significantly affect:
- Line protection using arresters
- Fault levels
XXXIV. Reliability Trends
Talk is cheap! I’ve heard a lot about how utilities are trying to improve reliability but nothing
as to how this can be accomplished in lieu of the following:
1. Elimination of experienced engineers
2. Reduction of participation in standards activities
3. Loss of control over generation and transmission
4. Decaying infrastructure
77
5.
6.
7.
8.
9.
10.
Purchase of products on price
Elimination of R&D
Overloading of equipment
Severe reduction of budgets and manpower
Loss of control over day-to-day activities
“Not in My Backyard” politics
XXXV. Load Survey Results
I get into more discussions on what is a typical loading on utility feeders do we did a little survey.
Question: What is your typical (average) feeder loading in amperes? What is your typical peak
load (not emergency) that will occur on a fairly regular basis?
Utility
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
Average
191
200
300
200
350
200
200
100
100
500
250-300
400
150
200
67
100
250
200
400
150
300
192
530
300
200
300
100
300
200
100
300
200
400
240
200
200
100
300
200
Peak
175-225
318
300
300
550
320
600
800
300
150
400
700
512
300
450
102
200
350
300
600-700
200
450
338
373
840
500
400
400
200
400
400
250
350
450
400
500
420
350
350
400
320
78
* About 30% of these values come from co-ops which tend to have lower load levels
XXXVI. Lightning Damage Survey
.
After a lightning storm, you can find various forms of damage. Some of the damage may
be caused by the lightning stroke (the spectacular stuff) and some may be caused by fault
current during the flashover. I suspect sometimes it’s difficult, if not impossible, to tell the
difference. In any case, I’ll let you decide. I have listed the comments I received (paraphrased in
some instances) as shown below:
1. “Most of the time the damage we have seen from lightning hitting a pole it that the pole
splinters into many pieces…..Most of our pole fires are associated with tracking due to an
insulator breaking down”
2. “ Pole explodes like a hotdog in a microwave..shatters pole 30-40 feet or more…new
poles are more often damaged than old ones because they are still wet from
treatment…rarely see pole fires due to lightning”
3. “ Poles split with large chunk blown out..damage similar to a tree except not all the way
down….not sure whether damage is from lightning or follow current…steam splits the
pole”
4. “Concrete poles with neutral in static position….hole was blown out the side of the pole
near the top….hole was not large enough to cause structural damage”
5. “ The higher voltage systems tend to sustain the most damage, we rarely have a problem
at 2400 volts….Lightning blows off arrester grounds of most porcelain type…blows lots of
tap fuses….lose transformers…we have very, very few pole fires. All new poles are
treated with penta, but we have CCa and creosote..”
6. “ We see damage such as pole mounted transformers blowing their lid off…internal
damage to mid line reclosers…”
7. “ Manufacturer comments: We see one or two switches come back every year with what
appears to be direct lightning damage…occasionally we see damage to the controlalthough not as often as you might thing because of the grounding design of the overall
system”
8. “ I saw one instance where the top of the pole was shattered, one third of the exposed
distance, with wood fragments and various pieces scattered up to fifty feet away”
9. “Burnt or charred pole tops (evidence of fires that may have burnt itself out)..pole top
blown to pieces – mostly at the power or communication levels (suspected due to quick
release of energy from the moisture in the pole): and charred paths down the pole
surface to ground with poles relatively intact”
10. “Splitting from the top to the neutral position. The only difference is that when lightning
hits and there is a flashover, in due time the leakage over to the pole causes the pole to
smolder and burn. Also, when farmers are burning off their wheat fields and the pole
catches fire, we have been to the location and found nothing but ashes with the
conductor still hanging with the hardware still attached”
11. “ Poles split out at the top, most of the time resulting in the PTPIN barely hanging from
the pole or completely blown off the pole. In some cases, insulator damage is
apparent….this type of damage may not show up for a couple of days when changes in
humidity creates blinking lights”
12. “ We have experienced pole fires, overhead conductor pitting and underground cable
failures (usually a few days after the lightning storm”
79
XXXVII. Substation Voltage Regulation
Introduction
The following are some of the comments I got back (25 utilities responded) on regulation
practices in substations. I’ve had to abbreviate most of them. A lot of good points. I appreciate
the response:
1. Who builds 3 phase regulators?
• Very few of respondents could answer this one
• Virginia Transformer, Pennsylvania Transformer, Delta Star, GE, and Siemens(most
mentioned) appear to still be making these units. A number of responses thought they
were no longer made.
• Some utilities only purchase single phase units
• Many utilities don’t purchase any regulators
• Regulators have high failure rate
2. Why choose LTC over bus voltage Regulators and vice versa?
• Single phase control gives better balance and reliability
• Do not like to install LTC in single ended substations due to the difficulty in getting the
transformer out of service to do maintenance on the LTC
• Do not use LTC above 24.9kV
• Regulators (1 phase) allow us to balance better
• Easier to have spare using 1 phase regulator
• Connectivity and communication is easier with 1 phase units
• Don’t like having regulation in the transformer (LTC) due to reliability concerns
• LTC better because it is one device and has less chance of failure than 3 devices
• Land area is less for LTC
• Use both…criteria of choice is based on load..prefer single phase regulators
• More expensive to maintain LTC
• New transformer 20 MVA or higher use LTC
• Fail 1 transformer per year due to LTC problem (this is a large utility)
• Do not believe being able to bypass single phase regulator is an advantage
• Education is easier for single phase regulators
• Use regulators on 10 MVA and below and LTC on larger units
• Don’t like the idea of LTC since it can make the transformer unuseable
• Our choice based on cost
• Regulators help us because our feeder loads have different characteristics
3. Philosophy of regulation for each feeder?
• Regulators allow us to balance feeder voltages
• Individual regulators see less total contact activity
• Choice based on load level
• Regulators give us more capacity capabiity
80
•
•
•
•
•
•
•
•
•
•
LTC can make voltage problems worse for some phases and feeders
We use both
Easier to maintain feeder regulators with minimal impact to our customers
Whichever cost less to give us good regulation
Regulators allow better control to control peak loads
On rural feeders some lines are much longer than others so individual control works
better
In general, we regulate by circuit. We have one station that is bus regulated. About 5 of
our 170 circuits are from LTC banks
Our mobiles do not have regulation so LTC is a problem when we have it
We regulate individual feeders as necessary with a combination of line regulators, and
switched and fixed capacitors out on the line
We have short and long lines. Individual circuit regulators give more flexibility.
XXXVIII. Ways We Scare Ourselves
Michael Crichton, of Jurassic Park fame,(who has a medical degree) has some interesting
comments recently, some of which are very applicable to the utility industry and its defensive
posture. Here are some of the scares the American public have let get out of control:
1. We are going to freeze, the earth is becoming too cold, we are going into an ice
age. Any responsible scientist knows this. – 1972
2. We are going to sizzle, global warming will be so bad we’ll have palm trees in
Montana – 1982
3. “In the 1970’s the world will undergo famines – hundreds of millions of people are
going to stave to death” - Paul Ehrlich. He argued for population control. The
Club of Rome (a global think tank) predicted a work population of 14 billion in the
year 2030 with no end in sight. Now we expect that world population to peak at 9
billion and then decline.
4. In 1972, the Club of Rome predicted that we would exhaust our supplies of gold,
mercury, tin, zinc, oil, copper, lead and natural gas by the year 1993.
5. In 1960 we predicted that the use of computers would replace work and we’d
have trouble finding things to do with all our leisure time. By the end of the
century, Americans were regarded as overworked, overstressed and sleepless.
6. The health threats posed by power lines lasted more than a decade and
according to one expert cost the nation $25 billion before many studies
determined it to be false. Ironically, 10 years later, the same magnetic fields
formerly feared as carcinogenic now are welcomed (magnetic therapy).
7. Here’s some others:
• Saccharin
• Cyclamates
• Swine flu
• Endocrine disrupters
• Deodorants
• Electric razors
• Florescent lights
• Computer terminals
• Road rage
• Killer bees
• Cell phones
81
• Y2K
“ I’ve seen a heap of trouble in my life, and most of it never came to pass” – Mark Twain
If you really want to scare yourself unnecessarily, “Think About This”:
a. The number of physicians in the United States is 700,000
b. Accidental deaths caused by physicians per year is 120,000
c. Accidental deaths per physician is 0.171 (per Dept. of Human Services)
Then think about this:
a. The number of gun owners in the US is 80,000,000
b. The number of accidental gun deaths per year (all age groups) is 1,500
c. The number of accidental deaths per gun owner is .0000188
Statistically, doctors are approximately 9,000 times more dangerous than gun owners
FACT: Not everyone has a gun, but almost everyone has at least one doctor
XXXIX. Cost of Poor Power Quality
A study by a major US utility produced the following table regarding the cost of poor
power to an Industrial Customer:
Disturbance
Voltage Sags
Momentary Outage
1 Hour Outage – notice
1 Hour Outage – no notice
4 Hour Outage
Cost per Event
$7,694
$11,027
$22,973
$39,459
$74,835
Annual Frequency
22.9
2/4
1.1
1.1
1.1
Here’s a thought: “ the power of the cars and trucks sold in the US in 2003 is 2.5 times more than
the total U.S. generating capacity” Not sure where that puts the electric car?
XXXX. Windpower Update
At a meeting I attended earlier this year, I jotted down the following comments made with regard
to windpower:
• Big PQ issue for windpower is voltage flicker
• Need about 30 mph wind to get full kW
• About a 30% capacity factor is considered OK
• GE is a big player and owns about half the market
• 6 Gigwatts are now installed
• Some units have a load factor under 5%
• A lot of these installations are really hobbies
• Iowa has the most number of windturbines for schools
• Cost is between $1000 and $5000 per kW
82
•
•
Rural Electrics are greatly encouraged by the government to install windpower
Some put DG in to avoid going to court (interesting)
XXXXI. Fault Impedance
Back to one of my favorite issues!!!!!! (see part I). The origin of the use of the fault impedance
value of 40 ohms (or 30, or 20) is apparently the result of an AIEE paper entitled “Overcurrent
Investigation on a Rural Distribution System” written in 1949 by G. Lincks, D. Edge, W. McKinley,
and J. Leh. This is an excellent paper describing measurements taken during the years 1944 to
1947. It is especially impressive considering the monitoring capability at the time the data was
taken.
It is interesting that the paper describes many aspects of overcurrent protection and actually adds
the figure, shown below, as almost an afterthought. There is very little description of the data
shown in this figure except for the following: “The assumed 40-ohms fault resistance used in
this investigation, proved to be more than ample for determining minimum fault currents
and might have been reduced to 30 ohms”.
REINFORCED
CONCRETE
Current Level in Amperes
20
0
WET GRASS
DRY GRASS
WET SOD
DRY SOD
40
WET SAND
60
DRY ASPHALT , CONCRETE OR DRY SAND
80
Typ e o f S urface
Figure 1 – High Impedance Faults
83
Figure 2 - Aspects of Overcurrent Protection – Data from 1949 AIEE Paper
The authors also state that they wouldn’t expect fault impedance to vary with system
voltage level.
The subject paper and discussion provide insight into how the values that the industry now uses
for fault impedance had their origin. There are, however, some points that should be made with
respect to the above:
1. Maximum fault levels for bolted faults in this study were on the order of 500 amperes
or less with the vast majority being less than 200 amperes (almost 40 ohms of
impedance for a bolted fault).
2. Load levels may not have been subtracted from the calculation. This would result in
a huge error since the high impedance fault levels are around 50 amperes or less
and load currents could be considerably higher. There is no indication that load
currents were subtracted out of the calculation. If the recorders only triggered on a
fault event, it might not have been able to record pre-fault load data with recorders of
this vintage.
3. The authors of the paper indicated that use of 40 ohms “proved more than
ample….and might have been reduced to 30 ohms”. All data in the past 30 years
indicates that use of 40 ohms would be extremely inadequate and values around
200 ohms or more would be needed to have any significant effect.
There have been many, many tests on downed conductors performed by utilities,
manufacturers, universities, EPRI and consultants. The results have been consistent at all
voltage levels, indicating the use of 40 ohms impedance provides virtually no level of
protection for high impedance faults. No tests have shown anything to the contrary. A
summary of some of these findings is shown below:
Texas A&M (EPRI)
Surface
Dry asphalt
Concrete (non-reinforced)
Dry sand
Wet sand
Dry sod
Fault Current
0
0
0
15
20
84
Dry grass
Wet sod
Wet grass
Concrete (reinforced)
25
40
50
75
PTI
Surface Type
Old Gravel
Grass
Dirt/Sand
Concrete
Old Gravel
Reinforced Concrete
Old Gravel
Fault Current in RMS amps.
5-25
55-65
8-12
28-36
2-15
30-80
5-12
High Impedance fault current levels are very low and almost always should be represented by an
impedance of 80 ohms or more (e.g. 80 amperes of fault current is approximately equal to 100
ohms of fault impedance on a 13.8 kV system or 90 ohms on a !2.47 kV system). Fault
impedances of 200 ohms or more would have to be used to simulate average fault levels caused
by most high impedance faults. All the data that could be found, which represents the past 25
years of research, suggests that the use of 10, 20, 30 or 40 ohms has virtually no value in helping
detect high impedance faults. No research the author is aware of, in the past 40 years, supports
use of these values and there is no evidence that fault impedance varies depending on primary
distribution voltage level or distance from the substation.
85
XXXXII. Explanation of Voltage Ratings
I always have trouble remembering this material. A little hard to read…sorry!
Voltage Unbalance seems to confuse many. Here are some things to keep in mind:
Voltage Derating for polyphase equipment
% Voltage Unbalance
Derating Factor
5
4
3
2
1
0
.75
.82
.90
.95
.99
1.0
The formula to calculate voltage unbalance is %Unb = 100 X (Max. deviation from Average V
(Average Voltage)
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Standard Nominal Voltages are as follows:
Three Wire
Four Wire
2400
4160
4800
6900
13800
23000
34500
4160Y/2400
8320Y/4800
12000Y/6930
12470Y/7200
13200Y/7970
13800Y/7970
20780Y/12000
22860Y/13200
24940Y/14400
34500Y/19920
(bold indicates preferred voltage levels)
87
Jim Burke
Introduction – I have so many requests lately on the subjects of stray voltage, capacitor
application and power quality standards that I thought I’d add a few pages on these subjects.
XXXXIII. Stray Voltage
Introduction
Stray Voltage has always been a term related to steady state voltages between the
neutral and ground that caused problems for dairy farms and swimming pools. As such, stray
voltages were not lethal. The term “stray voltage” is taking on a life of its own and becoming all
things to all people. The following are terms interchanged with the term “stray voltage” which are
incorrect and causing a lot of the present confusion:
a. Stray Voltage – the term as generally defined by utility engineers refers to the voltage
imposed on the distribution primary neutral due in large part to return currents (unbalanced
loads). In the context of the last 40 years, the voltage is associated with problems in dairy farms
and generally the voltages do not exceed about 8 volts. They are not easily mitigated and are not
considered dangerous or lethal (unless, of course, you consider the 9 volt battery in your radio a
threat to your life).
b. TOV – Temporary Overvoltages are commonly referred to as stray voltages which they
are not. TOV’s are 60 Hz overvoltages that occur on the unfaulted phases of a 4-wire multigrounded system during a fault (see Fig. #1). Temporary overvoltages can be a consideration for
voltage sensitive equipment such as surge arresters.
c. Contact Voltage – We normally use the term contact voltage to address the condition
where the “hot” lead (120 volts or more) contacts the outside shell of something like a streetlight.
This voltage is dangerous and can result in death. Contact voltage is not “stray voltage” although
it is sometimes misapplied in this context.
88
Maximum L-N Voltage (p.u.)
1.45
1.4
1.35
1.3
4 gpm
8gpm
1.25
1.2
1.15
1.1
1
10
100
1000
Ground Footing Resistance (ohms)
Figure #1 – Impact of Grounding on TOV
Problems in Identifying Stray Voltage Causes
Stray voltage (neutral-to-earth) is caused by voltage drop and ground currents that could
have their origin either on the utility system or the customer premises itself. The problem can be
very difficult to analyze since the return path of the unbalanced currents is complex and system
changes to mitigate the problem can often cause the opposite effect. Over the years the greatest
interest in stray voltage has been in the area of dairy farming, since cows are sensitive to stray
voltage, which may affect production. Swimming pools with plastic liners have also become an
issue.
The path of unbalanced current flow on a distribution system is not obvious. One thing
that greatly complicates an accurate model is that the loads are distributed making the flow of
current between the neutral and earth very complex.
Figure #2 shows the percentage of current in the neutral for various sizes of wire. The
fault, in this case, is located 10 miles from the substation and as we can see, most of the current
at the fault location (could be load as well) is in the neutral. Near the middle of the feeder there is
very little exchange of current, which means that in this area the stray voltage problem should be
less. However, we start to see a shift in current near the substation which indicates higher stray
voltages in the vicinity of the substation.
Figure #2 – Division of Current for Various Neutral Conductor Sizes
89
Figures #3 and #4 (not related to the example above) illustrate the typical effect of unbalance
current flow on stray voltage. Figure #3 shows that the stray voltage level at substation is high,
as it also is at the end of the feeder. There are 2 interesting things to point out. First, the stray
voltages near the substation are opposite to those at the end of line (current reversal) and
voltages in the middle of the feeder are relatively low. Also, it is interesting to note that if the
substation ground is good (1 ohm) things get worse in some areas and better in others.
Figure #3 – Effect of Substation Grounding on Stray Voltage
Figure #4 shows the effect of changing the system pole ground rod resistances from 5 ohms to
50 ohms. As can be seen, stray voltages are reduced, but not as much as one might think. In the
areas with the highest stray voltage, the benefit of improving grounding is questionable.
Figure #4 – Effect of Pole Grounds on Stray Voltage
XXXXIV. Airline Cabin Announcements:
All too rarely, airline attendants make an effort to make the in flight "safety lecture" and
announcements a bit more entertaining. Here are some real examples that have been
heard or reported:
1. On a Southwest flight (SW has no assigned seating, you just sit where you want)
passengers were apparently having a hard time choosing, when a flight attendant
announced, "People, people we're not picking out furniture here, find a seat and get in it!"
2. On a Continental Flight with a very "senior" flight attendant crew, the pilot said, "Ladies
and gentlemen, we've reached cruising altitude and will be turning down the cabin lights.
This is for your comfort and to enhance the appearance of your flight attendants."
3. On landing, the stewardess said, "Please be sure to take all of your belongings. If you're
90
going to leave anything, please make sure it's something we'd like to have.
4. "There may be 50 ways to leave your lover, but there are only 4 ways out of this
airplane"
5. "Thank you for flying Delta Business Express. We hope you enjoyed giving us the
business as much as we enjoyed taking you for a ride."
6. As the plane landed and was coming to a stop at Ronald Reagan, a lone voice came
over the loudspeaker: "Whoa, big fella. WHOA!"
7. After a particularly rough landing during thunderstorms in Memphis, a flight attendant
on a Northwest flight announced, "Please take care when opening the overhead
compartments because, after a landing like that, sure as hell everything has shifted."
8. From a Southwest Airlines employee: "Welcome aboard Southwest Flight 245 to
Tampa.. To operate your seat belt, insert the metal tab into the buckle, and pull tight. It
works just like every other seat belt; and, if you don't know how to operate one, you
probably shouldn't be out in public unsupervised."
9. "In the event of a sudden loss of cabin pressure, masks will descend from the ceiling.
Stop screaming, grab the mask, and pull it over your face. If you have a small child
traveling with you, secure your mask before assisting with theirs. If you are traveling with
more than one small child, pick your favorite."
10. "Weather at our destination is 50 degrees with some broken clouds, but we'll try to
have them fixed before we arrive. Thank you, and remember, nobody loves you, or your
money, more than Southwest Airlines."
11. "Your seat cushions can be used for flotation; and, in the event of an emergency water
landing, please paddle to shore and take them with our compliments."
12. "As you exit the plane, make sure to gather all of your belongings. Anything left behind
will be distributed evenly among the flight attendants. Please do not leave children or
spouses."
13. And from the pilot during his welcome message: "Delta Airlines is pleased to have
some of the best flight attendants in the industry. Unfortunately, none of them are on this
flight!"
14. Heard on Southwest Airlines just after a very hard landing in Salt Lake City the flight
attendant came on the intercom and said, "That was quite a bump, and I know what y'all
are thinking. I'm here to tell you it wasn't the airline's fault, it wasn't the pilot's fault, it
wasn't the flight attendant's fault, it was the asphalt."
15. Overheard on an American Airlines flight into Amarillo, Texas, on a particularly windy
and bumpy day: During the final approach, the Captain was really having to fight it. After
an extremely hard landing, the Flight Attendant said, "Ladies and Gentlemen, welcome to
Amarillo. Please remain in your seats with your seat belts fastened while the Captain taxis
what's left of our airplane to the gate!"
16. Another flight attendant's comment on a less than perfect landing: "We ask you to
please remain seated as Captain Kangaroo bounces us to the terminal."
17. An airline pilot wrote that on this particular flight he had hammered his ship into the
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runway really hard. The airline had a policy which required the first officer to stand at the
door while the Passengers exited, smile, and give them a "Thanks for flying our airline."
He said that, in light of his bad landing, he had a hard time looking the passengers in the
eye, thinking that someone would have a smart comment. Finally everyone had gotten off
except for a little old lady walking with a cane. She said, "Sir, do you mind if I ask you a
question?" "Why, no, Ma'am," said the pilot. "What is it?" The little old lady said, "Did we
land, or were we shot down?"
18. After a real crusher of a landing in Phoenix, the attendant came on with, "Ladies and
Gentlemen, please remain in your seats until Capt. Crash and the Crew have brought the
aircraft to a screeching halt against the gate. And, once the tire smoke has cleared and the
warning bells are silenced, we'll open the door and you can pick your way through the
wreckage to the terminal."
19. Part of a flight attendant's arrival announcement: "We'd like to thank you folks for
flying with us today. And, the next time you get the insane urge to go blasting through the
skies in a pressurized metal tube, we hope you'll think of US Airways."
20. Heard on a Southwest Airline flight. "Ladies and gentlemen, if you wish to smoke, the
smoking section on this airplane is on the wing and if you can light 'em, you can smoke
'em."
21. A plane was taking off from Kennedy Airport. After it reached a comfortable cruising
altitude, the captain made an announcement over the intercom, "Ladies and gentlemen,
this is your captain speaking. Welcome to Flight Number 293, nonstop from New York to
Los Angeles. The weather ahead is good and, therefore, we should have a smooth and
uneventful flight. Now sit back and relax... OH, MY GOD!" Silence followed, and after a few
minutes, the captain came back on the intercom and said, "Ladies and Gentlemen, I am so
sorry if I scared you earlier. While I was talking to you, the flight attendant accidentally
spilled a cup of hot coffee in my lap. You should see the front of my pants!" A passenger
in Coach yelled, "That's nothing. You should see the back of mine
XXXXV. Power Quality Revisited
Background
Utility companies have always made major efforts to provide reliable power with good
characteristics. The term “power quality”, however, took on an entirely new meaning about 20
years ago resulting from concerns with sensitive loads such as computers, PLC’s, digital clocks
and VCR’s. In these 20 plus years, no one has successfully been able to come up with a
definition of what constitutes good power quality. Power quality, like beauty, seems to be in the
eye of the beholder. While there is no agreed upon definition for good power quality, much work
in the areas of harmonics, surges, voltage flicker, interruptions, etc. has taken place.
The purpose of this section is to update the reader on the status of all these areas that
comprise the term “power quality”. Much has been done in terms of measurement,
standardization, surveys, and mitigation that this paper will attempt to summarize in a meaningful
fashion.
92
Definitions
Over the years, the number one problem with discussions between utility engineers and
customers has been in the area of definitions. Industrial engineers tend to refer to power
disturbances as dips, blips or flicker. For many of them (especially those without electrical
backgrounds), a blip could encompass anything from a momentary interruption to a sag, or even
voltage flicker. Figure shown below, illustrates some of the more common power disturbance
that are considered power quality problems that could result in mis-operation of sensitive
equipment. A brief, non-IEEE, definition of some of these disturbances is as follows:
Figure 5-Typical Voltage Disturbances
Sags – Sags are voltages between 90% and 10% of system nominal voltage. They
generally are caused by large loads starting or system faults. Generally faults on the customers
systems and on the utility system cause sags much deeper than those on events such as motor
starting.
Swells – Swells are phase to ground power frequency voltages between 110% and
140% that are the result of having a line-to-ground fault on an adjacent phase. The duration of
the swell is dependent on how fast the system fault is cleared by the protection scheme.
Harmonics – Harmonics are considered steady state events, where the 60 Hz waveform
of voltage and/or current becomes distorted. Harmonics are not normally caused by the utility
system itself. Instead, they are the result of non- linear loads, such as computers, dimmer
switches, arc furnaces, etc. These loads can inject harmonic currents into the utility system and
in severe cases cause problems for surrounding customers.
Surges - Surges are transient overvoltages that usually last less than a few
milliseconds. They are typically the result of lightning and equipment switching.
Interruptions – Interruptions are a complete loss of voltage to one or more customers.
The industry defines momentary interruptions as those lasting 5 minutes or less. A sustained
interruption is defined as loss of power for more than 5 minutes. It should be noted that the utility
93
industry defines reliability indices on the basis of momentary and sustained interruption
parameters only.
Voltage Flicker (not shown) – Voltage Flicker is a repetitious variation in the luminance
of a light source. The visibility of this fluctuation is a function of the repetition rate, the change in
voltage and the type (and rating) of the light source. Voltage flicker can be seen with very small
changes in voltage and is an annoyance to humans and not considered to be a problem for most
sensitive loads.
Overview of Industry Standards and Activities
The following is a list of the status of some of the significant PES industry activities in
many of the utility distribution power quality areas:
Reliability – “ IEEE Guide for Electric Power Distribution Reliability Indices - P1366”.
The purpose of this guide is to foster a uniformity of terms and definitions among utilities as well
as to establish consistent reporting practices and calculation methodology. The group has also
been at the forefront of performing surveys to help utilities benchmark their systems.
Harmonics – “ ANSI/IEEE Std 519, IEEE Recommended Practices and Requirements
for Harmonic Control in Power Systems”. The purpose of this document is to establish goals for
the design of electrical systems that include both linear and nonlinear loads. The voltage and
current waveforms that may exist throughout the system are described, and waveform distortion
goals for the system designer are established. This document addresses the steady state
limitations and sets a level of harmonic quality that should be provided at the point of common
coupling.
Sags – There are no utility guidelines for sags. The IEEE has established a task group
whose purpose is to establish guidelines with respect to the measurement and effect of voltage
sags. The group is presently addressing the steps necessary to develop sag indices. These
indices will no doubt have to address such items as the magnitude and duration of the sag as
well as the number of phases involved.
Swells - The magnitude of a swell is largely a function of the system grounding.
Information on the magnitude of swells for different types of system grounding can be found in
the “ IEEE Guide for the Application of Neutral Grounding in Electrical Utility Systems, Part IVDistribution”. Work in this area has not really taken place for the past 10 years.
Voltage Flicker – Most utilities continue to use the General Electric Flicker Curve,
originally published in 1921. A study published in 1994 by EPRI/CEA indicated that new
electronic and compact florescent lighting may be more or less prone to flicker that the standard
incandescent. Lamp dimming practices too, made flickering lamps more visible. The IEEE is
sponsoring a Task Group on Voltage Flicker. This group has proposed the adoption of the IEC
Flicker Standards with some minor commentary to reflect the difference in secondary voltage
level.
Industry Surveys, Guidelines and Statistics
One of the problems a utility has in assessing their power quality is finding information to
compare how they are doing with others. We all recognize that utilities are vastly different when
compared on the basis of load density, weather conditions, animals, etc. and hence it may be
impossible to come up with performance standards in most of these areas. It is, however, good
to know how you generally compare. The purpose of this section is to provide data from a
number of sources in the area of power quality that may prove helpful in any assessment of this
nature.
Reliability – Reliability for most utilities means, “sustained interruptions”, i.e.
interruptions of power to one or more customers lasting more than 5 minutes. While there are
many indices in use today, the primary indices being used by most utilities are SAIDI (average
amount of time a customer would expect to be without service), SAIFI (average number of times
a customer would expect to see an interruption of more than 5 minutes), and CAIDI (average
duration of an interruption). It should be noted that survey data in these areas is flawed since
94
utilities vary in how accurate their interruption numbers actually are. Utilities using sophisticated
computer systems to track outages accurately tend to have higher interruption times than those
that don’t. It has even been suggested that most of the utilities in the first quartile (best) are able
to do so because they do not keep accurate records. Some typical outage numbers (SAIDI) are
shown in Figure, below.
Minutes per Year
300
245
250
200
150
121
95
100
67
50
0
Q1
Q2
Q3
Q4
Quartile
Figure 6 – Average Time Without Service (SAIDI)
Sags – While sags are not reported to utility commissions, some monitoring studies have
been performed to give customers some idea of what to expect. The index used in most of these
studies is SARFI. SARFI represents the average number of specified rms variation
measurement events that occurred over the assessment period per customer served. For
example, if a customer saw 75 sags below 90% of voltage, that would be reported as SARFI90.
Likewise, if a customer saw 20 severe sags below 70% of nominal voltage, that would be
reported as SARFI70. Some typical SARFI values are shown in Figure 1 below.
Number of Incidents
60
50
50
40
30
18
20
10
10
0
SARFI90
SARFI70
SARFI50
SARFI Value
Figure 1 – Typical Number of Sags per Year (SARFI)
Harmonics – Harmonics are produced by nonlinear loads on the utility power system
such as static power converters, computers, and saturated magnetic devices. Harmonics can
result in such concerns as resonance, transformers overheating, sensitive equipment misoperation, etc. While harmonics have always been a major concern for industrial and commercial
customers with nonlinear loads, it is only within the past 20 years that the utility industry has
voiced any major concerns. This concern is based on the growing use of these harmonic
producing devices and their cumulative effect on the operation of the power system and
connected customers. To date, it is rare that a utility system sees an ambient level of harmonics
that will cause serious concern. To help insure that critical levels of harmonics do not become a
future problem, the industry has come up with a recommended practice for harmonic control
95
referred to as IEEE 519. The voltage limits recommended (simplified) in this document are
outline in Table 1.
Table 1 – Voltage Distortion Limits
Voltage at PCC (point of common coupling)
69 kV and below
69.001kV to 161kV
161.001 and above
Total THD % (total harmonic distortion)
5.0
2.5
1.5
Nonlinear loads produce harmonic currents, which in turn can distort the voltage. How
much the voltage is distorted is a function of the source impedance (high short circuit areas have
low source impedance and vice versa). Since these loads can be evaluated in terms of current
distortion prior to their actual installation, these current levels can be used (injected into a load
flow) to produce voltage distortions which can be evaluated based on the parameters shown in
Table 1. The industry has come up with limits for current distortion based on system short circuit
level. If the system short circuit level is high (source impedance low), a higher level of harmonic
current is allowed since it will have less effect on voltage distortion. Table 2, shown below, is a
simplified version these limits.
Table 2 – Current Distortion Limits (120V to 69kV)
Isc/Iload
<20
20-50
50-100
100-1000
>1000
Total Demand Distortion (TDD)
5.0
8.0
12.0
15.0
20.0
Flicker – Voltage flicker is the amplitude modulation of the fundamental frequency
voltage waveform by one or more frequencies (typically less than 30 Hz). These modulations,
which can be quite small, can cause visible brightening and dimming of connected lights. Voltage
flicker is primarily a visual perception problem and not a cause of equipment malfunction. For the
past 80 years the industry has almost universally employed the so-called “GE Flicker Curve”
shown in Figure . Until recently, there were no generally accepted standards for voltage flicker
measurements. There is an international standard now in place, which allows flicker to be
measured and evaluated on a common basis.
96
Figure 7 – GE Flicker Curve (1921)
Events per Residence per
Year
Surges – Surges normally refer to voltage transients resulting from lightning and
switching. These surges can have a high enough voltage level to cause insulation to break down
resulting in failure of the equipment. Surges are very common since they can be the result of
simply turning on a light switch (current chopping e=L*di/dt). Surges per a study performed some
time ago and found in C62.41 are shown in Figure .
25
20
15
10
5
0
350-500
500-1000
1000-1500
1500-2000
Surge Voltage Range
Figure 8 – Typical Surges in Residence
XXXXVI. Application of Capacitors
Introduction
The application of capacitors has become commonplace in the United States. There was a
time when the application of capacitors on a wide scale basis was unusual because losses didn’t
cost that much and regulators handled the voltage drop quite well.
97
Things have changed. Losses are a major concern. Voltage quality, due to more sensitive
loads, is an issue. Finally, in today’s world of cutting costs, capacitors are seen as the cheap
way to reduce losses and get more watts out of what’s already there.
The purpose of this section is to very briefly review some of the considerations distribution
engineers might address in the application of capacitors.
Benefits of Capacitors
The proper application of capacitors serves to reduce the system current and raise the system
voltage. This accomplishes 3 benefits:
1. Reduces loading of thermally limited equipment.
2. Reduces system voltage drop
3. Reduces system losses
The application of capacitors benefits the entire system and the value of these benefits for the
entire system should be considered when considering how many capacitors should be installed.
It should not be overlooked that kilovars flowing through the system cause reactive as well as
real losses. This means that when a certain quantity of kilovars is required at the load, more than
that will be required at the source of the kvars.
Typical Placement Studies
Most utilities try to apply capacitors “optimally”. Years ago, when voltage levels were low and
wire sizes were smaller, an “optimal placement study” might mean placement of the capacitor
banks to obtain a reasonable voltage profile. Today, optimum placement normally means place
to minimize losses at the lowest cost.
Placement Studies are normally performed in one of two ways:
Place capacitors until optimum power factor is reached (point where the cost of adding bank
exceeds value of losses reduction and equipment utilization benefits).
• Place capacitors until a predetermined power factor is met. This number is sometimes quite
arbitrary.
Optimal placement would be easy if the load didn’t change. The problem with placement
studies is that loads change during the day, week, month and most schemes have to deal with all
these changes as best they can. Shown below, is a plot of a scheme that was not optimized for
the summer peaking period. As can be seen in figure 9, the var needs change dramatically over
a fairly brief period of time. The challenge to the distribution engineer is to pick the correct size of
the banks to be used, the placement of these banks and minimize the cost.
•
10.00
8.00
MVAR/MW
6.00
4.00
MW
MVAR
2.00
0.00
8:30
7:00
6/30/98 7/1/98
5:30
7/2/98
4:00
7/3/98
2:30
1:00
7/4/98 7/5/98
23:30
7/5/98
22:00
7/6/98
20:30 19:00 17:30 16:00 14:30 13:00 11:30 10:00
8:29
7/7/98 7/8/98 7/9/98 7/10/98 7/11/98 7/12/98 7/13/98 7/14/98 7/15/98
-2.00
-4.00
HOUR/DATE
Figure 9 – Plot of MW and MVARS
Shown in figure 10 are typical placement scenarios for a feeder having 10 nodes (in this case
the nodes were 10 miles apart). As can be seen, the plot shows optimum placement of both the
98
KVAR
fixed and switched banks. This placement was determined using a computer optimization runs at
various load levels.
1400
1200
1000
800
600
400
200
0
Switched
Fixed
1-2 2-3 2-3 3-4 4-5 5-6 5-7 7-8 7-9
910
Optimum Capacitor Location
Figure 10 – Optimal Placement
One method which helps assess how much of the needs can be satisfied with fixed banks is
the use of a cumulative loading curve as shown in Figure 11. As can be seen, the load is virtually
always at 50% or greater. This curve is also valuable for setting stages of the controls.
120.00%
Percent of Time
100.00%
80.00%
60.00%
40.00%
20.00%
0.00%
0.00%
20.00%
40.00%
60.00%
80.00%
100.00%
Percent of Peak Load
Figure 11 – Cummulative Loading Curve
Control of Switched Banks
The control of a switched capacitor bank is very dependent on things like cost, type of load,
climatic conditions, voltage concerns both on the distribution and subtransmission system,
amount of acceptable complexity, etc. There are several types of control in use today:
• Voltage
• Current
• VAR
• Temperature
• Time
• Power Factor
• Automation
• Combinations of the above
Some of the advantages and disadvantages of each of these controls is briefly described as
follows:
- Voltage is relatively inexpensive and works well when voltage varies with load. On short
feeders where voltage drop is not great this method is difficult to coordinate. On modern
systems, it is generally used as an over-ride for emergency voltage conditions.
- Current control responds to loading well. It does require a current transformer which adds
to the expense. Major problem with current control is that it cannot differentiate between low
power factor loads like air conditioners (summer) and high power factor loads(winter)like
resistive heating.
- VAR control is effective for minimizing losses and can differentiate between summer and
winter peaks. It is expensive since it requires both CT’s and PT’s. It is very difficult to set
VAR controlled capacitors optimally when multiple switched banks are used.
99
-
-
-
-
Temperature is simple and inexpensive. It seems to work very well in many areas of the
country where air conditioning load dominates peak conditions. One drawback is that it
does not recognize holidays or weekends and for this reason usually requires some sort of
voltage override.
Time is also simple and inexpensive. It does not sense abnormal loads and can often get
out of sync due to extended power outages, holidays, etc. The more modern voltage
controllers avoid most of the concerns associated with the older mechanical units and have
had good success in some areas.
Power Factor is similar in application to VAR control. One consideration with this type of
control is a low power level, low power factor load could switch the banks in unnecessarily
(the opposite could also be true).
Automation of capacitor controls is showing very strong promise and customer acceptance
since the costs of these schemes is coming down and the benefits, in today’s environment
can be significant. Some of the benefits of automating the banks are greater flexibility,
better VAR support for transmission, control schemes are simpler, and it is easier to detect
failed banks.
Combinations of the above are commonplace especially where voltage is used as an override for emergency conditions.
VAR Requirements of Substation Transformers
One the more recent concerns for vars is the increasing need to compensate for reactive losses
in the substation transformer. This problem has sort of snuck up on some utilities due to the
following scenario. “Utility X purchases a transformer back in 1970 with a triple rating
(OA/FA/FOA). To reduce some of their concern for their growing short circuit levels they
purchase a transformer with a higher than normal impedance. In their effort in the late 90’s to
reduce cost, they decide to load these transformers according to the loading guides instead of
the more conservative approach of the past since transformers rarely fail due to overload. The
problem is this: if we assume a 30/40/50 MVA transformer at 14% impedance and loaded to
130%, this transformer will have over 15 MVARs of losses. That’s a big bank in the world of
distribution. At 100% of rating the losses are about 10 MVAR.
Capacitor Protection
A. Effect of Grounding
There are a number of ways to ground capacitor banks. While grounded wye banks are
normally used, there are sometimes reasons why this connection may not be optimum. A
summary of considerations in this area is as follows:
• A three phase capacitor may be connected in delta, wye-ungrounded or wye-grounded.
• Delta or ungrounded wye offer the greatest possibility of neutral inversion or a resonant
condition when one or two conductors on the source side of the bank are open. It can
consequently be a problem to locate these banks on the load side of a switch or fuse.
• Grounded wye banks are usually used on 4 wire multi-grounded systems only. A grounded
wye bank on an ungrounded system creates a ground source that may interfere with
sensitive relaying as well as contribute to overvoltages during ground faults on these
ungrounded systems.
• Grounded wye banks are generally easy to clear since there is adequate ground current. On
the other hand, ungrounded banks have the currents limited to 300 percent of normal phase
current by the impedance of the other two legs. The fuse must have a continuous current
rating of 135% of rated current of the bank and clear in 5 minutes for reasonable
coordination. It is sometimes difficult to satisfy both conditions.
To summarize:
−
For delta or ungrounded systems, delta connected banks are usually used except at system
locations where fault current is excessive, ungrounded banks are most common.
100
−
−
For grounded, 4-wire systems, grounded banks are used in most locations. Where fault
current is excessive, ungrounded banks are used. Ungrounded banks should be used on the
load side of switches.
In substations the banks are almost always wye-connected. On delta systems they are
always ungrounded and on 4-wire systems they are either grounded or ungrounded.
B. Fusing
When a capacitor bank fails, the energy stored in its series group of capacitors is available to
dump into the combination of the failed capacitor and fuse. The failed capacitor and fuse must
be able to absorb or hold off this energy with a low probability of case rupture of the capacitor
unit. The available energy is about 3.19 joules per kVAR. The available energy is compared with
the rating of the fuse and capacitor unit. This is one of criteria for selecting a current limiting fuse
for high energy applications (large banks) as opposed to an expulsion fuse.
Capacitor Switching
Most textbooks on distribution engineering (including my own ) cover the mechanism by which
capacitors can cause overvoltages as a result of either energization, or de-energization with
restrike. While even low level capacitor switching transients have been known to cause
misoperation of customer equipment (e.g. adjustable speed drives), we rarely encounter
switching transients on distribution systems which can cause utility equipment failure. The
conditions that can create problems on distribution systems normally occur at the higher voltage
levels while switching large capacitor banks or long distances of cable. Digital calculations of
transient overvoltages are shown below, for an actual 34.5kV underground system having a
very large 15 MVAR capacitor bank at the substation.
- Energization of a 15 MVAR substation bank = 2.65 p.u.
- De-energization of 15 MVAR substation bank with re-strike >3 p.u.
- Energization of Feeder Cable = 2.18 p.u.
- Cable De-energization (no restrike) = 1.0 p.u.
- Pre-insertion resistors reduce surges by about 40% for energization of the substation bank.
Series Capacitors
Series capacitors were used some years ago when systems were lower voltage, wire was
smaller and power factor was low (uncorrected). Series capacitors were used to instantly
respond to load changes resulting in voltage flicker. Over the years, series capacitors obtained
somewhat of a poor reputation (some say undeserved) for causing system problems, some of
which are addressed below. Modern systems generally do not see as much benefit from series
capacitors since system power factors are generally higher. However, there have been a
number of modern applications where series capacitors have proven very effective and without
the possible problems due in some part to modern series capacitor design.
Large Motor Load
Figure 12 – Series Capacitor Application
101
Some of the collective “application wisdom”, with regard to series capacitors, is as follows:
• Applicable to radial load circuits supplying loads of about 70 to 95 percent lagging power
factor. Below that, shunt are usually better and above that, the benefits are low.
• KVAR in series caps is generally less than half that for a shunt bank with the same
voltage effect.
• The current rating of the capacitor bank equals that of the circuit since they must carry
rated circuit current continuously. In addition, they must be able to carry temporarily, the
starting current of the largest motor plus other loads. The total steady state current plus
transient current should not exceed 1.5 times rating.
• The rating of the series capacitor (kilovars, voltage, and current) for a radial feeder
depends on the desired voltage regulation, the load power factor, and the amount of
resistance and reactance in the feeder relative to each other and the circuit rating.
• Standard capacitor units can withstand about 200 percent of their rated working voltage
for brief periods without damage to the dielectric; therefore it is necessary to use
capacitors with continuous current ratings equal to 50 per cent of the maximum current
that may flow during a fault. It is usually more cost efficient to use protective devices
across the bank.
• Operating problems with series capacitors include:
o Subsynchronous resonance of a motor during starting – can usually be avoided
with a resistor in parallel with the capacitor. Sometimes just shorting the
capacitor during starting works (gap may go over anyway due to the half
frequency impedance of the capacitor).
o Ferroresonance of a transformer - High magnetizing inrush of transformer may
create a resonant condition. This is generally automatically cured by the parallel
gap. The gap is usually set at twice the rating of the capacitor. A resistor
shunting also works.
o Hunting of motors
102
Pros and Cons of Good Grounding
NTRODUCTION
Distribution neutral grounding is probably one of the most confusing subjects faced by
the utility distribution engineer. In an industry where utilities are combining practices,
complicated by the fact that European utilities are purchasing U.S. systems and vice
versa, the confusion has been compounded. Questions being asked are:
• Is good grounding really necessary?
• Does poor grounding have advantages?
• What is the best grounding?
• When is grounding important? And when is it not?
The purpose of this section is to attempt to answer some of these questions. It will be
shown that while good grounding is usually preferred, there are times when good
grounds are not important and may even be detrimental. Some of the grounding areas
covered are:
• Classes of distribution system grounding
• Arrester application
• Effect on swells
• Stray voltage
• Line protection
• Capacitor grounding
• Overcurrent protection
• Number of grounds per mile
• Etc.
Fig. 1. Typical 4-Wire Multigrounded System
103
CLASSES OF SYSTEM GROUNDING
There are many ways to ground a distribution system primary. This paper will deal
primarily with the effects of grounding on a 4-wire multigrounded system since it
predominates in this country. The following section, however, gives a brief overview of
some of the advantages and disadvantages of the various system grounding practices in
use today.
Distribution systems are classified as either grounded or ungrounded. While there are
advantages and disadvantages of each type of grounding, it is impossible to say which is
the “best”. The following is a general description of the major types:
A. Ungrounded Systems
Ungrounded system have the secondary windings of the distribution substation
transformer connected either ungrounded delta or ungrounded wye, with the former
connection being more common. The distribution feeders are three-wire, three-phase
and two-wire single-phase circuits. The major advantage of an ungrounded system, like
a delta system, is that a single line to ground fault will not result in high levels of fault
current sufficient to disrupt service beyond the fault itself. This is also a disadvantage in
that overcurrent protection for this type of fault is difficult if not impossible to detect. The
delta system also gives better phase balancing, lower energy into a fault, and produces
less EMF.
B. Grounded Systems
Grounded systems are usually derived from a distribution substation transformer with
wye-connected secondary windings with a neutral point of the windings solidly grounded
or connected to ground through a non-interrupting, current-limiting device such as a
resistor or reactor. A grounding transformer may be used to establish a grounded
system, as is common in Europe. The circuits associated with grounded distribution
systems generally have a neutral conductor connected to the supply grounding point.
The neutral conductor of the distribution circuits may be connected to earth at frequent
intervals (multigrounded), or it may be fully insulated and have no other earth connection
except at the source (unigrounded). In three-wire unigrounded systems, a neutral
conductor is not run with each circuit, but the system is grounded through the
connections of the substation transformer or grounding transformer. The neutral
conductor associated with the primary feeders of multi-grounded neutral distribution
systems is connected to earth at intervals specified by national or local codes. It is also
common practice to bond this neutral conductor to surge-arrester ground leads and to all
noncurrent-carrying parts, such as equipment tanks and guy wires, and to interconnect it
with a secondary neutral conductor or grounded conductor. In some situations, the same
neutral conductor is used for both the primary and secondary systems. Several types of
grounded systems are as follows:
• Four-Wire Multigrounded Systems: This system is by far the most popular in the U.S.
and has the advantage of being easy to protect for most overcurrent fault conditions. It is
also preferred since a large portion of the loads in the U.S. are single phase and can be
connected between the phase wire and the neutral conductor. It is much cheaper for
single phase service, especially for underground, since only one cable, bushing, switch,
104
•
•
•
fuse, etc., needs to be used as compared to a delta system which needs almost twice as
much equipment. It also can use lower rated arresters and BIL.
Four-Wire Unigrounded Systems: This system uses 4 wires, but is only grounded at
the source. It is used sparingly in the U.S. The primary advantage of this system is that
greater ground relaying sensitivity can be obtained in comparision to the multi-grounded
system. It also produces less EMF. A disadvantage of this system is that it creates
higher voltage swells than the multigrounded system.
Three-Wire Unigrounded Systems: These systems are popular in Europe. Because
line-to-ground current levels are generally low using this system, it is difficult to
coordinate series overcurrent devices (similar to problems with a delta system). With the
predominance of 3 phase loading in Europe, the system tends to be much more
balanced than a system found in the U.S. allowing for much greater sensitivity to ground
fault detection.
Five-Wire Distribution System: This is a new system which utilizes three phase wires,
a multigrounded wire and an isolated neutral. It has several advantages over the fourwire multigrounded system in that it has the ability to detect high impedance faults,
reduce EMF, see faults farther out of the substation, and reduce stray voltages.
EFFECT OF GROUNDING
A. Capacitor Banks
There are a number of ways to ground capacitor banks. While grounded wye banks are
normally used, there are sometimes reasons why this connection may not be optimum.
A summary of considerations in this area is as follows:
• A three phase capacitor may be connected in delta, wye-ungrounded or wye-grounded.
• Delta or ungrounded wye offer the greatest possibility of neutral inversion or a resonant
condition when one or two conductors on the source side of the bank are open. It can
consequently be a problem to locate these banks on the load side of a switch or fuse.
• Grounded wye banks are usually used on 4 wire multi-grounded systems only. A
grounded wye bank on an ungrounded system creates a ground source that may
interfere with sensitive relaying as well as contribute to overvoltages during ground faults
on these ungrounded systems.
• Grounded wye banks are generally easy to clear since there is adequate ground current.
On the other hand, ungrounded banks have the currents limited to 300 percent of normal
phase current by the impedance of the other two legs. The fuse must have a continuous
current rating of 135% of rated current of the bank and clear in 5 minutes for reasonable
coordination. It is sometimes difficult to satisfy both conditions.
To summarize:
−
For delta or ungrounded systems, delta connected banks are usually used except at
system locations where fault current is excessive, ungrounded banks are most
common.
−
For grounded, 4-wire systems, grounded banks are used in most locations. Where
fault current is excessive ungrounded banks are used. Ungrounded banks should be
used on the load side of switches.
−
In substations the banks are almost always wye-connected. On delta systems they
are always ungrounded and on 4-wire systems they are either grounded or
ungrounded.
B. Overvoltages (Swells)
105
Swells are steady state overvoltages caused by faults on adjacent phases. The duration
of these overvoltages is dependent on the protection practices used by the utility. Swells
can result in power quality problems as well as failure of arresters. Some grounding
considerations regarding the magnitude of swells are as follows:
Maximum L-N Voltage (p.u.)
1 .4 5
1 .4
1 .3 5
1 .3
4 g p m
8 g p m
1 .2 5
1 .2
1 .1 5
1 .1
1
1 0
1 0 0
1 0 0 0
G r o u n d F o o tin g R e s is ta n c e (o h m s )
Fig. 2. Effect of Footing Resistance and Ground Rod Spacing
•
•
•
Effect of Footing Resistance, Soil Resistivity and Ground Rod Spacing: Studies run
by the authors show that if an arbitrary swell limit of 20% is desired (this is the value used
for arrester application by many utilities), it is necessary to have a ground footing
resistance of less than 1 ohm for a typical 4-wire system. A footing resistance of 25
ohms produces overvoltages (near the end of the line) of about 1.31 per unit for the same
system. Using a ground footing resistance of 25 ohms does reduce overvoltages for
faults within about 5 miles of the substation as compared to 100 ohms. Faults beyond 5
miles produce swells that are virtually identical. The results of this study also showed
that the use of the standard 4 grounds per mile is not sufficient to keep these
overvoltages (swells) down to the desired level (see figure 2). If the number of grounds
is increased to 8 per mile, there will be a reduction of about 2% with a footing resistance
of 25 ohms. Augmenting the number of grounds per mile does not have a significant
effect on reducing swells. This is especially true since there are many equipment
grounds on the system. When soil resistivity was changed from 100 ohm-m to 1000
ohm-m, virtually no change occurred in the magnitude of the swells.
Broken Neutrals: Neutrals play a major role in the effectiveness of the grounding
system. Studies show that fault 10 miles from the substation can cause swells of 1.33
per unit for a broken neutral on any part of the system. Even faults at only 1.5 miles from
the substation can cause swell of up to 1.5 per unit if a broken neutral exists. The size of
the neutral conductor appreciably reduces swells, whereas good grounds do not affect
the voltage much. This indicates that the neutral is more important than the grounding.
Substation Grounding: Substation grounding has little effect on swells. Substation
grounding impedance of 0.5, 1.0, 2.0, and 3.0 showed little difference in their effect on
swells caused by faults out on the feeder.
C. EMF
Unbalanced load current flows in the ground and the neutral wire. The current flowing in
the ground creates most of the magnetic field associated with EMF. Current in the
neutral tends to reduce this field. Studies show that for typical conditions approximately
50% of the return current flows in the earth and the other 50% in the neutral. A case can
be made, that poor grounding forces more current in the neutral and thereby reduces the
EMF. Measurements taken by one of the authors on actual systems shows ground
impedance to be far less of a factor than what many studies show. You be the judge.
106
D. Fault Levels
Studies show that ground rod footing resistance does slightly affect fault current levels for
close in faults but has little effect for faults more than 4 or 5 miles from the substation.
Figure #3, shown below, is a plot of “actual” measure faults, faults calculated with 25
ohms neutral ground rod impedance and faults with no ground rod impedance
(symmetrical components). As can be seen, there is very little difference. Since close in
fault magnitudes are almost always sufficient to operate protection properly, footing
resistance in this area is not an issue. Fault magnitudes farther from the substation are
not seriously affected by footing impedance. It can hence
be argued that footing resistance is not important in the area of overcurrent protection.
Fig. 3 Comparison of Fault Calculations
E. Stray Voltage
While most cases of stray voltage are the result of on-site” generated problems, it can
also be the result of a poor utility return path (earth and neutral wire). Utility caused stray
voltage is the result of the return current (or unbalanced 3-phase current) returning via
the neutral wire and the ground and producing a voltage which is passed to the customer
premises via the distribution transformer connection. The flow of current in these paths is
complex and depends on many factors (distance from substation, number for grounds,
value of footing resistance, size of the neutral, etc.). While good ground footing
resistances near the affected customer are important, the problem is more affected by
the magnitude of the return current and the size of the neutral conductor. Reducing the
ground footing resistance near the customer many times proves ineffective for this
reason.
F. Arrester Grounding
Arrester grounding is not as critical as most engineers believe. It depends. Studies
show that where arresters are put on every phase and every tower or pole, ground
resistance between 0 and 250 ohms had little effect on flashover rates. As spacing of
arresters is increased, grounding does have a relatively minor influence. The problem
with arresters used for direct stroke protection is that they will most likely fail anyway due
to energy of the stroke. For a direct strike to a distribution line, even with several
arresters sharing the energy in a lightning flash, an arrester will be subject to energies in
excess of 5 kJ/kV of MCOV more than 50% of the time. Ten percent of first strokes are
likely to subject an arrester to greater than 12 kJ/kV of MCOV. Most heavy duty
distribution class arresters can only absorb about 2.2 kJ/kV of MCOV. This along with
the added energy in multiple strokes and continuing current suggest that direct hits will
cause MOV failures most of the time. On a distribution line, a shield wire used in
conjunction with the arrester is recommended if more complete protection is desired,
since the shield wire intercepts most of the energy (At transmission voltage level, the
107
problem is less serious due to the much higher BIL levels of the structures and large
energy capability of the arresters). It can be argued that poor arrester grounding may
help the arrester survive since the arrester closest to the lightning hit does not absorb all
the energy and shares it with adjacent arresters.
Percent
Flashovers
per Strike
% F lashover for A rresters
6
4
2
0
0
25
100
250
500 1000 2000
G ro u n d R esistan ce
Fig. 4 Effect of Resistance on Arresters
G. Shield Wires
Ground resistance is very important when using a shield wire as is the spacing of the
grounds. A shield wire can be very beneficial if very low ground resistances can be
achieved. For example, simulations on a standard distribution system design indicated
that with a ground resistance of 0 ohms, essentially no flashovers could be expected. If
the ground impedance was increase to 25 ohms, about 22% of the hits would cause a
flashover and with a ground footing impedance of 100 ohms, over 82% of the direct hits
would cause the line to flashover. Using a shield wire, it is essential to put grounds on
every span to achieve good protection. Field tests by one of the authors have proven
this to be true. A sampling of about 50 feeders with static wire protection and a
significant percentage of poles without static grounds (>15%) revealed a dramatic
difference in performance (>50% reduction in lightning related flashovers) when grounds
were added to these poles.
108
Percent
Flahovers per
Strike
% Flashover for Shield Wire
100
50
0
0
25
100
250
500 1000
Ground Resistance
Fig. 5 Effect of Resistance on Shield Wires
The Man In the Arena
It’s not the critic who counts, not the man who points out how the strong man stumbled, or where the doer of deeds could have
done them better. The credit belongs to the man who is actually in the arena; whose face is marred by dust and sweat and blood;
who strives valiantly; who errs and comes short again and again; who know the great enthusiasms, and spends himself in a worthy
cause; who, at best, knows in the end the triumph of high achievement; and who, at the worst, if he fails, at least fails which daring
greatly, so that his place shall never be with those cold and timid souls who know neither victory nor defeat.
Theodore Roosevelt
Tidbits
a. Fuse Save vs. Fuse Blow Survey Results
Historically, one of the primary purposes of reclosing, was to save the fuse during
temporary fault conditions. It has been well known that in high fault current areas (above
approximately 4kA depending on fuse size and type), it was impossible to save the fuse since the
fuse was simply too fast (.5 cycles) and hence could not be saved even by the fastest breaker or
recloser (after you get about a mile or 2 from the substation, it is usually possible to save the
fuse).
We have seen the industry reassess their overcurrent coordination practices, on
overhead systems, in an effort to address power quality issues (momentaries). There are now
essentially 3 approaches that utilities use:
1. Fuse Save – This approach makes the attempt to minimize customer interruption
time (reduce SAIDI) by attempting to open the breaker or recloser faster than it takes
to melt the fuse. This saves the fuse and allows a simple momentary interruption…a
blink. For most systems, this works pretty well. In high short circuit areas, it may not
be possible to make this approach work.
2. Fuse Blow – The approach here is eliminate the fast trip of the breaker or recloser
and have the fuse operate for all permanent and temporary faults. The purpose of
this scheme is solely and entirely to minimize momentary interruptions. This scheme
is very successful in high short circuit areas where a “fuse save” approach didn’t
work anyway. The downside of the “Fuse Blow” concept is that it increases SAIDI,
i.e. in an effort to increase power quality (momentaries), we decrease reliability.
3. Both – Many utilities use both schemes for a variety of reasons:
• Fuse Blow for high short circuit current areas and Fuse Save
where it will work.
• Fuse Save on overhead and Fuse Blow on underground taps
109
•
•
•
Number of Utilities Reporting
Fuse Save on rural and Fuse Blow on urban
Fuse Save on stormy days and Fuse Blow on nice days.
Fuse Save on some circuits and Fuse Blow on others depending
on customer desires
• Etc.
Although there has been a lot of discussion on this in the industry, it was unclear as to
what utilities were actually doing these days. The following informal survey addressed the status
of the industry to date:
90
80
70
60
50
40
30
20
10
0
78
54
Fuse Save
Fuse Blow
Both
24
17
Total Save
Fusing Philosophy
* Total Save - This category is the number of utilities that are presently using a fuse save philosophy at least on some
portion of their system
Survey Observations:
• Most of the utilities adopting the “Fuse Blow” philosophy are from the northeast area of
the United States, and have relatively high short circuit levels. These utilities indicate
that momentary operations are their primary concern. Most seemed to recognize that
this approach will reduce system reliability (SAIDI).
• A surprising number of utilities reported that they do the best they can to tailor their
philosophy to the conditions (short circuit levels, type of customer, etc.) and choose the
philosophy that’s best for the individual situation.
• The vast majority of utilities use a “Fuse Save” philosophy, when it works, and do not
consider momentary operations more important than interruptions.
• Most of the utilities, indicating the “Both” category, try to save the fuse on overhead lines,
if they can. They indicated both because they either had very high short circuit areas
(fuse operates anyway) or a large portion of underground taps (no temporary faults).
• A large number of utilities block their instantaneous trip in high fault current areas and
install a recloser out on the feeder where “fuse saving” can be successful.
• Utilities going to a “Fuse Blow” approach appeared to be cognizant of the fact that they
were converting temporary faults into permanent interruptions and thereby greatly
increasing the frequency of interruptions (by a factor of 4) for faults on overhead lateral
taps.
• Some of the utilities listed in the “Fuse Blow” category do not actually have their entire
systems implemented with this scheme although it is their chosen philosophy.
• There are a number of instances where results were received from more than one
recipient from the same company. Since so many companies today operate with totally
different practices, due to mergers, etc., there was no attempt to consolidate those
results.
• This is an informal, unfunded survey.
b. Slant Rated Cutouts
110
Ever been confused about slant ratings? Join the crowd! Slant rated cutouts are
referenced by ANSI C37.42 as being 7.8/15 kV, 15/27kV or 27/38kV. Slant rating 7.8/15kV for
example, can be used on grounded wye, wye or delta systems as long as the line-to-neutral
voltage of the system is lower than the smaller number, 7.8kV, and the line-to-line voltage is
lower that the higher number, 15kV.
The rating implies that one cutout will interrupt the full rating when the lower number
7.8kV, is applied during a line to ground fault. Two cutouts in series, such as with a line-to-line
fault, will share the applied voltage and, thus, interrupt the higher voltage rating,15kV. If there is
a line-to-line fault of a low current magnitude, two cutouts in series may not share in the
interruption and, thus, the applied voltage. One cutout may be required to perform the interruption
by itself. A slant rated cutout can withstand the full line-to-line voltage whereas a cutout with a
single voltage rating could not withstand the higher line-to-line voltage.
c. Energy Outlook
Wind
• Leading technology in terms of growth
• Approximately 2,000 MW per year being installed
• Tax incentives remain main drivers
Photovoltaics
• Still twice as expensive as normal grid power
• Growth is dependent on government support
Biomass
• Niche opportunity
• Market uncertain
Low-Impact Hydro
• Significant untapped potential, but U.S. market is small absent major changes to
the permitting and licensing process
Geothermal
• Dependent on government subsidy
Nuclear
When I started in the business (1965), it looked like the industry would go totally nuclear
since it was cleaner and less expense (pre-lawyers….I guess). Much of the world depends on
nuclear. Canada, the only country, shown below, using less nuclear then us, has a lot of hydro.
The chart below makes you wonder whether we’re smarter than the rest of the world or quite the
opposite when it comes to generation. I would suggest that much of the push to DG is a step
backward. Are “renewables” real or just a hobby? You decide!
111
90
80
70
60
50
40
30
20
10
0
Li
th
ua
ni
Fr a
an
Be ce
lg
iu
Uk m
ra
i
Sw n e
Sw ed
itz en
er
la
nd
So J a
ut pa
Un h K n
ite o re
d
St a
at
e
Ca s
na
da
% Nuclear
Nuclear Generation
c. Critical Flashover – The critical flashover voltage (CFO) of self-restoring insulation (meaning
no damage after the flashover) is the voltage where the insulation has a 50% probability of
flashing over from a standard 1.2X50 microsecond voltage wave. A statistical BIL is the 10%
probability value for the standard test wave. Normally the CFO and BIL are within a few percent
of each other. CFO for some components is:
Kv/ft.
Air
180
Wood
100
Fiberglass
150
d. Cost of Poor Power Quality – Here are some neat numbers (large Industrial Loads) for you
PQ types:
Disturbance
Voltage Sags
Momentary Outage
1 Hour Outage with Notice
1 Hour Outage without
Notice
4 Hour Outage
Cost per Event
$7,694
$11,027
$22,973
$39,459
$74,835
e. Electric Cars - The power of the 16.6 million cars and light trucks sold in the United States
in 2003 adds up to 2.5 times the total U.S. generating capacity. So much for electric cars!
112
f. Lightning – A direct hit to a distribution line is difficult to protect for whether you use a shield
wire, lightning arresters or both. The success of lightning arresters and higher insulation levels is
probably due to their ability to mitigate induce hits (strokes to surrounding trees, buildings, etc.
Induced voltages have been measured up to 300 kV. Strokes hitting 60 feet away induce about
5.25 kV per kA and those 400 feet away about 2.23 kV/kA. Lightning strokes can be as high as
100 kA or even more. More typical is about 30 kA. Shield wires do not work well if the ground
rod resistance is high (about 10 ohms or more).
g. Surge (Characteristic) Impedance - A transmission line can be represented by a whole
series of small series inductors and shunt capacitors connected in an infinitely long line. The
inductance and capacitance values per unit of line, depend on the size of the conductors and the
spacing between them. The smaller the spacing between the two conductors, and the greater
the diameter, the higher the capacitance and the greater lower the inductance. Each series
inductor acts to limit the rate at which current can charge the following shunt capacitor, and in
doing so establishes a very important property of a transmission line, its surge impedance.
When the voltage is applied to the sending end of a line, the voltage at any point on the
line actually consists of two voltages, one voltage traveling from the sending end of the line
toward the receiving end, the other traveling from the receiving end back to the sending end. The
former will be designated as E+, the latter E-. Each of these voltages is accompanied by the
corresponding current, I+ and I-, respectively. The ratio of either voltage to its corresponding
current at any point in the line is a constant Z0, which is independent of the line length but is a
function of the series resistance, the series inductance, the shunt conductance, and the shunt
capacitance of the line per unit length. This constant is the characteristic impedance of the line
and can be expressed as;
+
E I
+
= −E
−
I
−
=
Z0
⎛ R + j ωL ⎞
= ⎜⎜
⎟⎟
⎝ G + j ωC ⎠
Where; R = resistance in ohms per unit length
L = inductance in henrys per unit length
G = shunt conductance in mhos per unit length
C = shunt capacitance in farads per unit length
And = 2 π f, where f is the frequency in cycles per second
In actual practice at high frequencies, such as lightning, the quantities jwL and jwC are
so large in comparison with R and G that the latter can be neglected and the characteristic
impedance expressed simply as
Z0 =
L
C
Typically the surge impedance of lines up to 230 kV is relatively constant (regardless of
wire diameter) at about 400 ohms.
h. Ungrounded Systems
• One of the problems with ungrounded systems was that as systems grew, faults
were no longer self clearing due to large capacitive currents
• Ungrounded systems recorded higher transient overvoltages
• An ungrounded system “in a sense” is capacitive grounded
• On an ungrounded system, a line-to-ground fault causes 3 times the capacitive
current
113
•
A resonant grounded system is one in which the capacitive current is tuned or
neutralized by a reactor (ground fault neutralizer or Peterson coil)
Ground Fault Neutralizer Current/mi. of Single Phase
Amps
kV
23
.145
34.5
.200
46
.260
69
.390
Top 10 Funny Store Signs
1. Outside a muffler shop: "No appointment necessary, we hear you coming."
2. Outside a hotel: "Help! We need inn-experienced people."
3. On a desk in a reception room: "We shoot every 3rd salesman , and the 2nd one just
left."
4. In a veterinarians waiting room: "Be back in 5 minutes, Sit ! Stay!"
5. At the electric company: "We would be de-lighted if you send in your bill. However, if
you don''t you will be."
6. On the door of a computer store: "Out for a quick byte."
7. In a restaurant window: "Don''t stand there and be hungry, come on in and get fed up."
8. Inside a bowling alley: "Please be quiet, we need to hear a pin drop."
9. In the front yard of a funeral home: "Drive carefully, we''ll wait."
10. In a counselors office: "Growing old is mandatory, growing wise is optional.
i. Broadband over Power Lines (BPL)
BPL is the delivery of broadband Internet signals using the power lines already
connected to homes and businesses. The frequency range of the signal is normally between 1.7
and 80 megahertz. BPL has gone by other names including power line carrier (PLC) and ripple
control. PLC proved to be a problem because the high frequency signal was severely attenuated
or even blocked by voltage regulators, circuit reclosers, transformers and shunt capacitors. The
ripple control applications proved to be limited by low data rates and was used primarily for oneway applications such as meter reading. The advent of spread spectrum technology, developed
first by the military, made BPL technologically feasible.
BPL uses a form of spread spectrum called “orthogonal frequency division multiplexing
(OFDM), which has the benefits of high spectral efficiency, resiliency to RF interference, and low
multi-path distortion. The BPL OFDM typically uses and unlicensed spectrum between 1
megahertz and 100 megahertz. The FCC requires that these signals not cause interference with
other users and accept any and all interference from other users.
114
It is estimated that over 75 utilities have pilot projects in the area of BPL. Some of the
pros and cons of BPL are:
PROS:
• Uses existing power lines where cable might not be present
• It works
• Can interface with many types of electrical equipment
CONS
• Interference concerns with amateur radio operators, short wave emergency
communication, fire departments and police, etc.
• Problems are sometimes difficult to track down and solve
• Possibility of multiple lawsuits due to interference concerns
• Cost (requires economics of scale to be attractive)
• Competing technologies
• Rural areas may not be economically feasible
Alternatives to BPL include:
•
•
•
•
•
•
•
DSL
Cable TV
WiFi and Wimax
Mesh Networks
Wireless Internet Service Providers
FiberSatellite
Technology Improvements
Jim Burke
109 Dorchester Pines Court
Cary, NC 27511
distjimb@aol.com
115
INDEX
Arc impedance……19
Arrester grounding…..107
BIL……20
BPL…….114
Broadband….. 114
Cable facts……29
Cable impedance…..30
Cables…..29
Capacitance Line Charging…..72
Capacitor Application…..97-102
Capacitor application….. 97-102
Capacitor formulas…..33
Capacitor grounding….105
Characteristic Impedance…..113
Charging current….72
Cold load pickup….10
Commercial…..45
Computer Jargon…..63
Conductor burndown…..14
Conductor current rating….29
Conductors…..29
Coordination rules…..17, 73
Cost of Poor PQ…..82
Cost of interruptions….68
Cost of poor power…..82, 112
Cost of Power Interruptions…..68
Cost of sectionalizing equipment…..69
Costs of equipment…..42
Critical Flashover…..112
Current transformers…..24
Current-dangerous levels…..32
Custom power….67
Decibels…..65
Device numbers …..15
Distributed Generation…..31, 51, 111
DSG Info…..51
DSG Requirements…..31
Electricity Rates…..40
EMF…..106
Energy…..111
European Practices….35
Fault calculations….11
Fault Currents…..66
Fault data…..66
Fault Impedance….83
116
Fault levels…..7
Fuse “save vs. blow”…..109
Fuse application….12
Fuse Blow Survey…..109
Fuse Save Survey…..109
Fusing Capacitors….. 13
Fusing Rules…..12
Grounding information….76, 103-109
Grounding, Pros and Cons – 103-109
High Impedance Faults - 8,9,83-86
Humor…..81, 90, 114
Impedance of Faults…..83
Impedances of Cables…..74
Impedances of Lines…..74
Industrial Data…..45
Inrush currents…..9, 66
Instrument transformers…..23
Interruption Cost…..68
Jokes….81, 90, 114
Lightning characteristics…..18
Lightning damage survey…..79
Line Charging…..72
Load Survey…..78
Loading – 57-62
Loading of Equipment……21, 57-60
Loading survey…..78
Low impedance faults…..8
Maintenance…..70
Major Event…..71
Maxwell’s Equations…..49
Modern Physics…..56
Nuclear…..111
Overcurrent Protection Rules…..73-75
Potential transformers…..23
Power Quality…..38, 92
Power Quality Costs…..82, 112
Power Quality Data……38-40
Protective device abbreviations….16
Quarks……56
Rates for Electricity…..40
Ratings, Voltage – 86
Reclosing…..9
Reliability…..53
Reliability “major events”…..71
Reliability Data…..44, 53-55, 77
Rules of Thumb…..28
Safety…..33
Sags…..55
Saturation curves……20
Sectionalizing Equipment Costs…..69
Shield wires…..108
Slant Ratings…..110
Stray Voltage…..88-90
Substation Voltage Regulation…..80
Surface current levels…..9
117
Surge Impedance…..113
Survey Load…..78
Survey on Fuses…..109
Survey, Lightning Damage…..79
Survey, Voltage Regulation…..80
Symmetrical Component Values…..74
Transducer terms….26
Transformer Loading…..21, 57-62
Transformer Saturation…..20
Transformers…..20
Uniformly Distributed Loads…..28
Voltage ratings….86
Voltage Regulation…..80
Voltage regulation survey…..80
Voltage Standards…..86
Wind…..82, 111
118
Jim Burke
EXPERIENCE
Mr. Burke joined InfraSource in 2006 as an
Executive Advisor after 45 years in the industry. He is
recognized throughout the world as an expert in
distribution protection, design, power quality and
reliability.
Mr. Burke began his career in the utility
business with the General Electric Company in 1965
training and taking courses in generation, transmission
and distribution as part of GE's Advanced Utility
Engineering Program. In 1969, he accepted a position
as a field application engineer in Los Angeles
responsible for transmission and distribution system
analyses, as well as generation planning studies for
General Electric's customer utilities in the Southwestern
states. In 1971 he joined GE's Power Distribution
Engineering Operation in New York where he was
responsible for distribution substations, overcurrent and
overvoltage protection, and railroad electrification for
customers all over the world. During this period he was
involved with the development of the MOV "riser pole"
arrester, the Power Vac Switchgear, the static
overcurrent
relay
and
distribution
substation
automation.
In 1978 Mr. Burke accepted a position at
Power Technologies Inc. (PTI) where he continued to
be involved with virtually all distribution engineering
issues. During this period he was responsible for the
EPRI distribution fault study, the development of the
first digital fault recorder, state-of-the-art grounding
studies, and numerous lightning and power quality
monitoring studies. In the area of railroad electrification
he was the project manager of the EPRI manual on
"Railroad Electrification on Utility Systems" as well as
project manager of system studies for the 25 to 60 Hz
conversion of the Northeast Corridor.
Until his
He has authored and co-authored over 130
technical papers (7 prize papers) addressing all these
areas. He has taught numerous courses, all over the
world, for thousands of engineers in virtually all areas of
distribution engineering. He is the author of the book
“Power Distribution Engineering: Fundamentals &
Applications”, now in its 16th printing. He is author of
two revisions to the chapter on Distribution Engineering
in
the
"Standard
MSIA – Union College – 1969 - Thesis:
“Reliability and Availability Analysis of Direct
Buried Distribution Systems”
PSEC – GE (Schenectady) - 1969
PROFESSIONAL ACTIVITIES
IEEE
Past Chair:
•
Distribution Subcommittee
•
Distribution Neutral Grounding
•
Overvoltage Protection of DG’s
•
Switching
and
Overcurrent
Protection
•
Voltage Quality
•
Test Code for Faulted Circuit
Indicators,
•
Testing of Distribution 3 Phase
Submersible Switches
Presently, he is Chair of the Distribution
Awards Group and member of many
other IEEE groups.
first:
50,000 Volt Electrified Railroad
Microprocessor
based
Fault
Recorder
•
Riser Pole Arrester using Metal
Oxide
•
•
Five Wire Distribution System
Digital Simulation of MOV’s for
Distribution Systems
He
also
managed
numerous
projects
including the EPRI Distribution Fault Study, the
successful use of MOV line protection for the 115kV
line and many others in the areas of power quality,
reliability,
overcurrent
protection,
Electrical
BSEE - Univ. of Notre Dame - 1965
engineering. He was project manager for the industries
•
for
EDUCATION
departure in 1997, he was manager of distribution
•
Handbook
Engineering."
ACHIEVEMENTS & HONORS
IEEE Awards
Fellow (1992)
Standards Medallion (1992)
7 Prize Papers
The 1996 Award for “Excellence in Power
Distribution Engineering”
Distinguished Lecturer in PQ & Reliability
2005
Recipient
of
“Herman
Halperin
Transmission and Distribution Award”
distjimb@aol.com
overvoltage
protection, grounding, capacitor application, planning,
etc. In 1997, he joined ABB, consulting in all areas of
distribution as well as software engineering.
119
G.E.
1.
PTI
"An Availability and Reliability Analysis of Direct Buried
and Submersible Underground Distribution Systems,”
IEEE Transactions Conference paper, Underground
Conference Detroit, Mich., June 1970 (co-author: R. H.
Mann)
18.
“Study Defines Surges in Greater Detail”, Electrical
World, June 1, 1980.
19.
“A Study of Distribution Feeder Faults Using a Unique
New Recording Device,” Western Underground Meeting,
Portland, September 1980.
20.
“25 to 60 Hz Conversion of the New Haven Railroad,”
IEEE Transactions Paper presented at IEEE/ASME Joint
Conference, Baltimore, May 1983 (co-authors: D.A.
Douglass and P. Kartluke).
21.
“Characteristics of Faults, Inrush and Cold Load Pickup
Currents in Distribution Systems,” presented to the
Pennsylvania Electric Association, May, 1983.
22.
“Characteristics of Fault Currents on Distribution
Systems”, presented at the IEEE Summer Power Meeting
in July, 1983 IEEE Transactions Paper No. 83 SM 441-3
(co-author: D.J. Lawrence).
2.
“How Do You Serve 3 Phase Loads Underground,”
Electrical World, June 1970 (co-authors: R. H. Mann, and
F. Tabores).
3.
“Railroad Electricification” Electric Forum Magazine,
June 1976 (co-author: J. H. Easley).
4.
“Surge Protection of Underground
Electric Forum Magazine, August 1976.
5.
“An Analysis of Distribution Feeder Faults”, Electric
Forum Magazine, December 1976 (co-author: D. J.
Ward)
6.
“Doubling the Capacity of the Black Mesa and Lake
Powell Railroad,” Electric Forum Magazine, November
1978 (co-author: S. Gilligan).
23.
“Protecting Underground Systems with Zinc Oxide
Arresters,” Electric Forum Magazine”, November 1979
(co author: S. Smith)
“Optimizing Performance of Commercial Frequency
Electrified Railroads,” presented in New York City in
May, 1985 at the IEEE Transportation Division Meeting.
24.
“Compensation Techniques to Increase Electrified
Railroad Performance,” IEEE Transactions, presented at
the IEEE/ASME Joint Conference, Norfolk, VA, April,
1986.
25.
“Factors Affecting the Quality of Utility Power, APPA
Conference, May 28, 1986, Colorado Springs, CO.
7.
8.
Transformers”,
“A Comparison of Static and Electromechanical Time
Overcurrent Relay Characteristics, Application and
Testing,” Philadelphia Electric Association, June 1975
(co-authors: R. F. Koch and L. J. Powell).
9.
“Distribution Substation Practices”, (two
presented at Quito, Ecuador, June 1975.
volumes),
26.
10.
“Distribution System Feeder Overcurrent Protection”,
GET-6450, June 1977. Also presented as a seminar in the
US and Latin America.
“Fault Impedance Considerations for System Protection”,
presented at the T&D Conference, Anaheim, CA,
September 1986
27.
“Cost/Benefit Analysis of Distribution Automation,”
presented at the American Power Conference, Chicago,
IL, April 1987
28.
“The Effect of Higher Distribution Voltages on System
Reliability,” Panel Session, IEEE Summer Power
Meeting, San Francisco, CA, 1987.
11.
“Surge Protection of Underground Systems up to 34.5
kV,” presented at Underground Conference in Atlantic
City, NJ. September 1976 (co-authors: N.R. Schultz, E.G.
Sakshaug and N. M. Neagle).
12.
“Railroad Electricification from a Utility Viewpoint.”
Philadelphia Electric Association, May 1977.
29.
“Are Distribution Overvoltage Margins Inadequate?,”
Western Underground Meeting, January 1988.
13.
“Increasing the Power System Capacity of the 50 kV
Black Mesa and Lake Powell Railroad Through
Harmonic Filtering and Series Compensation,” IEEE
Transactions paper presented at 1978 IEEE Summer
Power Meeting, Paper No. F79 284-1 (co-authors: A.P.
Engel, S.R. Gilligan and N.A. Mincer).
30.
“Utility Operation and Its Effect on Power Quality,”
IEEE Winter Power Meeting Panel Session, February
1988.
31.
“Higher Distribution Voltages… Not Always a Panacea,”
Electrical World, April 1988.
32.
“Distribution Systems, Reliability, Availability and
Maintainability,” IMEA Summer Conference for Utilities,
June 1988, (co-author: R.J. Ringlee).
33.
“Why Underground Equipment is
Overvoltage,” Electrical World, July 1988.
34.
“Cost/Benefit Analysis of Distribution Automation:
Evaluation and Methodology,” T&D Automation
Conference Exposition, St. Louis, MO, September 1988
(Part II).
35.
“Improper Use Can Result In Arrester Failure,” Electrical
World, December 1988.
36.
“Metal Oxide Arresters on Distribution Systems:
Fundamental Considerations," IEEE Transactions,
presented at the IEEE PES Winter Meeting, New York,
NY, February 1989, (Co-authors: E.G. Sakshaug and J.
Kresge). [1991 SPD Prize Paper Award].
37.
“The Effect of Switching Surges on 34.5 kV System Design
and Equipment,” IEEE Transactions, presented at the
IEEE/PES T&D Conference and Exposition, New
Orleans, LA, April 1989, (Co-authors: J. W. Feltes and
L.A. Shankland).
14.
“An Analysis of VEPCO’s 34.5 kV Distribution Feeder
Faults, IEEE Transactions paper F78 217-2, presented at
PES Meeting, New York, January 1978, also Electrical
World Publication, Pennsylvania Electric Association,
University of Texas, and Georgia Tech Relay Conference
(co-authors: L. Johnston, D. J. Ward and N. B. Tweed).
15.
“Type NLR & NSR Reclosing Relays – An Analysis of
VEPCO’s 34.5 kV Distribution Feeder Faults as Related
to Through Fault Failures of Substation Transformers,”
General Electric Publication GER-3063, March, 1978 (coauthors: L. Johnston, D. J. Ward, and N. B. Tweed).
16.
“The Application of Gapless Arresters on Underground
Distribution Systems,” IEEE Transactions Paper No. F79
636-2, Vancouver, British Columbia, July 1979, T&D
Conference and Exposition (co-author: S. Smith and E.G.
Sakshaug).
17.
Guide for “Surge Protection of Cable-Connected
Equipment on Higher Voltage Distribution Systems,”
(SPD Working Group, IEEE Transactions paper
presented at the 1979 T&D Conference and Exposition.
Failing
on
120
38.
“The Application of Surge Arresters on Distribution
Systems”, Power Distribution Conference, Austin, TX,
October 1989.
39.
“Application of MOV and Gapped Arresters on Non
Effectively Grounded Distribution Systems, “IEEE
Transactions, Paper No. 90 WM 136-2 PWRD, presented
at the IEEE PES Winter Meeting, Atlanta, A, February
4-8, 1990, (Co-authors: V. Varneckas, E. Chebli, and G.
Hoskey).
40.
41.
42.
“Power Quality – Two Different Perspectives,” IEEE
Transactions, Paper No. 90 WM 053-9 PWRD, presented
at the IEEE PES Winter Meeting, Atlanta, A, February 48, 1990, (Co-authors: D.J. Ward and D.C. Griffith). This
paper received the IEEE 1991 Working Group Prize
Paper Award.
“Power Quality Measurements on the Niagara Mohawk
Power System,” presented at the 1990 Chattanooga IEEE
Section’s Power Quality Seminar, April 18, 1990, (Coauthors: P.P. Barker, R.T. Mancao, and C. Burns).
“Constraints on Mitigating Magnetic fields on
Distribution Systems,” Panel Session, IEEE PES Summer
Power Meeting, Minneapolis, MN, July 16-20, 1990.
56.
“Power Quality Monitoring of a Distribution System,”
presented at the IEEE Summer Power Meeting,
Vancouver, British Columbia, July 19-23, 1993, (coauthors: P.O. Barker, R. T. Mancao, T. A. Short, C. A.
Warren, C.A. Burns, and J.J. Siewierski).
57.
“5 Wire Distribution System Design,” EPRI White Paper,
August 20, 1993, (co-authors: P.B. Steciuk, D.V. Weiler,
and W.S. Sears).
58.
“Characteristics of Distribution Systems That May Affect
Faulted Circuited Indicators,” Panel Session, 1994 IEEE
T&D Conference and Exposition, Chicago, IL, April 1015, 1994.
59.
“Constraints on Managing Magnetic Fields on
Distribution Systems,” presented at the 1994 IEEE T&D
Conference and Exposition, Chicago, IL, April 10-15,
1994, (co-author: P.B. Steciuk).
60.
“The Impact of Railroad Electrification on Utility System
Power Quality,” presented at the Mass Transit System ’94
Conference, Dallas, TX, September 1994, (co-author: P.B.
Steciuk).
61.
Power Distribution Engineering:
Fundamentals and
Applications, Marcel Dekker, Inc., 1994.
62.
“Distribution Modeling for Lightning Protection for
Overhead Lines,” presented at the EEI, T&D Committee
Meeting, Salt Lake City, UT, October 20, 1994 (coauthors: T.A. Short and P. Garcia).
63.
“Hard to Find Information About Distribution Systems,”
presented at PTI’s Power Distribution Course,
Sacramento, CA, March 1995.
64.
“Sensitivity and Selectivity of Overcurrent Protective
Devices on Distribution Systems (or, Now You See
It…Now You Don’t), Panel Session, 1995 IEEE Summer
Power Meeting, Portland, OR July 23-28, 1995.
43.
“The Effect of Lightning on the Utility Distribution
System”, presented at the 12th Annual Electrical
Overstress/Electrostatic Discharge Symposium, Orlando,
FL September 11, 1990.
44.
“Power Quality Measurements on the Niagara Mohawk
Power System… Revisited,” presented at the
PCIM/Power Quality ’90 Seminar, Philadelphia, PA,
October 21-26, 1990, (co-authors: P.P. Barker, R. T.
Mancao, C. W. Burns, and J.J. Siewierski).
45.
“Protecting Underground Distribution” Electric Light &
Power, April 1991, (co-author: P.P. Barker).
46.
“Utility Distribution System Design and Fault
Characteristics,” Panel Session, 1991 IEEE T&D
Conference and Exposition, Dallas, TX, Sept. 23-27, 1991.
65.
“Tutorial on Lightning and Overvoltage Protection,”
presented at the 1995 Power Distribution Conference,
Austin, TX October 24, 1995.
47.
“Distribution Surge Arrester Application Guide,” Panel
Session, 1991 IEEE T&D Conference and Exposition,
Dallas, TX, Sept. 23-27, 1991.
66.
48.
“Controlling Magnetic Fields in the Distribution System,”
Transmission and Distribution, December 1991, pp. 24-27.
“Analysis of Voltage Sag Assessment of Frequency of
Occurrence and Impacts of Mitigations,” presented at
Conference on Electrical Distribution, January 9-10,
1996, Kuala Lumpur, Malaysia, (co-authors: S. Yusof,
J.R. Willis, P.B. Steciuk, T.M. Ariff and M. Taib).
49.
“The Effect of Distribution System Grounding on MOV
Selection,” IEEE Transactions, presented at the IEEE PES
Winter Power Meeting, New York, NY January 26-30,
1992, (co-authors: R. T. Mancao and A. Myers).
67.
“Lightning Effects Studied – The FPL Program,”
Transmission & Distribution World, May 1996, Vol. 48,
No. 5, (co-authors: P. Garcia and T. A. Short).
68.
50.
“Why Higher MOV Ratings May Be Necessary,”
Electrical World, February 1992, (co-authors: R. T.
Mancao and A. Myers).
51.
Standard Handbook for Electrical Engineers, “Chapter
18”, 13th Edition, Fink & Beaty, 1992.
“Application of Surge Arresters to a 115-kV Circuit,”
presented at the 1996 Transmission and Distribution
Conference & Exposition, Los Angeles, CA, September
16-20, 1996, (co-authors: C.A. Warren, T. A. Short, C. W.
Burns, J.R. Godlewski, F. Graydon, H. Morosini).
69.
“Fault Currents on Distribution Systems,” panel session
paper presented at 1996 Transmission and Distribution
Conference and Exposition, Los Angeles, CA, September
16-20, 1996.
70.
“Philosophies of Distribution System Overcurrent
Protection,”
Training
Session
on
“Distribution
Overcurrent Protection and Policies,” 1996 Transmission
and Distribution Conference & Exposition, Los Angeles,
CA, September 16-20, 1996.
71.
“A Summary of the Panel Session: Application of High
Impedance Fault Detectors: Held at the 1995 IEEE PES
Summer Meeting,” presented at 1996 Summer Power
Meeting, Denver, Colorado, July 28-August 2, 1996, (coauthors G.E. Baker, J.T. Tengdin, B. D. Russell, R. H.
Jones, T. E. Wiedman).
72.
“Philosophies of Overcurrent Protection for a Five-Wire
Distribution System,” panel session paper presented at
52.
“Philosophies of Overcurrent Protection”, Panel Session,
1992 Summer Power Meeting, Seattle WA, July 13-17,
1992.
53.
“The Effect of TOV on Gapped and Gapless MOVs,”
presented to SPD Committee meeting, September 21-25,
1992, Kansas City, MO.
54.
“IEEE Guide for the Application of Neutral Grounding in
Electric Utility Systems, Part IV – Distribution,”
published by IEEE, 1992, (prepared by the Working
Group on the Neutral Grounding of Distribution Systems
of the IEEE Surge-Protective Devices Committee, J.J.
Burke, Chairman).
55.
“Application of MOV’s in the Distribution Environment,”
presented at the IEEE Transactions Power Delivery, Vol.
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1996 Transmission and Distribution Conference and
Exposition, Los Angeles, CA, September 16-20, 1996 (coauthor P.B. Steciuk).
95.
“Distribution Impacts of Distributed Generation –
Revisited,” panel session at DistribuTECH 2000, Miami,
Florida.
73.
“Utility Characteristics Affecting Sensitive Industrial
Loads,” Power Quality Assurance Magazine, Nov./Dec.
1996.
96.
“
Maintaining
Reliability
In
a
De-regulated
Environment,” T&D World 2000, April 26-28, Cincinnati,
Ohio.
74.
“Fundamentals of Economics of Distribution Systems,”
IEEE PES Winter Power Meeting, New York City,
February 1997.
97.
“Using Outage Data to Improve Reliability” IEEE
Computer Applications in Power” magazine, April 2000,
(Volume 13, Number 2)
98.
“Techniques and Costs to Improve Power Quality,” the
EEI Power Quality Working Group, New Orleans,
March, 1997.
“Utilities Take on Challenges or Improved Reliability and
Power Quality” Electric Light and Power Magazine,
Vol.78, Issue6, June 2000
99.
“Determining the Optimum Level of Reliability” Infocast
Reliability Seminar, September 27, 2000, Chicago
76.
“Trends in Distribution Reliability,” University of Texas
Power Distribution Conference, October 1997.
100.
“Hard-to-Find information on Distribution Systems, Part
II - The New Millennium, November 2000.
77.
“System and Application Considerations for Power
Quality Equipment in Distribution,” EEI Distribution
Committee Meeting, Baltimore, MD, October 1997.
101.
“Determining the Optimum Level of Reliability –
Revisited” IEEE T&D Conference 2001, Atlanta, Ga.
78.
“Hard to Find Information about Distribution Systems –
Revisited” – June 1998, ABB.
102.
“Trends Creating Reliability Concerns or 10 Steps to
Becoming a Less Reliable Utility” IEEE T&D Conference
2001, Atlanta, Ga.
79.
"Power Quality at Champion Paper - The Myth and the
Reality", IEEE Transaction, Paper #PE-340-PWRD-0
-06-1998, (Co-Authors: C.A. Warren, T.A. Short, H.
Morosini, C.W. Burns, J. Storms)
103.
“Distribution Systems Neutral Grounding” (co-author M.
Marshall) IEEE T&D Conference 2001, Atlanta, Ga.
104.
80.
"Delivering Different Levels of Service Reliability Over a
Common Distribution System" T + D World Conference,
Arlington VA, September 29 1998.
“Distribution Automation” A compilation prepared for
the Intensive Distribution Planning and Engineering
Workshop, September 24-28, 2001 Raleigh, NC.
105.
81.
"European vs. U.S. Distribution System Design," 1999
WPM, N.Y.C. (co-author S. Benchluch)
“How Important is Good Grounding on Utility
Distribution Systems? PQ Magazine - April 02, 2002 –
(co-author M. Marshall)
82.
“Managing the Risk of Performance Based Rates,” 1999,
(co-author R. Brown). IEEE Transactions, May 2000,
volume 15, pages 893-898.
106.
“Status of Distribution Reliability and Power Quality in
the United States” (co-author E. Neumann), presented at
the ENSC 2002 in San Antonio.
83.
“Application of Reclosers on Future Distribution
Systems,” (co-author R. Smith) – BSS Meeting in
Greensboro N.C., Jan. 1999.
107.
“Nashville Electric Service Uses an Integrated Approach
to System Planning”, T&D World Magazine, Dec 2002 –
(co-authors – Leech, Neumann, et al).
84.
“Serving Rural Loads from Three Phase and Single Phase
Systems,” (co- authors S. Benchluch, A. Hanson, H. L.
Willis, H. Nguyen, P. Jensen).
108.
“ A Standardized Approach to the Application of Line
Reclosers” Distributec 2003 – (co authors: C Williams, T.
Fahey, R. Goodin, K Josupait).
85.
Standard Handbook for Electrical Engineers, 14th edition,
McGraw Hill, 1999.
109.
“Considerations When Applying Capacitors on
Distribution Systems” T&D Conference 2003, Dallas,
Texas.
110.
“The Application of Capacitors on Rural Distribution
Systems” – Rural Electric Power Conf. – May 2004 –
Scottsdale, Arizona.
ABB
75.
Synergetic Design
86.
“Hard to Find Information About Distribution Systems,”
Third Revision, June 1999.
87.
“Trends in Distribution Reliability in the United States,”
CIRED, Nice, France, June 1999.
88.
“Reclosers Improve Power Quality on Future Distribution
Systems,” T & D Conference, New Orleans, 1999
111.
89.
“Distribution Impacts of Distributed Resources,” SPM –
1999, Alberta, Canada.
“Using OMS Data to Improve Equipment Reliability
Modeling” – Panel Session IEEE/PES – Denver – 2004
112.
“Requirements for Reclosers on Future Distribution
Systems,” Power Quality Assurance Magazine, July 1999
“Sectionalizing Distribution Systems in the 21st Century”,
NRECA/CRN publication August 2004
113.
91.
“Fault Impedance…How Much?” – T & D World
Magazine.
“ Hard-to- Find Information on Distribution Systems III”,
May 2005
114.
92.
“A Systematic and Cost Effective Method to Improve
Distribution System Reliability,” (co-authors H. Nguyen,
R. Brown) IEEE SPM - 1999, Edmonton, Alberta.
“ Stray Voltage Issues” (co-author K. Dosier) presented at
T&D Conference and Expo – New Orleans, October 2005
115.
“Hard-to-Find Information on Distribtuion Systems IV”,
July 2005
116.
“Sectionalizing Distribution Systems in the 21st Century:
One Engineers Opinion”, CRN project 03-17
117.
“Fault Impedance (40 ohms is a fallacy)”, REPC meeting,
Albuquerque, April 2006
90.
93.
“Rural Distribution System Design Comparison,” (coauthors: H. Nguyen, S. Benchluch)- IEEE, WPM 2000,
Singapore.
94.
“Improving Distribution Reliability Using Outage
Management Data,” (co-author: J. Meyers) presented at
DistribuTECH 2000, Miami, Florida.
122
118.
Hard to Find Information About Distribution Systems V –
January 2006
119.
“Point of View…40 ohms” – T&D World Magazine –
2006
120.
“Stray Voltage Issues are Back” (co-author K. Dosier) –
T&D World Magazine, 2006
InfraSource Inc.
121.
“The Confusion Surrounding Stray Voltage” – 2007
REPC Meeting in Rapid City, South Dakota
122.
“Does Good Grounding Improve Distribution System
Performance?” – T&D World Magazine – July 2007
123.
“Hard to Find Information About Distribution Systems –
Volumes 1 and 2 - Updated, August 2007
Quanta Technology
124.
“Stray Voltage: Two Different Perspectives” (co-author
C. Untiedt) – IEEE REPC 2008, April 2008, Charleston,
S.C.
125.
“The Confusion Surrounding Stray Voltage” – IAS
Magazine May/June 2008
126.
“10 More Ways to Become a Third World Utility” –
Independent publication – April 2008
127.
“Summary of Distributed Resources Impact on Power
Delivery Systems” IEEE transactions TPWRD-003422007, published in Power Delivery, Vol.23, No.3, July
2008. (co-authors R. Walling, R. Saint, R. Dugan, L.
Kopovic)
128.
“Impact of Transmission Lines on Stray Voltage” – (coauthors N. Abed, S. Saleem) – IEEE SPM 2010
129.
“The Impact of a “Fuse Blow” Scheme on Distribution
System Reliability and Power Quality” (co-author C
O’Meally) – IEEE REPC 2009, April 2009. Fort Collins,
Colorado.
130.
“Stray Voltage: Two Different Perspectives” (co-author
C. Untiedt) – IAS Magazine publication – MayJune 2009
131.
“Calculating Line Losses for Feeders with Varying
Conductor Sizes” – (co-author T. Hong) – 2010 IEEE
T&D Conference
132.
“Hard to Find Information on Distribution Systems –
Volume 2 – Update – April 21, 2009
133.
“Improving the Reliability of Power Distribution Systems
Through Single-Phase Tripping” (co-authors J. Romero
Aguero, J. Wang) – 2010 IEEE T&D Conference
134.
“The Impact of a “Fuse Blow” Scheme on Distribution
System Reliability and Power Quality” (co-author C
O’Meally) – IAS Magazine 2010
123