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HARD TO FIND INFORMATION ABOUT DISTRIBUTION SYSTEMS (Contains Hard to Find I, II, III, IV, and V with index)

Volume 1

Jim Burke [email protected] 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



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.

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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



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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

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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

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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.

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• •

• •







• • •

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

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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

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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: • • • • • • • • • • • • • •

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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.

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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

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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

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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.

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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

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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 – [email protected], [email protected], [email protected] 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

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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.

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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

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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

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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

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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

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* 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”

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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

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• • • • • • • • • •

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

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• 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

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• •

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

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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

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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.

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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)

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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.

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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

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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

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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.

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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

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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

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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

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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.

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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.

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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

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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.

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-

-

-

-

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.

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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

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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

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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

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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,

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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)

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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.

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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

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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

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• • •

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

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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 [email protected]

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” [email protected]

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. 9, No. 1, Pages 293-305 – Jan. ’94 .

121

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

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