Distribution system and power quality

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ECE 5750 Distribution System & Power Quality Part 7: Voltage sags & momentary interruptions

Instructor: Dr. Ha Le Department of Electrical and Computer Engineering

California State Polytechnic University, Pomona

What will be presented? 1) Characteristics and sources of voltage sags and

interruptions

2) Equipment sensitivity

3) Utility fault-clearing practices

4) Methods of reducing voltage sags and momentary interruptions

Reading: PQ textbook, Chapter 3

Short-duration voltage variations

Duration:  Instantaneous ( 0.5 – 30 cycles )  Momentary ( 0.5 – 3 seconds )  Temporary ( 3 – 60 seconds )

Voltage magnitude:  Interruption ( < 0.1 pu )  Sag ( 0.1 – 0.9 pu )  Swell ( 1.1 – 1.4 pu )

Voltage Sag

Voltage Interruption

Voltage Swell

What is a voltage sag? A voltage sag is a short duration decrease in the rms ac voltage to lie between 0.1 and 0.9 pu of the nominal voltage at the power frequency.

Nominal voltage 7.2 kV = 1 pu

2.15 kV = 0.30 pu

5.11 kV = 0.70 pu

Interruptions A decrease in the rms ac voltage that causes it to lie in the range of zero and 0.1 pu is called an interruption.

May 04, 1994 at 12:46:59 PQNode Local3764 Phase C Voltage RMS Variation

Trigger

0 2 4 6 8 10 12 0

20 40 60 80

100 120

Time (Seconds)

% Vo

lts

0 25 50 75 100 125 150 175 200 -100

-75 -50 -25

0 25 50 75

100

Time (mSeconds)

% Vo

lts

Duration 11.22 Sec

Min 0.096 Ave 6.568 Max 98.19 Ref Cycle

13266

BMI/Electrotek

Instantaneous sag October 29, 1994 at 17:00:04 PQNode Local9906

Phase A Voltage RMS Variation

0 0.1 0.2 0.3 0.4 0.5 0

20 40 60 80

100 120

Time (Seconds)

% Vo

lts

0 25 50 75 100 125 150 175 200 -150 -100

-50 0

50 100 150

Time (mSeconds)

% Vo

lts

Duration 0.150 Sec

Min 15.01 Ave 60.42 Max 99.92 Ref Cycle

64047

BMI/Electrotek

Instantaneous (0.5 – 30 cycles)

Instantaneous swell October 29, 1994 at 17:00:04 PQNode Local9906

Phase B Voltage RMS Variation

Trigger

0 0.1 0.2 0.3 0.4 0.5 85 90 95

100 105 110 115 120

Time (Seconds)

% Vo

lts

0 25 50 75 100 125 150 175 200 -150 -100

-50 0

50 100 150

Time (mSeconds)

% Vo

lts

Duration 0.133 Sec

Min 102.2 Ave 108.9 Max 116.2 Ref Cycle

64047

BMI/Electrotek

Instantaneous (0.5 – 30 cycles)

Momentary sag May 07, 1994 at 07:20:22 PQNode Local9553

Phase C Voltage RMS Variation

0 0.25 0.5 0.75 1 1.25 1.5 1.75 20 40 60 80

100 120

Time (Seconds)

% Vo

lts

0 25 50 75 100 125 150 175 200 -150 -100

-50 0

50 100

Time (mSeconds)

% Vo

lts

Duration 1.300 Sec

Min 24.23 Ave 49.20 Max 100.7 Ref Cycle

35316

BMI/Electrotek

Momentary (0.5 – 3 seconds)

Momentary swell May 07, 1994 at 07:20:22 PQNode Local9553

Phase A Voltage RMS Variation

0 0.25 0.5 0.75 1 1.25 1.5 1.75 90 95

100 105 110 115

Time (Seconds)

% Vo

lts

0 25 50 75 100 125 150 175 200 -150 -100

-50 0

50 100 150

Time (mSeconds)

% Vo

lts

Duration 0.950 Sec

Min 99.58 Ave 105.9 Max 110.3 Ref Cycle

35316

BMI/Electrotek

Momentary (0.5 – 3 seconds)

Temporary sag February 26, 1995 at 09:06:28 PQNode Local5818

Phase B-C Voltage RMS Variation

Trigger

0 1 2 3 4 5 6 50 60 70 80 90

100 110 120

Time (Seconds)

% Vo

lts

0 25 50 75 100 125 150 175 200 -100

-75 -50 -25

0 25 50 75

100

Time (mSeconds)

% Vo

lts

Duration 5.817 Sec

Min 51.71 Ave 67.81 Max 99.77 Ref Cycle

35271

BMI/Electrotek

Temporary ( 3 – 60 seconds )

Temporary swell February 26, 1995 at 09:08:44 PQNode Local9431

Phase C-A Voltage RMS Variation

Trigger

0 0.5 1 1.5 2 2.5 3 3.5 4 90 95

100 105 110 115 120 125 130

Time (Seconds)

% Vo

lts

0 25 50 75 100 125 150 175 200 -150 -100

-50 0

50 100 150

Time (mSeconds)

% Vo

lts

Duration 3.717 Sec

Min 98.61 Ave 124.2 Max 126.7 Ref Cycle

30372

BMI/Electrotek

Temporary (3 – 60 seconds )

Characteristics of voltage sags Voltage sags can be described by:

1) Magnitude

2) Duration

3) Phase angle shifts

4) Missing voltage

5) Other characteristics:

 Point-in-wave characteristics

 Maximum unbalance ratio

Voltage sag magnitudes (1)  Voltage sag can be detected by power quality monitors.

 Instantaneous voltage and current waveforms, RMS variations, and other quantities can be recorded by sampling.

Voltage sag magnitudes (2) RMS voltage is computed by

 nv N

dttv N

V N

rms  

 1

2 1)( 1

Reporting voltage sags  Nominal voltage = 12.47 kV (3-phase) = 7.2 kV (1-phase)

 Lowest retain voltage is 2.15 kV = 0.3 pu

 How to report a sag?

Option 1: Report it in terms of magnitude: “A sag down to 0.3 pu.”

Option 2: Report it in terms of missing voltage: “A 70% sag.”

Voltage sag duration (1)  Tripping of equipment determined both by magnitude and duration of sag.

 Short duration sags (e.g. 20% sag for 0.1 cycle) typically do not affect equipment.

 Sag duration can be computed by determining time instants corresponding to rms voltage magnitude falling below 0.9 pu (t1) and subsequent recovery to above 0.9 pu (t2)

Voltage sag duration (2)  There are situations where a sag may never recovers to above 0.9 pu

(below figure).

 The duration in such cases is reported in qualitative manner:

a) t = 0.1833 – 0.018 = 0.1653 s

b) “Sag is longer than 0.1653 s or longer than 10 cycles”

0.1833

Phase angle shift (1)  Some equipment are sensitive to phase shifts in addition to magnitude

and duration (E.g. phase controlled rectifiers).

 An ideal waveform is synthesized and phase angles of fundamental frequency of measured and synthesized waveforms are computed.

 Phase shift is given by sm  

Phase shift = 31.9 deg.

Phase angle shift (2)

 Phase shift can also be estimated by determining the time between two adjacent voltage zero crossing points.

 The corresponding phase angle is calculated as follows:

msd ttt  21600360  dd tT t 

Phase shift = 30.2 deg.

Missing voltage  It represents the instantaneous difference between the voltage that would

have been present and actual measured voltage during sag condition.

 It can be computed by: Synthesized voltage – Measured sag voltage

][][][ nVnVnV ms 

Other characteristics  Other characteristics used to describe voltage sag include

point-in-wave and maximum unbalance ratio.

 Point-in-wave characteristics provides the fundamental frequency’s phase angle at the point of interest (point of initiation and recovery of sag condition) in the waveform.

 Maximum unbalance ratio describes maximum deviation of RMS value over its average value during the sag condition i.e.

averageVVV /)( minmax 

Equipment sensitivity  Sensitivity of the load equipment varies depending on

specific load type, control settings and related applications. Hence it is difficult to predict which characteristics of voltage sag will cause equipment malfunction.

 Voltage sag magnitude and duration are used to determine equipment sensitivity.

 Magnitude-duration plots are used to quantify equipment susceptibility to voltage sags.

 Two frequently employed plots are CBEMA curve (Computer Business Equipment Manufacturers Association) and ITI curves (Information Technology Industry council).

CBEMA curves  CBEMA curve was used till 1995 when it was superseded by ITI curves.

 Describes tolerance of mainframe computer to magnitude and duration of voltage variations on the power system.

ITI curve

Equipment ride-through capability (1)  The curve specifies the minimum voltage magnitude a piece of

equipment can withstand or tolerate without malfunction.

 Also known as equipment voltage sag immunity or susceptibility limit.

Equipment ride-through capability (2)

Equipment ride-through capability (3)  Adjustable speed drives (ASD) are very sensitive to voltage sag.

 Motor contactors have a higher tolerance to voltage sags. It trips for voltage sags below 0.5pu and lasting for more than 1 cycle.

Sources of voltage sag & interruption (1)

Voltage sags and interruptions are mainly caused by:

 Short circuit conditions or faults

 Operation of protective devices such as recloser may give instantaneous and momentary interruptions.

 Starting of large industry motors (inrush currents)

Sources of voltage sag & interruption (2) 1) Breakers A & B

operate to clear fault FLT-3.

2) As two lines supply distribution station, customers experience only a sag due to FLT-3.

3) Fault FLT-2 will be cleared by lateral fuse.

4) For a fault at FLT-1, customers of LOAD will experience voltage sags and interruptions.

5) If fault is temporary, interruptions are momentary.

Utility fault-clearing practices  Primary objective of utility system fault-clearing process,

besides personnel safety, is to limit damage to the distribution system.

 Two fundamental types of faults on power system are:

1) Transient or temporary faults: No permanent damage is caused to system insulation and voltage can be restored after fault arc is extinguished.

2) Permanent faults: Faults caused by physical damage to the element of the insulation system. A line crew must be dispatched to clear the fault and restore power.

Temporary faults (1)

-2500

2500

-25000

25000

1 2 3 4 5 6 7 8 9 10 11

IA IB

IC V

A B

V B

C V

C A

Cycles

IA IB IC VAB VBC VCA

Temporary faults (2)

-2500

2500

5000

-25000

25000

1 2 3 4 5 6 7 8 9 10 11

IA IB

IC V

A B

V B

C V

C A

Cycles

IA IB IC VAB VBC VCA

How to deal with sags & interruptions?

We consider overcurrent protection of distribution circuits

& power quality impact on customers

OC protection of distribution circuits  When short-circuit conditions exist on the power system

circuit, overcurrent (OC) protective devices must operate to interrupt the short-circuit currents.

 The devices are installed in series along the feeders or laterals and coordinated so that only one device clears the fault.

 In DS, overcurrent protective devices include:

1) Fuses

2) Automatic reclosers

3) Sectionalizers

4) Feeder circuit breakers

A typical distribution circuit & its equipment

NC = normally closed NO = normally open

A distribution 3-phase lateral

Current interruption devices  Circuit breakers (IEEE Std. 100):

a) A switching device capable of making, carrying, and breaking currents under normal circuit conditions and also making, carrying for a specified time, and breaking currents under specified abnormal conditions such as those of short circuit.

b) A circuit breakers can detect and interrupt a fault current upon a trip order from its relay.

 Disconnect switches: Same as circuit breakers except that they cannot detect and interrupt fault currents.

 Fuses: An overcurrent protective device with a circuit- opening fusible part that is heated and severed by the passage of the overcurrent through it.

Process of AC current interruption (1)

1) On a trip order, the breaker contact begins to open and move away from the line-side terminal. An electric arc forms between the contact and the line-side terminal.

2) Even though the contact is physically apart from the line-side terminal, but because of the presence of the arc, current is still flowing.

3) Gas, liquid, or vacuum are used to help extinguish the arc. Successful current interruption hinges upon the ability to extinguish the arc in the shortest possible time and to prevent it from re-ignition.

Process of AC current interruption (2) 4) As the instantaneous current approaches zero, the current

rapidly loses conductivity.

5) Within a few microseconds after current zero – if the interruption is successful – the arc voltage increase to the system voltage and current will remain zero.

6) The voltage potential builds up across the contact and the line-side terminal. There are two voltage potentials, one on each contact side: source-side and line-side.

7) The potential difference is the transient recovery voltage (TRV). The breaker must withstand the TRV. If not, a breaker restrike occurs, arc reignites, current flows again. Interruption fails. Try again on the next zero current until successful or breaker melts.

OC protection devices (1) Sectionalizer

1) Ease coordination of overcurrent protective devices

2) Does not have a relay and does not interrupt short- circuit current

3) Used in conjunction with a recloser by counting the number of recloser operations

4) When count reaches a predetermined number, the sectionalizer trips and isolates the section

Feeder circuit breakers

1) Breaker operation controlled by an external overcurrent relay

OC protection devices (2)

Fuses

 Inexpensive and maintenance free.

 Fuses detect overcurrent by melting the fuse element.

 Purpose is to operate on permanent faults and isolate the faulty section from the healthy portion of the feeder.

 There are two types of fuses generally used in power system:

1) Expulsion fuses

2) Current limiting fuses

Expulsion fuses (1)  Consists of fuse link housed in vented

arc-confining tube.

 When heavy current flows, the fuse element melts and an arc is struck.

 This creates high pressure gases that expels arc plasma. The arc cools down and will not reignite after current zero.

 Actual time taken to interrupt the current determines duration of the voltage sag.

 Less expensive as compared to current-limiting fuses.

Fig. 3.14: A typical utility fuse cutout with an expulsion fuse. A pin-shape object is a fuse link.

Expulsion fuses (2)

 A vented fuse in which the expulsion effect of the gases produced by the internal arcing, either alone or aided by other mechanisms, results in current interruptions.

 They are NOT current limiting, but duration limiting. They a) Interrupt at current zero

b) Electro-mechanical and Vented

 Rating: e.g. 5.2 kV, continuous current rating 100 A, interrupting symmetrical current 1.6 kA.

Expulsion fuse characteristics (1)  Possesses inverse time-

current characteristics

 Two curves are present namely minimum melting time and maximum clearing time curve.

 When fuse melts the fault current and its associated time will lie between the two curves.

 Minimum melting time = Minimum time required for current to sever the fusible element.

 Maximum melting time = Longest time to melt

Expulsion fuse characteristics (2)  Relative speed of fuse

operation is measured in terms of melting speed ratio

 According to ANSI Std. C37-40-2003, the speed ratio is the ratio of magnitude of melting current at 0.1s to that at 300s for fuse rated up to 100A or 600s for above 100A.

 A fuse with lower speed ratio is faster than that with higher ratio.

Current limiting fuses (1)  Used in cases when the fault current is very

high (in excess of 2000A – 3000A)

 The fuse element is a thin ribbon encased in a sealed insulating tube filled with special sand.

 Fuse element melts in many places simultaneously and the energy in the arc is dissipated in a closed environment

 The arc is quenched very quickly sometimes even before natural current zero. Hence voltage sag durations are very small.

Fig. 3.17 Various types of current-limiting fuses used in utility applications (Courtesy of Cooper Power Systems)

Current limiting fuses (2)

Fuse link construction

No fault condition: Fuse is part of the lateral. Can carry current at the continuous current rating. Fault condition:

 Fuse element heats to the melting point (in t seconds), and begins to break apart. An arc forms at the severed part. Fault current flows through the fuse element and arc. Melting continues, and vaporized the remaining element. Gas forms.

 Fault current passes the zero crossing, at this time no current in the element and arc. Gas may overwhelm/extinguish the arc. If not – arc will reignite and fault current establish.

 More gas, since fuse element burns more, arc is more far apart. Next or a few more current zero, gas extinguishes the arc. High pressure gas expels the fuse holder. Time to do this is called maximum clearing time.

Reclosers  Special circuit breakers used in

DS to perform fault interruption and reclosing functions.

 Generally used on overhead lines as faults mostly are of temporary nature; Generally pole-mounted.

 Majority of the faults will be cleared in the first operation.

 Oil-insulated designs are common. SF6 and encapsulated dielectric type reclosers are also used.

Fig. 1.8 A pole mounted remote- controlled 3-phase recloser

Oil-insulated reclosers

1-phase recloser 3-phase recloser

Recloser time-current characteristics

 Two time-current characteristics: fast and delayed curves. Can switch between the two curves depending on the need. It can interrupt currents in a time as short as 1.5 cycles, thereby limiting the sag duration.

 Fast tripping is used typically for fuse saving applications.

 Delayed tripping allows the downline fuses to clear the fault.

Fig. 3.22 Time-current characteristics of a recloser: fast and delayed curves

Operation of a recloser

Two most common sequences in use on 4-shot reclosers (midline or tap):

 One fast, three- delayed

 Two fast, two delayed

Typical interruptions:

 3-6 cycles but 1.5 cycle is also common.

1 FAST, 3 DELAYED

2 FAST, 2 DELAYED

RECLOSE INTERVAL TYPICALLY 1 - 2 SEC *

* FIRST RECLOSE INTERVAL MAY BE "INSTANTANEOUS" OR 12-30 CYCLES

Overcurrent relays (1) I’ is the input to the overcurrent relay operating coil. Ip is relay pickup current

Instantaneous overcurrent relays respond to the magnitude of their input current.

I’ > Ip : Relay contacts close “instantaneously” to energize the circuit breaker trip coil.

I’ < Ip : Relay contacts remain open, blocking the coil.

Lower figure: Instantaneous overcurrent relay block and trip regions

Overcurrent relays (2) Time-delay overcurrent relays also respond to the magnitude of their input current, but with an intentional time delay. Characteristics:

 Current tap-setting: Pickup current in amps

 Time-dial setting: The adjustable amount of time delay

I’ > Ip : Relay operates after a small time delay

I’ >> Ip : Relay operates after a smaller time delay

I’< Ip : Relay contacts remain open, blocking the coil.

Instantaneous overcurrent relay block and trip regions

Overcurrent relays (3)

Electromechanical time-delay overcurrent relay (right) and CO-8 time-delay overcurrent relay characteristics (left) - (Courtesy of ABB and Westinghouse)

Relay connections to trip all 3 phases

 Phase relays  operate for 3-phase, line-to-line, single line-to-ground, double line-to- ground.

 Faults involving ground (i.e. SLG) can be much lower than 3-LG, especially for distribution feeders with high zero-sequence impedances  Need ground relays

Fuse saving & Fuse blowing  Fuse saving: Avoid blowing

out fuses on temporary faults. Reclosers are used to save fuses.

 Requirements:

a) A recloser or breaker must be located upstream from the fuse to save that fuse.

b) The time-current characteristics of recloser and fuse must be time coordinated.

 Recloser operates quickly on first operation so that it clears the fault before any fuses downstream have chance to melt. Customers may only experience a small blink.

 If fault persists, recloser switches to delayed characteristics to allow the downstream fuses to clear the fault.

Fuse saving or fast tripping

Line recloser trips on the first operation to clear a fault before any fuses downline melt.

If a fault is still present:

 Switch to a slow or delayed tripping characteristic (permanent faults)

 Try a second fast operation (temporary faults)

Fig. 3.26 Time-current curves (TCC) for recloser-fuse coordination

Recloser-Fuse coordination  Time taken by recloser to

interrupt the fault current must be less than the melting time of the fuse.

 If fast operations are not successful, recloser must switch to delayed tripping to allow the fuse to blow and clear the fault

 Proper recloser-fuse coordination: Fuse minimum melting and maximum curves are located between the recloser fast and delayed tripping curves

Fig. 3.26 Time-current characteristic curves for resloser-fuse coordination

OC protection coordination (1)

Single-line diagram of a 13.8-kV radial distribution feeder with fuse / recloser / relay protection

Data for the 13.8-kV feeder

OC protection coordination (2) Situation 1: 3-LG TEMPORARY fault on the load side of tap 2 is 1500A.

1) The 560-A fast recloser opens 3 cycles after the 1500A fault current occurs.

2) Assume that the fault clears during the first reclose interval.

3) 30 cycles later, the recloser recloses.

4) 100T fuse (at bus 2) does not melt.

Figure 10.19: Time-current curves (TCC) for the 13.8-kV feeder

Situation 2: 3-LG PERMANENT fault on the load side of tap 2 is 1500 A. 1) The 560-A fast recloser opens 3 cycles after the 1500A fault current

occurs. It recloses 30 cyc. later into the permanent fault.

2) It opens again after 3 cyc., and recloses into the fault a second time after a 2-s delay.

3) The 560-A delayed recloser opens 3 sec. later.

4) During this interval the 100T fuse blows and clears the fault. 5) The delayed recloser recloses 5s later.

OC protection coordination (3)

Impact of fuse-saving on customers  Customers downline

from the recloser will experience sags and instantaneous interruptions. They will complain  Poor PQ.

 Customers upline from the recloser will experience sags.

 Utility solution:

a) Eliminate fuse-saving

b) Impact: Customers on the affected fused tap will suffer a sustained interruption  Utility reliability impacted.

Practice A: Recloser-fuse coordination Consider the previous 13.8-kV feeder with the following information:

 3-phase fault current on the load side of tap 2: If = 1500A  Current through the recIoser R before the fault: IR = 250A  Current through the fuse 100T before the fault: I100T = 95A  Current through the fuse 100T during the fault: I100T = 1500A

(ignoring load currents)

RecIoser:  Two fast and Two delayed operations  First recIose interval = 0.5s; Second recIose interval = 2s  RecIose intervals after a delayed trip = 5 - 10s

Data from TCC in Fig. 10.19: Operating times for the 1500A fault currents:

100T Fuse: 0.45 - 0.6s; Assume that it takes 0.5s to melt. RecIoser: Fast tripping for 560A recIoser causes it to operate after

0.05s; Delayed Tripping causes it to operate after 3s.

Assume that the fault is TEMPORARY and will clear itself after 2s and a fuse saving scheme is employed. Determine protection operation sequence and sketch the RMS current profile seen by the recloser. Also determine PQ impact.

Solution A: Recloser-fuse coordination (1)

13.8-kV feeder

Solution A: Recloser-fuse coordination (2)

Solution A: Recloser-fuse coordination (3)

Solution A: Recloser-fuse coordination (4)

PQ impact on customers: Downstream from the recloser: 1 momentary interruption between t=0s to t=2.6s (fault cleared at 2s then recloser closes at 2.6s).

Upstream from the recloser: 2 sags instantaneous 1st sag: 0s-0.05 (3 cycles) 2nd sag: 0.55-0.6s (3 cycles)

Practice B: Recloser-fuse coordination Given the same feeder and information as in the previous Practice A.

Now assume that the fault is PERMANENT.

Determine protection operation sequence and sketch the RMS current profile seen by the recloser. Also determine PQ impact.

Single-line diagram of a 13.8-kV radial distribution feeder with fuse / recloser / relay protection

Solution B: Recloser-fuse coordination (1)

Solution B: Recloser-fuse coordination (2)

The RMS current profiles seen by the recloser and 100T fuse at tap 2

Solution B: Recloser-fuse coordination (3) PQ impact on customers:

Downstream from the recloser (except customers on Lateral 2 “Load 2”:

 1 temporary interruption between t=0s to t=3.2s (fault cleared when 100T fuse melts); duration = 3.2s

Customers on Lateral 2 “Load 2”:

 Sustained interruption until the fuse is replaced

Upstream from the recloser: 3 sags

 1st sag: 0s-0.05 (3 cycles) instantaneous

 2nd sag: 0.55-0.6s (3 cycles) instantaneous

 3rd sag: 2.6-3.2s (0.8s) momentary

References

1. S. Santoso, Fundamentals of Electric Power Quality, 2012.

2. R. C. Dugan, M. F. McGranaghan, S. Santoso, W. Beaty, Electrical Power Systems Quality, McGraw Hill 2012.

3. T. A. Short, Electric Power Distribution Handbook, 2003.

4. J. D. Glover, M. S. Sarma, T. J Overbye, Power System Analysis and Design, 5th Ed., CENGAGE Learning, 2012.

5. T. Gonen, Electric Power Distribution Engineering, 3rd ed., 2014, CRC Press, ISBN 9781482207002.

6. W. H. Kersting, Distribution System Modeling and Analysis, 3rd ed., CRC Press, 2012.

7. IEEE Std. 519-1992.

8. Other sources