34786407-8-shortcircuit-iec

©1996-2009 Operation Technology, Inc. – Workshop Notes: Short-Circuit IEC

Short-Circuit AnalysisIEC Standard

©1996-2009 Operation Technology, Inc. – Workshop Notes: Short-Circuit IEC Slide 2

CORTO CIRCUITO

Estándar de ANSI/IEEE & IEC.

Análisis de fallas transitorias (IEC 61363).

Efecto de Arco (NFPA 70E-2000)

Integrado con coordinación de dispositivos de protección.

Evaluación automática de dispositivos.

Características principales:


Purpose of Short-Circuit Studies• A Short-Circuit Study can be used to determine

any or all of the following:

– Verify protective device close and latch capability

– Verify protective device interrupting capability

– Protect equipment from large mechanical forces (maximum fault kA)

– I2t protection for equipment (thermal stress)

– Selecting ratings or settings for relay coordination

Types of Short-Circuit Faults



Types of SC Faults•Three-Phase Ungrounded Fault•Three-Phase Grounded Fault•Phase to Phase Ungrounded Fault•Phase to Phase Grounded Fault•Phase to Ground Fault

Fault Current

•IL-G can range in utility systems from a few percent to

possibly 115 % ( if Xo < X1 ) of I3-phase (85% of all faults).

•In industrial systems the situation IL-G > I3-phase is rare.

Typically IL-G .87 * I3-phase

•In an industrial system, the three-phase fault condition is frequently the only one considered, since this type of fault generally results in Maximum current.

Types of Short-Circuit Faults


)tSin(Vmv(t)

i(t)v(t)

Short-Circuit Phenomenon


Offset) (DC

TransientState Steady

t) - sin(

Z

Vm ) - tsin(

Z

Vmi(t)

(1) ) t Sin(Vmdt

di L Riv(t)

LR

-e

expression following theyields 1equation Solving

i(t)v(t)

DC Current

AC Current (Symmetrical) with No AC Decay


AC Fault Current Including the DC Offset (No AC Decay)



Machine Reactance ( λ = L I )

AC Decay Current


Fault Current Including AC & DC Decay


IEC Short-Circuit Calculation (IEC 909)

• Initial Symmetrical Short-Circuit Current (I"k)

• Peak Short-Circuit Current (ip)

• Symmetrical Short-Circuit Breaking Current (Ib)

• Steady-State Short-Circuit Current (Ik)


IEC Short-Circuit Calculation Method

• Ik” = Equivalent V @ fault location divided by equivalent Z

• Equivalent V is based bus nominal kV and c factor

• XFMR and machine Z adjusted based on cmax, component Z & operating conditions


Transformer Z Adjustment

• KT -- Network XFMR

• KS,KSO – Unit XFMR for faults on system side

• KT,S,KT,SO – Unit XFMR for faults in auxiliary system, not between Gen & XFMR

• K=1 – Unit XFMR for faults between Gen & XFMR


Syn Machine Z Adjustment

• KG – Synchronous machine w/o unit XFMR

• KS,KSO – With unit XFMR for faults on system side

• KG,S,KG,SO – With unit XFMR for faults in auxiliary system, including points between Gen & XFMR


Types of Short-Circuits

• Near-To-Generator Short-Circuit

– This is a short-circuit condition to which at least one synchronous machine contributes a prospective initial short-circuit current which is more than twice the generator’s rated current, or a short-circuit condition to which synchronous and asynchronous motors contribute more than 5% of the initial symmetrical short-circuit current ( I"k) without motors.

Near-To-Generator Short-Circuit




• Far-From-Generator Short-Circuit

– This is a short-circuit condition during which the

magnitude of the symmetrical ac component of

available short-circuit current remains essentially

constant.

Far-From-Generator Short-Circuit



Factors Used in If Calc

• κ – calc ip based on Ik”

• μ – calc ib for near-to-gen & not meshed network

• q – calc induction machine ib for near-to-gen & not meshed network

• Equation (75) of Std 60909-0, adjusting Ik for near-to-gen & meshed network

• λmin & λmax – calc ik


IEC Short-Circuit Study Case



• Maximum voltage factor is used

• Minimum impedance is used (all negative

tolerances are applied and minimum

resistance temperature is considered)

When these options are selected



• Minimum voltage factor is used

• Maximum impedance is used (all positive

tolerances are applied and maximum

resistance temperature is considered)

When this option is selected


Voltage Factor (c)

• Ratio between equivalent voltage &

nominal voltage

• Required to account for:

• Variations due to time & place

• Transformer taps

• Static loads & capacitances

• Generator & motor subtransient behavior


Calculation Method

• Breaking kA is more conservative if the option No Motor Decay is selected

IEC SC 909 Calculation



Device Duty Comparison


Mesh & Non-Mesh If

• ETAP automatically determines mesh & non-meshed contributions according to individual contributions

• IEC Short Circuit Mesh Determination Method – 0, 1, or 2 (default)


L-G FaultsL-G Faults


Symmetrical Components

L-G Faults


Sequence Networks


0

ZZZ

V3I

I3I

021

efaultPrf

af 0

g Zif

L-G Fault Sequence Network Connections


21

efaultPrf

aa

ZZ

V3I

II12

L-L Fault Sequence Network Connections


0

ZZZZ

Z

VI

I0III

20

201

efaultPrf

aaaa 012

g Zif

L-L-G Fault Sequence Network Connections


Transformer Zero Sequence Connections


grounded.

solidly areer transformConnected Y/

or Generators if case thebemay This

I

: then trueare conditions thisIf

&

: ifgreater

becan faultsG -L case. severemost

theisfault phase-3 aGenerally

1f3

1021

fI

ZZZZ

Solid Grounded Devices and L-G Faults


Zero Sequence Model

• Branch susceptances and static loads including capacitors will be considered when this option is checked

• Recommended by IEC for systems with isolated neutral, resonant earthed neutrals & earthed neutrals with earth fault factor > 1.4


Complete reports that include individual branch contributions for:

•L-G Faults

•L-L-G Faults

•L-L Faults

One-line diagram displayed results that include:

•L-G/L-L-G/L-L fault current contributions

•Sequence voltage and currents

•Phase Voltages

Unbalanced Faults Display & Reports


Total Fault Current Waveform

Transient Fault Current Calculation (IEC 61363)


Percent DC Current Waveform



AC Component of Fault Current Waveform



Top Envelope of Fault Current Waveform


IEC Transient Fault Current Calculation




•L-G Faults

•L-L-G Faults

•L-L Faults




•Phase Voltages



TEMA 2


Protective Device Coordination

ETAP Star


ETAP START PROTECCION Y COORDINACION

Curvas para más de 75,000 dispositivos.

Actualización automática de Corriente de Corto Circuito.

Coordinación tiempo-corriente de dispositivos.

Auto-coordinación de dispositivos.

Integrados a los diagramas unifilares.

Rastreo o cálculos en diferentes tiempos.



Agenda

• Concepts & Applications

• Star Overview

• Features & Capabilities

• Protective Device Type

• TCC Curves

• STAR Short-circuit

• PD Sequence of Operation

• Normalized TCC curves

• Device Libraries


Definition

• Overcurrent Coordination

– A systematic study of current responsive devices in an electrical power system.


Objective

• To determine the ratings and settings of fuses, breakers, relay, etc.

• To isolate the fault or overloads.


Criteria

• Economics

• Available Measures of Fault

• Operating Practices

• Previous Experience


Design

• Open only PD nearest (upstream) of the fault or overload

• Provide satisfactory protection for overloads

• Interrupt SC as rapidly (instantaneously) as possible

• Comply with all applicable standards and codes

• Plot the Time Current Characteristics of different PDs


Analysis

When:

• New electrical systems

• Plant electrical system expansion/retrofits

• Coordination failure in an existing plant


Spectrum Of Currents

• Load Current

– Up to 100% of full-load

– 115-125% (mild overload)

• Overcurrent

– Abnormal loading condition (Locked-Rotor)

• Fault Current

– Fault condition

– Ten times the full-load current and higher


Protection

• Prevent injury to personnel

• Minimize damage to components

– Quickly isolate the affected portion of the system

– Minimize the magnitude of available short-circuit


Coordination

• Limit the extent and duration of service interruption

• Selective fault isolation

• Provide alternate circuits


Coordination

t

I

C B A

C

D

D B

A


Protection vs. Coordination

• Coordination is not an exact science

• Compromise between protection and coordination

– Reliability

– Speed

– Performance

– Economics

– Simplicity


Required Data• One-line diagrams (Relay diagrams)

• Power Grid Settings

• Generator Data

• Transformer Data– Transformer kVA, impedance, and connection

Motor Data

• Load Data

• Fault Currents

• Cable / Conductor Data

• Bus / Switchgear Data

• Instrument Transformer Data (CT, PT)

• Protective Device (PD) Data– Manufacturer and type of protective devices (PDs)

– One-line diagrams (Relay diagrams)


Study Procedure

• Prepare an accurate one-line diagram (relay diagrams)

• Obtain the available system current spectrum (operating load, overloads, fault kA)

• Determine the equipment protection guidelines

• Select the appropriate devices / settings

• Plot the fixed points (damage curves, …)

• Obtain / plot the device characteristics curves

• Analyze the results


Time Current Characteristics

• TCC Curve / Plot / Graphs

• 4.5 x 5-cycle log-log graph

• X-axis: Current (0.5 – 10,000 amperes)

• Y-axis: Time (.01 – 1000 seconds)

• Current Scaling (…x1, x10, x100, x100…)

• Voltage Scaling (plot kV reference)

• Use ETAP Star Auto-Scale


TCC Scaling Example

• Situation:

– A scaling factor of 10 @ 4.16 kV is selected for TCC curve plots.

• Question

– What are the scaling factors to plot the 0.48 kV and 13.8 kV TCC curves?


TCC Scaling Example• Solution


Fixed Points

• Cable damage curves

• Cable ampacities

• Transformer damage curves & inrush points

• Motor starting curves

• Generator damage curve / Decrement curve

• SC maximum fault points

Points or curves which do not change regardless of protective device settings:


Capability / Damage Curves

t

I

I2

2t

Gen

I2t

MotorXfmr

I2t

Cable

I2t


Cable Protection

• Standards & References– IEEE Std 835-1994 IEEE Standard Power Cable

Ampacity Tables

– IEEE Std 848-1996 IEEE Standard Procedure for the Determination of the Ampacity Derating of Fire-Protected Cables

– IEEE Std 738-1993 IEEE Standard for Calculating the Current- Temperature Relationship of Bare Overhead Conductors

– The Okonite Company Engineering Data for Copper and Aluminum Conductor Electrical Cables, Bulletin EHB-98


Cable Protection

2

2

1

tA

T 2340.0297log

T 234

The actual temperature rise of a cable when exposed to a short circuit current for a known time is calculated by:

Where:A= Conductor area in circular-mils

I = Short circuit current in ampst = Time of short circuit in seconds

T1= Initial operation temperature (750C)

T2=Maximum short circuit temperature

(1500C)


Cable Short-Circuit Heating LimitsRecommended

temperature rise: B) CU 75-200C


Shielded Cable

The normal tape width is 1½

inches


NEC Section 110‑14 C

• (c) Temperature limitations. The temperature rating associated with the ampacity of a conductor shall be so selected and coordinated as to not exceed the lowest temperature rating of anylowest temperature rating of any connected terminationconnected termination, conductor, or device. Conductors with temperature ratings higher than specified for terminations shall be permitted to be used for ampacity adjustment, correction, or both.

• (1) Termination provisions of equipment for circuits rated 100 amperes or less, or marked for Nos. 14 through 1 conductors, shall be used only for conductors rated 600C (1400F).

• Exception No. 1: Conductors with higher temperature ratings shall be permitted to be used, provided the ampacity of such conductors is determined based on the 6O0C (1400F) ampacity of the conductor size used.

• Exception No. 2: Equipment termination provisions shall be permitted to be used with higher rated conductors at the ampacity of the higher rated conductors, provided the equipment is listed and identified for use with the higher rated conductors.

• (2) Termination provisions of equipment for circuits rated over 100 amperes, or marked for conductors larger than No. 1, shall be used only with conductors rated 750C (1670F).


Transformer Protection• Standards & References

– National Electric Code 2002 Edition

– C37.91-2000; IEEE Guide for Protective Relay Applications to Power Transformers

– C57.12.59; IEEE Guide for Dry-Type Transformer Through-Fault Current Duration.

– C57.109-1985; IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration

– APPLIED PROCTIVE RELAYING; J.L. Blackburn; Westinghouse Electric Corp; 1976

– PROTECTIVE RELAYING, PRINCIPLES AND APPLICATIONS; J.L. Blackburn; Marcel Dekker, Inc; 1987

– IEEE Std 242-1986; IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems

–


Transformer CategoryANSI/IEEE C-57.109


Transformer Categories I, II


Transformer Categories III


Transformer

t(sec)

I (pu)

Thermal200

2.5

I2t = 1250

2

25Isc

Mechanical

K=(1/Z)2t

(D-D LL) 0.87

(D-R LG) 0.58

Frequent Fault

Infrequent Fault

Inrush

FLA


Transformer Protection

MAXIMUM RATING OR SETTING FOR OVERCURRENT DEVICE

PRIMARY SECONDARY

Over 600 Volts Over 600 Volts 600 Volts or Below

Transformer

Rated Impedance

Circuit Breaker Setting

Fuse

Rating

Circuit Breaker Setting

Fuse

Rating

Circuit Breaker Setting or Fuse

Rating

Not more than 6%

600 %

300 %

300 %

250%

125%

(250% supervised)

More than 6% and not more

than 10%

400 %

300 %

250%

225%

125%

(250% supervised)

Table 450-3(a) source: NEC

Any Location – Non-Supervised


Transformer Protection

• Turn on or inrush current

• Internal transformer faults

• External or through faults of major magnitude

• Repeated large motor starts on the transformer. The motor represents a major portion or the transformers KVA rating.

• Harmonics

• Over current protection – Device 50/51

• Ground current protection – Device 50/51G

• Differential – Device 87

• Over or under excitation – volts/ Hz – Device 24

• Sudden tank pressure – Device 63

• Dissolved gas detection

• Oil Level

• Fans

• Oil Pumps

• Pilot wire – Device 85

• Fault withstand

• Thermal protection – hot spot, top of oil temperature, winding temperature

• Devices 26 & 49

• Reverse over current – Device 67

• Gas accumulation – Buckholz relay

• Over voltage –Device 59

• Voltage or current balance – Device 60

• Tertiary Winding Protection if supplied

• Relay Failure Scheme

• Breaker Failure Scheme


Recommended Minimum Transformer Protection

Protective systemWinding and/or power system

grounded neutral groundedWinding and/or power system

neutral ungrounded

Up to 10 MVA Above 10 MVA Up to 10 MVAAbove

10 MVA

Differential - √ - √

Time over current √ √ √ √

Instantaneous restricted ground fault √ √ - -

Time delayed ground fault √ √ - -

Gas detection√ - √

Over excitation - √ √ √ Overheating - √ - √


Question

What is ANSI Shift Curve?


Answer

• For delta-delta connected transformers, with line-to-line faults on the secondary side, the curve must be reduced to 87% (shift to the left by a factor of 0.87)

• For delta-wye connection, with single line-to-ground faults on the secondary side, the curve values must be reduced to 58% (shift to the left by a factor of 0.58)


Question

What is meant by Frequent andInfrequent for transformers?


Infrequent Fault Incidence Zones for Category II & III Transformers

* Should be selected by reference to the frequent-fault-incidence protection curve or for transformers serving industrial, commercial and institutional power systems with secondary-side conductors enclosed in conduit, bus duct, etc., the feeder protective device may be selected by reference to the infrequent-fault-incidence protection curve.

Source: IEEE C57

Source

Transformer primary-side protective device (fuses, relayed circuit breakers, etc.) may be selected by reference to the infrequent-fault-incidence protection curve

Category II or III Transformer

Fault will be cleared by transformer primary-side protective device

Optional main secondary –side protective device. May be selected by reference to the infrequent-fault-incidence protection curve

Feeder protective device

Fault will be cleared by transformer primary-side protective device or by optional main secondary-side protection device

Fault will be cleared by feeder protective device

Infrequent-Fault Incidence Zone*

Feeders

Frequent-Fault Incidence Zone*


Motor Protection

• Standards & References

– IEEE Std 620-1996 IEEE Guide for the Presentation of Thermal Limit Curves for Squirrel Cage Induction Machines.

– IEEE Std 1255-2000 IEEE Guide for Evaluation of Torque Pulsations During Starting of Synchronous Motors

– ANSI/ IEEE C37.96-2000 Guide for AC Motor Protection

– The Art of Protective Relaying – General Electric


Motor Protection

• Motor Starting Curve

• Thermal Protection

• Locked Rotor Protection

• Fault Protection


Motor Overload Protection (NEC Art 430-32 – Continuous-Duty Motors)

• Thermal O/L (Device 49)

• Motors with SF not less than 1.15

– 125% of FLA

• Motors with temp. rise not over 40°C

– 125% of FLA

• All other motors

– 115% of FLA


Motor Protection – Inst. Pickup

LOCKED ROTOR S d

1 I

X X "

PICK UP

LOCKED ROTOR

I RELAY PICK UP 1.2 TO 1.2

I

PICK UP

LOCKED ROTOR

I RELAY PICK UP 1.6 TO 2

I

with a time delay of 0.10 s (six cycles at 60 Hz)

Recommended Instantaneous Setting:

If the recommended setting criteria cannot be met, or where more sensitive protection is desired, the in stantaneous relay (or a second relay) can be set more

sensitively if delayed by a timer. This permits the asymmetricalasymmetrical starting component to decay out. A typical setting for this is:


Locked Rotor Protection

• Thermal Locked Rotor (Device 51)

• Starting Time (TS < TLR)

• LRA

– LRA sym

– LRA asym (1.5-1.6 x LRA sym) + 10% margin


Fault Protection (NEC Art / Table 430-52)

• Non-Time Delay Fuses

– 300% of FLA

• Dual Element (Time-Delay Fuses)

– 175% of FLA

• Instantaneous Trip Breaker

– 800% - 1300% of FLA*

• Inverse Time Breakers

– 250% of FLA

*can be set up to 1700% for Design B (energy efficient) Motor


Low Voltage Motor Protection

• Usually pre-engineered (selected from Catalogs)

• Typically, motors larger than 2 Hp are protected by combination starters

• Overload / Short-circuit protection


Low-voltage MotorRatings Range of ratingsContinuous amperes 9-250 —

Nominal voltage (V) 240-600 —

Horsepower 1.5-1000 —

Starter size (NEMA) — 00-9

Types of protection Quantity NEMA designation

Overload: overload relay elements 3 OL

Short circuit: circuit breaker current

trip elements3 CB

Fuses 3 FUUndervoltage: inherent with integral control supply and three-wire control circuit — —

Ground fault (when speci fied): ground relay with toroidal CT — —


Minimum Required Sizes of a NEMA

Combination Motor Starter System

MAXIMUM CONDUCTOR LENGTH FOR ABOVE AND

BELOW GROUND CONDUIT SYSTEMS. ABOVE GROUND SYSTEMS HAVE DIRECT SOLAR EXPOSURE. 750 C

CONDUCTOR TEMPERATURE, 450 C AMBIENT

CIRCUIT BREAKER SIZE

FU

SE

SIZ

E

CLA

SS

J

FU

SE

MO

TO

R H

P

460V

NE

C F

LC

ST

AR

TE

R

SIZ

E

MIN

IMU

M

SIZ

E

GR

OU

ND

ING

C

ON

DU

CT

OR

F

OR

A 5

0 %

CU

RR

EN

T C

AP

AC

ITY

MIN

IMU

M

WIR

E

SIZ

E

MA

XIM

UM

LE

NG

TH

FO

R 1

%

VO

LTA

GE

D

RO

P

NE

XT

LA

RG

ES

T

WIR

E

SIZ

E

US

E N

EX

T

LA

RG

ER

GR

OU

ND

C

ON

DU

CT

OR

MA

XIM

UM

LE

NG

TH

FO

R 1

%

VO

LTA

GE

D

RO

P W

ITH

LA

RG

ER

WIR

E

250%

200%

150%

1 2.1 0 12 12 759 10 1251 15 15 15 5

1½ 3 0 12 12 531 10 875 15 15 15 6 2 3.4 0 12 12 468 10 772 15 15 15 7

3 4.8 0 12 12 332 10 547 20 20 15 10

5 7.6 0 12 12 209 10 345 20 20 15 15

7½ 11 1 12 10 144 8 360 30 25 20 20

10 14 1 10 8 283 6 439 35 30 25 30

15 21 2 10 8 189 6 292 50 40 30 45

20 27 2 10 6 227 4 347 70 50 40 60

25 34 2 8 4 276 2 407 80 70 50 70

30 40 3 6 2 346 2/0 610 100 70 60 90

40 52 3 6 2 266 2/0 469 150 110 90 110

50 65 3 2 2/0 375 4/0 530 175 150 100 125

60 77 4 2 2/0 317 4/0 447 200 175 125 150

75 96 4 2 4/0 358 250 393 250 200 150 200

100 124 4 1 250 304 350 375 350 250 200 250

125 156 5 2/0 350 298 500 355 400 300 250 350

150 180 5 4/0 500 307 750 356 450 350 300 400


Required Data - Protection of a Medium Voltage Motor• Rated full load current

• Service factor

• Locked rotor current

• Maximum locked rotor time (thermal limit curve) with the motor at ambient and/or operating temperature

• Minimum no load current

• Starting power factor

• Running power factor

• Motor and connected load accelerating time

• System phase rotation and nominal frequency

• Type and location of resistance temperature devices (RTDs), if used

• Expected fault current magnitudes

• First ½ cycle current

• Maximum motor starts per hour


Medium-Voltage Class E Motor Controller

RatingsClass El

(without fuses)

Class E2 (with fuses)

Nominal system voltage 2300-6900 2300-6900Horsepower 0-8000 0-8000

Symmetrical MVA interrupting capacity at nominal system voltage

25-75 160-570

Types of Protective Devices QuantityNEMA Designation

Overload, or locked Rotor, or both:

Thermal overload relayTOC relay

IOC relay plus time delay

333

OL OC TR/O

Thermal overload relay 3 OL

TOC relay 3 OC

IOC relay plus time delay 3 TR/OC

Short Circuit:

Fuses, Class E2 3 FU

IOC relay, Class E1 3 OC

Ground Fault

TOC residual relay 1 GP

Overcurrent relay with toroidal CT

1 GP

NEMA Class E2 medium voltage starter

NEMA Class E1 medium voltage starter

Phase Balance

Current balance relay 1 BC

Negative-sequence voltage relay (per bus), or both

1 —

Undervoltage:Inherent with integral control supply and three-wire control circuit, when voltage falls suffi ciently to permit the contractor to open and break the seal-in circuit

— UV

Temperature:Temperature relay, operating from resistance sensor or ther mocouple in stator winding

— OL


Starting Current of a 4000Hp, 12 kV, 1800 rpm Motor

First half cycle current showing current offset.

Beginning of run up current showing load torque pulsations.


Starting Current of a 4000Hp, 12 kV, 1800 rpm Motor -

Motor pull in current showing motor reaching synchronous speed

Oscillographs


Thermal Limit Curve


Thermal Limit Curve

Typical Curve


200 HP

MCP

O/L

Starting Curve

I2T

(49)

MCP (50)

(51)ts

tLR

LRAs LRAasym


Protective Devices

• Fuse

• Overload Heater

• Thermal Magnetic

• Low Voltage Solid State Trip

• Electro-Mechanical

• Motor Circuit Protector (MCP)

• Relay (50/51 P, N, G, SG, 51V, 67, 49, 46, 79, 21, …)


Fuse (Power Fuse)

• Non Adjustable Device (unless electronic)

• Continuous and Interrupting Rating

• Voltage Levels (Max kV)

• Interrupting Rating (sym, asym)

• Characteristic Curves

– Min. Melting

– Total Clearing

• Application (rating type: R, E, X, …)


Fuse Types

• Expulsion Fuse (Non-CLF)

• Current Limiting Fuse (CLF)

• Electronic Fuse (S&C Fault Fiter)


Minimum Melting Time Curve

Total Clearing Time Curve


Current Limiting Fuse(CLF) • Limits the peak current of short-circuit

• Reduces magnetic stresses (mechanical damage)

• Reduces thermal energy


Current Limiting ActionC

urr

ent

(pea

k a

mp

s)

tm ta

Ip’

Ip

tc

ta = tc – tm

ta = Arcing Time

tm = Melting Time

tc = Clearing Time

Ip = Peak Current

Ip’ = Peak Let-thru Current

Time (cycles)


Symmetrical RMS Amperes

Pea

k L

et-T

hrou

gh A

mpe

res

100 A

60 A

7% PF (X/R = 14.3)

12,500

5,200

230,000

300 A

100,000

Let-Through Chart


Fuse

Generally:

• CLF is a better short-circuit protection

• Non-CLF (expulsion fuse) is a better Overload protection

• Electronic fuses are typically easier to coordinate due to the electronic control adjustments


Selectivity Criteria

Typically:

• Non-CLF: 140% of full load

• CLF: 150% of full load

• Safety Margin: 10% applied to Min Melting (consult the fuse manufacturer)


Molded Case CB

• Thermal-Magnetic

• Magnetic Only

• Motor Circuit Protector (MCP)

• Integrally Fused (Limiters)

• Current Limiting

• High Interrupting Capacity

• Non-Interchangeable Parts

• Insulated Case (Interchange Parts)

Types

• Frame Size

• Poles

• Trip Rating

• Interrupting Capability

• Voltage


MCCB


MCCB with SST Device


Thermal Minimum

Thermal Maximum

Magnetic(instantaneous)


LVPCB

• Voltage and Frequency Ratings

• Continuous Current / Frame Size / Sensor

• Interrupting Rating

• Short-Time Rating (30 cycle)

• Fairly Simple to Coordinate

• Phase / Ground Settings

• Inst. Override


CB 2CB 1

IT

ST PU

ST Band

LT PU

LT Band

480 kV

CB 2

CB 1

If =30 kA


Inst. Override


Overload Relay / Heater

• Motor overload protection is provided by a device that models the temperature rise of the winding

• When the temperature rise reaches a point that will damage the motor, the motor is de-energized

• Overload relays are either bimetallic, melting alloy or electronic


Overload Heater (Mfr. Data)


QuestionWhat is Class 10 and Class 20 Thermal OLR curves?


Answer

• At 600% Current Rating:

– Class 10 for fast trip, 10 seconds or less

– Class 20 for, 20 seconds or less (commonly used)

– There is also Class 15, 30 for long trip time (typically provided with electronic overload relays)

6

20


Answer


Overload Relay / Heater• When the temperature at the combination motor starter is more than

±10 °C (±18 °F) different than the temperature at the motor, ambient temperature correction of the motor current is required.

• An adjustment is required because the output that a motor can safely deliver varies with temperature.

• The motor can deliver its full rated horsepower at an ambient temperature specified by the motor manufacturers, normally + 40 °C. At high temperatures (higher than + 40 °C) less than 100% of the normal rated current can be drawn from the motor without shortening the insulation life.

• At lower temperatures (less than + 40 °C) more than 100% of the normal rated current could be drawn from the motor without shortening the insulation life.


Overcurrent Relay

• Time-Delay (51 – I>)

• Short-Time Instantaneous ( I>>)

• Instantaneous (50 – I>>>)

• Electromagnetic (induction Disc)

• Solid State (Multi Function / Multi Level)

• Application


Time-Overcurrent Unit

• Ampere Tap Calculation

– Ampere Pickup (P.U.) = CT Ratio x A.T. Setting

– Relay Current (IR) = Actual Line Current (IL) / CT Ratio

– Multiples of A.T. = IR/A.T. Setting

= IL/(CT Ratio x A.T. Setting)

IL

IR

CT

51


Instantaneous Unit

• Instantaneous Calculation

– Ampere Pickup (P.U.) = CT Ratio x IT Setting

– Relay Current (IR) = Actual Line Current (IL) / CT Ratio

– Multiples of IT = IR/IT Setting

= IL/(CT Ratio x IT Setting)

IL

IR

CT

50


Relay Coordination

• Time margins should be maintained between T/C curves

• Adjustment should be made for CB opening time

• Shorter time intervals may be used for solid state relays

• Upstream relay should have the same inverse T/C characteristic as the downstream relay (CO-8 to CO-8) or be less inverse (CO-8 upstream to CO-6 downstream)

• Extremely inverse relays coordinates very well with CLFs


Situation

Calculate Relay Setting (Tap, Inst. Tap & Time Dial)For This System

4.16 kV

DS 5 MVA

Cable

1-3/C 500 kcmilCU - EPR

CB

Isc = 30,000 A

6 %

50/51 Relay: IFC 53CT 800:5


Solution

AInrsuh 328,869412I

A338.4800

5II LR

Transformer: AkV

kVAL 694

16.43

000,5I

IL

CTRIR

Set Relay:

A 55 1.52800

5328,8)50(

1

)38.1(6/4.338 0.6

4.5338.4%125

AInst

TD

ATAP

A


Question

What T/C Coordination interval should be maintained between relays?


Answer

At

I

B

CB Opening Time

+

Induction Disc Overtravel (0.1 sec)

+

Safety margin (0.2 sec w/o Inst. & 0.1 sec w/ Inst.)


Recloser• Recloser protects electrical transmission systems from temporary

voltage surges and other unfavorable conditions.

• Reclosers can automatically "reclose" the circuit and restore normal power transmission once the problem is cleared.

• Reclosers are usually designed with failsafe mechanisms that prevent them from reclosing if the same fault occurs several times in succession over a short period. This insures that repetitive line faults don't cause power to switch on and off repeatedly, since this could cause damage or accelerated wear to electrical equipment.

• It also insures that temporary faults such as lightning strikes or transmission switching don't cause lengthy interruptions in service.


Recloser Types

• Hydraulic

• Electronic

– Static Controller

– Microprocessor Controller


Recloser Curves


TEMA 3


Transient Stability


Topics

• What is Transient Stability (TS)

• What Causes System Unstable

• Effects When System Is Instable

• Transient Stability Definition

• Modeling and Data Preparation

• ETAP TS Study Outputs

• Power System TS Studies

• Solutions to Stability Problems


What is Transient Stability

• TS is also called Rotor Angle StabilitySomething between mechanical system and

electrical system – energy conversion

• It is a Electromechanical PhenomenonTime frame in milliseconds

• All Synchronous Machines Must Remain in Synchronism with One AnotherSynchronous generators and motorsThis is what system stable or unstable means



• Torque Equation (generator case)

T = mechanical torque

P = number of poles

air = air-gap flux

Fr = rotor field MMF

= rotor angle



• Swing Equation

M = inertia constant

D = damping constant

Pmech = input mechanical power

Pelec = output electrical power


What Causes System Unstable

• From Torque EquationT (prime mover)Rotor MMF (field winding)Air-Gap Flux (electrical system)

• From Swing EquationPmechPelecDifferent time constants in mechanical and

electrical systems


What Causes System Unstable

• In real operationShort-circuitLoss of excitationPrime mover failureLoss of utility connectionsLoss of a portion of in-plant generationStarting of a large motorSwitching operationsImpact loading on motorsSudden large change in load and generation


Effects When System Is Instable

Case 1: Steady-state stableCase 2: Transient stable Case 3: Small-signal unstable Case 4: First swing unstable

• Swing in Rotor Angle (as well as in V, I, P, Q and f)



• A 2-Machine Example

• At = -180º (Out-of-Step,Slip the Pole)



• Synchronous machine slip poles – generator tripping

• Power swing

• Misoperation of protective devices

• Interruption of critical loads

• Low-voltage conditions – motor drop-offs

• Damage to equipment

• Area wide blackout

• …


• Examine One Generator

• Power Output Capability Curve

is limited to 180º

Transient Stability Definition


Transient Stability Definition

• Transient and Dynamic Stability Limit

After a severe disturbance, the synchronous generator reaches a steady-state operating condition without a prolonged loss of synchronism

Limit: < 180 during swing


• Synchronous Machine

Machine Exciter and AVR Prime Mover and Governor / Load Torque Power System Stabilizer (PSS) (Generator)

Modeling and Data Preparation



• Typical synchronous machine data



• Induction Machine

Machine Load Torque



• Power Grid

Short-Circuit Capability Fixed internal voltage and infinite inertia



• Load

Voltage dependency Frequency dependency



• Load



• Events and Actions



Device Type Action

Bus 3-P Fault L-G Fault Clear Fault

Branch Fraction Fault

Clear Fault

PD Trip Close

Generator Droop / Isoch

Start Loss Exc. P Change V Change Delete

Grid P Change V Change Delete

Motor Accelerate Load Change

Delete

Lumped Load Load Change

Delete

MOV Start

Wind Turbine Disturbance Gust Ramp

MG Set Emergency Main


Power System TS Studies

• Fault3-phase and single phase faultClear faultCritical Fault Clearing Time (CFCT)Critical System Separation Time (CSST)

• Bus TransferFast load transferring

• Load SheddingUnder-frequencyUnder-voltage

• Motor Dynamic Acceleration Induction motorSynchronous motor



• Critical Fault Clearing Time (CFCT)

• Critical Separation Time (CSST)

unstable

unstableCycle

Clear faultClear fault

1 cycle

unstable

stable

1 cycle

Clear faultClear fault

CFCT

Fault

unstable

unstable

Cycle

1 cycleunstable

stable

1 cycle

CSST

SeparationSeparationSeparationSeparationFault



-1

-0.8

-0.6

-0.4

-0.2

0

0.2

0.4

0.6

0.8

1

-1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1

Vmotor

s

• Fast Bus Transfer

Motor residual voltage


• Fast Bus Transfer

Ttransfer 10 cycles

90 degrees

ER 1.33 per unit (133%)


ES = System equivalent per unit volts per hertz

EM = Motor residual per unit per hertz

ER = Resultant vectorial voltage in per unit volts per hertz



• Load Shedding



• Motor Dynamic AccelerationImportant for islanded system operationMotor starting impact Generator AVR actionReacceleration


• Improve System Design Increase synchronizing power

• Design and Selection of Rotating Equipment Use of induction machines Increase moment of inertia Reduce transient reactance Improve voltage regulator and exciter

characteristics

Solution to Stability Problems


• Application of Power System Stabilizer (PSS)

• Add System Protections Fast fault clearance Load shedding System separationOut-Of-Step relay…

Solution to Stability Problems


TEMA 4


Harmonic Analysis


ARMONICAS

Exploración de frecuencia.

Flujo Armónico de Carga.

Dimensionamiento y Diseño de Filtros.

Evaluación Automática del límite de distorsión.

Factores de la influencia del teléfono (TIF & I*T)



Types of Power Quality Problems


Waveform Distortion

• Primary Types of Waveform Distortion

– DC Offset

– Harmonics

– Interharmonics

– Notching

– Noise


Harmonics

• One special category of power quality problems

• “Harmonics are voltages and/or currents present in an electrical system at some multiple of the fundamental frequency.”(IEEE Std 399, Brown Book)


Nonlinear Loads

• Sinusoidal voltage applied to a simple nonlinear resistor

• Increasing the voltage by a few percent may cause current to double


Fourier Representation

• Any periodic waveform can be expressed as a sum of sinusoids

• The sum of the sinusoids is referred to as Fourier Series (6-pulse)

)cos(

13cos13

111cos

11

17cos

7

13cos

5

1(cos

32

1h

hh

dac

thI

tttttII


Harmonic Sources

• Utilities (Power Grid)

– Known as “Background Harmonic”

– Pollution from other irresponsible customers

– SVC, HVDC, FACTS, …

– Usually a voltage source

• Synchronous Generators

– Due to Pitch (can be eliminated by fractional-pitch winding) and Saturation

– Usually a voltage source


Harmonic Sources (cont’d)

• Transformers

– Due to magnetizing branch saturation

– Only at lightly loaded condition

– Usually a current source

• Power Electronic Devices

– Charger, Converter, Inverter, UPS, VFD, SVC, HVDC, FACTS (Flexible alternating current transmission systems) …

– Due to switching actions

– Either a voltage source or a current source


Harmonic Sources (cont’d)

• Other Non-Linear Loads

– Arc furnaces, discharge lighting, …

– Due to unstable and non-linear process

– Either a voltage source or a current source

• In general, any load that is applied to a power system that requires other than a sinusoidal current


Harmonic I and V


Classification of Harmonics

• Harmonics may be classified as:

– Characteristic Harmonics

Generally produced by power converters

– Non-Characteristic Harmonics

Typically produced by arc furnaces and discharge lighting (from non-periodical waveforms)


Phase Angle Relationship

• Fundamental Frequency



• Third Order



• Fifth Order

• Seventh Order


Order vs. Sequence


Characteristic Harmonics


Characteristic Harmonics (cont’d)


Harmonic Spectrum

%


Harmonic-Related Problems

• Motors and Generators

– Increased heating due to iron and copper losses

– Reduced efficiency and torque

– Higher audible noise

– Cogging or crawling

– Mechanical oscillations


Harmonic-Related Problems (cont’d)• Transformers

– Parasitic heating

– Increased copper, stray flux and iron losses

• Capacitors (var compensators)

– Possibility of system resonance

– Increased heating and voltage stress

– Shortened capacitor life


Harmonic-Related Problems (cont’d)• Power Cables

– Involved in system resonance

– Voltage stress and corona leading to dielectric failure

– Heating and derating

• Neutrals of four-wire systems (480/277V; 120/208V)

– Overheating

• Fuses

– Blowing


Harmonic-Related Problems (cont’d)• Switchgears

– Increased heating and losses

– Reduced steady-state current carrying capability

– Shortened insulation components life

• Relays

– Possibility of misoperation

• Metering

– Affected readings


Harmonic-Related Problems (cont’d)• Communication Systems

– Interference by higher frequency electromagnetic field

• Electronic Equipment (computers, PLC)

– Misoperation

• System

– Resonance (serial and parallel)

– Poor power factor


Parallel Resonance

• Total impedance at resonance frequency increases

• High circulating current will flow in the capacitance-inductance loop


Parallel Resonance


Capacitor Banks


Capacitor Banks

Say, Seventh Harmonic Current = 5% of 1100A = 55 A


Capacitor Banks

Resistance = 1% including cable and transformerCAF = X/R = 7*0.0069/0.0012 =40.25Resonant Current = 55*40.25 = 2214 A


Parallel Resonance (cont’d)

Cause:

Impacts: 1. Excessive capacitor fuse operation

2. Capacitor failures3. Incorrect relay tripping4. Telephone interference5. Overheating of equipment

Source inductance resonates with capacitor bank at a frequency excited by the facilities harmonic sources


Harmonic Distortion Measurements

• Total Harmonic Distortion (THD)

– Also known as Harmonic Distortion Factor (HDF), is the most popular index to measure the level of harmonic distortion to voltage and current

– Ratio of the RMS of all harmonics to the fundamental component

– For an ideal system THD = 0%

– Potential heating value of the harmonics relative to the fundamental


Harmonic Distortion Measurements (cont’d)

1

2

2

F

F

THDi

Where Fi is the amplitude of the ith harmonic,

and F1 is that for the fundamental component.

– Good indicator of additional losses due to current flowing through a conductor

– Not a good indicator of voltage stress in a capacitor (related to peak value of voltage waveform, not its heating value)


Harmonic Distortion Example

Find THD for this waveform


Harmonic Example

• Find THD for this Harmonic Spectrum


Adjustable Speed Drive – Current Distortion


Adjustable Speed Drive – Voltage Distortion


Harmonic Distortion Measurements (cont’d)• Individual Harmonic Distortion (IHD)

- Ratio of a given harmonic to fundamental- To track magnitude of individual harmonic

1F

FIHD i

• Root Mean Square (RMS) - Total- Root Mean Square of fundamental plus all harmonics

- Equal to fundamental RMS if Harmonics are zero

1

2iFRMS


Harmonic Distortion Measurements (cont’d)• Arithmetic Summation (ASUM)

– Arithmetic summation of magnitudes of all components (fundamental and all harmonics)

– Directly adds magnitudes of all components to estimate crest value of voltage and current

– Evaluation of the maximum withstanding ratings of a device

1

iFASUM


Harmonic Distortion Measurements (cont’d)• Telephone Influence Factor (TIF)

– Weighted THD

– Weights based on interference to an audio signal in the same frequency range

– Current TIF shows impact on adjacent communication systems

2

1

2

1

i

ii

F

FW

TIF


Harmonic Distortion Measurements (cont’d)

• I*T Product (I*T)

– A product current components (fundamental and harmonics) and weighting factors

H

hhh TITI

1

2)(

where Ih = current component

Th= weighting factor

h = harmonic order (h=1 for fundamental)H = maximum harmonic order to account


Triplen Harmonics

• Odd multiples of thethird harmonic(h = 3, 9, 15, 21, …)

• Important issue forgrounded-wye systemswith neutral current

• Overloading and TIF problems

• Misoperation of devices due to presence of harmonics on the neutral


Triplen Harmonics


Winding Connections

• Delta winding provides ampere turn balance

• Triplen Harmonics cannot flow

• When currents are balanced Triplens behave as Zero Sequence currents

• Used in Utility Distribution Substations

• Delta winding connected to Transmission

• Balanced Triplens can flow

• Present in equal proportions on both sides

• Many loads are served in this fashion


Implications

• Neutral connections are susceptible to overheating when serving single-phase loads on the Y side that have high 3rd Harmonic

• Measuring current on delta side will not show the triplens and therefore do not give a true idea of the heating the transformer is subjected to

• The flow of triplens can be interrupted by appropriate isolation transformer connection

• Removing the neutral connection in one or both Y windings blocks the flow of Triplen harmonic current

• Three legged core transformers behave as if they have a “phantom” delta tertiary winding


Modeling in Harmonic Analysis

• Motors and Machines

– Represented by their equivalent negative sequence reactance

• Lines and Cables

– Series impedance for low frequencies

– Long line correction including transposition and distributed capacitance


Modeling in Harmonic Analysis (cont’d)

• Transformers

– Leakage impedance

– Magnetizing impedance

• Loads

– Static loads reduce peak resonant impedance

– Motor loads shift resonant frequency due to motor inductance


Reducing System Harmonics

• Add Passive Filters

– Shunt or Single Tuned Filters– Broadband Filters or Band Pass Filters– Provide low impedance path for harmonic

current– Least expensive


Reducing System Harmonics (cont’d)

• Increase Pulse Numbers

– Increasing pulse number of convert circuits

– Limited by practical control problems


Reducing System Harmonics (cont’d)• Apply Transformer Phase Shifting

– Using Phase Shifting Transformers

– Achieve higher pulse operation of the total converter installation

• In ETAP

– Phase shift is specified in the tab page of the transformer editor


Reducing System Harmonics (cont’d)• Either standard phase shift or special phase

shift can be used


Reducing System Harmonics (cont’d)• Add Active Filters

– Instantly adapts to changing source and load conditions

– Costly

– MVA Limitation


Voltage Distortion Limits

Recommended Practices for Utilities (IEEE 519): Bus Voltage

At

PCC

Individual Distortion

(%)

Total Voltage Distortion

THD (%)

69 kV and below 3.0 5.0

69.001 kV through 161kV 1.5 2.5

161.001 and above 1.0 1.5

In ETAP:

Specify Harmonic Distortion Limits in Harmonic Page of Bus Editor:


Current Distortion Limits

Recommended Practices for General Distribution Systems (IEEE 519):


TEMA 5


Motor StartingDynamic Acceleration


ARRANQUE DE MOTORES

Aceleración dinámica de motores.

Parpadeo (Flicker) de tensión.

Modelos dinámicos de motores.

Arranque estático de motores.

Varios dispositivos de arranque.

Transición de carga.



Why to Do MS Studies?

• Ensure that motor will start with voltage drop• If Tst<Tload at s=1, then motor will not start

• If Tm=Tload at s<sr, motor can not reach rated speed

• Torque varies as (voltage)^2

• Ensure that voltage drop will not disrupt other loads• Utility bus voltage >95%

• 3% Sag represents a point when light flicker becomes visible

• 5% Sag represents a point when light flicker becomes irritating

• MCC bus voltage >80%

• Generation bus voltage > 93%


Why to Do MS Studies?

• Ensure motor feeders sized adequately (Assuming 100% voltage at Switchboard or MCC)

• LV cable voltage drop at starting < 20%

• LV cable voltage drop when running at full-load < 5%

• HV cable voltage drop at starting < 15%

• HV cable voltage drop when running at full-load < 3%

• Maximum motor size that can be started across the line• Motor kW < 1/6 kW rating of generator (islanded)

• For 6 MW of islanded generation, largest motor size < 1 MW


Motor Sizing

• Positive Displacement Pumps / Rotary Pumps

• p = Pressure in psi

• Q = fluid flow in gpm

• n = efficiency

• Centrifugal Pumps

• H = fluid head in feet


Motor Types

• Synchronous• Salient Pole

• Round Rotor

• Induction• Wound Rotor (slip-ring)

• Single Cage CKT Model

• Squirrel Cage (brushless) • Double Cage CKT Model


Induction Motor Advantages

• Squirrel Cage• Slightly higher efficiency and power factor

• Explosive proof

• Wound Rotor• Higher starting torque

• Lower starting current

• Speed varied by using external resistances


Typical Rotor Construction

• Rotor slots are not parallel to the shaft but skewed


Wound Rotor


Operation of Induction Motor• AC applied to stator winding

• Creates a rotating stator magnetic field in air gap

• Field induces currents (voltages) in rotor

• Rotor currents create rotor magnetic field in air gap

• Torque is produced by interaction of air gap fields


Slip Frequency

• Slip represents the inability of the rotor to keep up with the stator magnetic field

• Slip frequencyS = (ωs-ωn)/ωs where ωs = 120f/P

ωn = mech speed


Static Start - Example


Service Factor


Inrush Current


Resistance / Reactance

• Torque Slip Curve is changed by altering resistance / reactance of rotor bars.

• Resistance ↑ by ↓cross sectional area or using higher resistivity material like brass.

• Reactance ↑ by placing conductor deeper in the rotor cylinder or by closing the slot at the air gap.


Rotor Bar Resistance ↑

• Increase Starting Torque

• Lower Starting Current

• Lower Full Load Speed

• Lower Efficiency

• No Effect on Breakdown Torque


Rotor Bar Reactance ↑

• Lower Starting Torque

• Lower Starting Current

• Lower Breakdown Torque

• No effect on Full Load Conditions


Motor Torque Curves


Rotor Bar Design

• Cross section Large (low resistance) and positioned deep in the rotor (high reactance). (Starting Torque is normal and starting current is low).

• Double Deck with small conductor of high resistance. During starting, most current flows through the upper deck due to high reactance of lower deck. (Starting Torque is high and starting current is low).


Rotor Bar Design

• Bars are made of Brass or similar high resistance material. Bars are close to surface to reduce leakage reactance. (Starting torque is high and starting current is low).


Load Torque – ID Fan


Load Torque – FD Fan


Load Torque – C. Pump


Motor Torque – Speed Curve


Double Cage Motor


Motor Full Load Torque

• For example, 30 HP 1765 RPM Motor


Motor Efficiency

• kW Saved = HP * 0.746 (1/Old – 1/New)

• $ Savings = kW Saved * Hrs /Year * $/kWh


Acceleration Torque

• Greater Acceleration Torque means higher inertia that can be handled by the motor without approaching thermal limits


Acceleration Torque

P


Operating Range

• Motor, Generator, or Brake


0.8 1.0

kvar

Loa

d(k

va)

Terminal Voltage

Ter

min

al C

urre

nt

Terminal Voltage0.8 1.0

P = Tm Wm , As Vt ( terminal voltage ) changes from 0.8 to 1.1 pu, Wm changes by a very small amount. There fore, P is approx constant since Tm (α w²m) is approx. constant

L1 Ir

Rated Conditions• Constant Power


0.9 1.0

Kva LR

Terminal Voltage Terminal Voltage0.9 1.0

.8 kvaLR

Vt (pu)

Vt (pu)

.9 I LR

I LR

PIt

KVA LR = Loched - rotor KVA at rated voltage = 2HP

2 ≡ Code letter factor ≡ Locked – rotor KVA ∕ HP

Z st = KVA B KVR ²

KVA LR KVB

Pu, Rst = Zst cos θ st , Xst= Zst sin θ st ______ ____

KVR = rated voltage KVB = Base voltage KVAB = Base power

Starting Conditions• Constant Impedance

Starting Conditions Constant Impedance


ws wm

v1

p

R

Load

Voltage Variation

0

I

80% voltage

100% voltage

ws wm0

TT st T’ st

Tst α ( operating voltage) ²

Rated voltage_____________

Rated voltage_____________Ist α ( operating voltage)

• Torque is proportional to V^2

• Current is proportional to V

I

80% V

100% V


Frequency Variation• As frequency decreases, peak torque shifts toward lower

speed as synchronous speed decreases.

• As frequency decrease, current increases due reduced impedance.

Tem

WS1 WS2 Wm

F1

F2 › F1

0

I

WS1 WS2 Wm

F1

F2 › F1

0

W3 = 120f

P ___ RPM

Adjustable speed drive : Typical speed range for variable torque loads such as pumps and fans is 3/1,maximun is 8/1 ( 1.5 to 60 Hz)


Number of Poles Variation

• As Pole number increases, peak torque shifts toward lower speed as synchronous speed decreases.

Tem

W′S WSWm0

2 P - poles

P - poles

P

RLoad

Nro. of poles variation

W′S = WS___

2


Rotor Z Variation

• Increasing rotor Z will shift peak torque towards lower speed.

S

RQ

P

r1

r2 r3 r4

r1 › r2 › r3 › r4

Rotor – Resistance Variation


Modeling of Elements

• Switching motors – Zlr, circuit model, or characteristic model

• Synch generator - constant voltage behind X’d

• Utility - constant voltage behind X”d

• Branches – Same as in Load Flow

• Non-switching Load – Same as Load flow

• All elements must be initially energized, including motors to start


Motor Modeling

1. Operating Motor

– Constant KVA Load

2. Starting Motor

– During Acceleration – Constant Impedance

– Locked-Rotor Impedance

– Circuit Models

Characteristic Curves

After Acceleration – Constant KVA Load


Locked-Rotor Impedance

• ZLR = RLR +j XLR (10 – 25 %)

• PFLR is much lower than operating PD. Approximate starting PF of typical squirrel cage induction motor:

PO

WE

R F

AC

TO

R

HORSE POWER RATING


Circuit Model I

• Single Cage Rotor

– “Single1” – constant rotor resistance and reactance


Circuit Model II

• Single Cage Rotor

– “Single2” - deep bar effect, rotor resistance and reactance vary with speed [Xm is removed]


Circuit Model III

• Double Cage Rotor

– “DB1” – integrated rotor cages


Circuit Model IV

• Double Cage Rotor

– “DB2” – independent rotor cages


Characteristic Model

• Motor Torque, I, and PF as function of Slip

– Static Model


Calculation Methods I

• Static Motor Starting

– Time domain using static model

– Switching motors modeled as Zlr during starting and constant kVA load after starting

– Run load flow when any change in system

• Dynamic Motor Starting

– Time domain using dynamic model and inertia model

– Dynamic model used for the entire simulation

– Requires motor and load dynamic (characteristic) model


Calculation Methods II


Static versus Dynamic

• Use Static Model When

– Concerned with effect of motor starting on other loads

– Missing dynamic motor information

• Use Dynamic Model When

– Concerned with actual acceleration time

– Concerned if motor will actually start


MS Simulation Features

• Start/Stop induction/synchronous motors

• Switching on/off static load at specified loading category

• Simulate MOV opening/closing operations

• Change grid or generator operating category

• Simulate transformer LTC operation

• Simulate global load transition

• Simulate various types of starting devices

• Simulate load ramping after motor acceleration


Automatic Alert• Starting motor terminal V

• Motor acceleration failure

• Motor thermal damage

• Generator rating

• Generator engine continuous & peak rating

• Generator exciter peak rating

• Bus voltage

• Starting motor bus

• Grid/generator bus

• HV, MV, and LV bus

• User definable minimum time span


Starting Devices Types

• Auto-Transformer

• Stator Resistor

• Stator Reactor

• Capacitor at Bus

• Capacitor at Motor Terminal

• Rotor External Resistor

• Rotor External Reactor

• Y/D Winding

• Partial Wing

• Soft Starter

• Stator Current Limit

– Stator Current Control

– Voltage Control

– Torque Control


Starting Device

• Comparison of starting conditions


Starting Device – AutoXFMR

• C4 and C3 closed initially

• C4 opened, C2 is closed with C3 still closed. Finally C3 is open


Starting Device – AutoXFMR

• Autotransformer starting

MCCM

Autotransformer starter

line

Vmcc

EX. 50% Tap

VMCC50%

tap

5VMCC IST

3IST

VM

PFST ( with autotransformer) = PFST ( without autotransformer)


Starting Device – YD Start

• During Y connection Vs = VL / √3

• Phase current Iy = Id / √3 and 3 to 1 reduction in torque


Starting Device – Rotor R


Starting Device – Stator R• Resistor

VMCC50%

tap

5VMCC VMRLR

XLR

RL XL

PFST ( with resistor) = 1-[pu tap setting ]² * [ 1- (PFST without resistor)²]

= 1- (0.5)² * [1-(PFST)²]


VMCC50%

tap

5VMCC VMRLR

XLR

RL XL

Starting Device Stator X

• Reactor

PFST ( with reactor) = [pu tap setting ] * PFST (without reactor)


Transformer LTC Modeling

• LTC operations can be simulated in motor starting studies

• Use global or individual Tit and Tot

V limit

Tit Tot

T


MOV Modeling I

• Represented as an impedance load during operation– Each stage has own impedance based on I, pf, Vr

– User specifies duration and load current for each stage

• Operation type depends on MOV status– Open statusclosing operation

– Close statusopening operation


MOV Modeling II

• Five stages of operationOpening ClosingAcceleration Acceleration

No load No load

Unseating Travel

Travel Seating

Stall Stall

• Without hammer blow Skip “No Load” period

• With a micro switch Skip “Stall” period

• Operating stage time extended if Vmtr < Vlimit


MOV Closing

• With Hammer Blow- MOV Closing


MOV Opening

• With Hammer Blow- MOV Opening


UNSETTING

TRAVEL

VMTR < V LIMIT

STALLACCL

I

MOV Voltage Limit• Effect of Voltage Limit Violation

Tacc TposTravel Tstl


TEMA 6


Short-CircuitANSI Standard


CORTO CIRCUITO

Estándar de ANSI/IEEE & IEC.

Análisis de fallas transitorias (IEC 61363).

Efecto de Arco (NFPA 70E-2000)

Integrado con coordinación de dispositivos de protección.

Evaluación automática de dispositivos.



Types of SC Faults•Three-Phase Ungrounded Fault•Three-Phase Grounded Fault•Phase to Phase Ungrounded Fault•Phase to Phase Grounded Fault•Phase to Ground Fault

Fault Current

•IL-G can range in utility systems from a few percent to

possibly 115 % ( if Xo < X1 ) of I3-phase (85% of all faults).

•In industrial systems the situation IL-G > I3-phase is rare.

Typically IL-G .87 * I3-phase

•In an industrial system, the three-phase fault condition is frequently the only one considered, since this type of fault generally results in Maximum current.

Short-Circuit Analysis


Purpose of Short-Circuit Studies• A Short-Circuit Study can be used to determine

any or all of the following:

– Verify protective device close and latch capability

– Verify protective device Interrupting capability

– Protect equipment from large mechanical forces (maximum fault kA)

– I2t protection for equipment (thermal stress)

– Selecting ratings or settings for relay coordination


System Components Involved in SC Calculations• Power Company Supply

• In-Plant Generators

• Transformers (using negative tolerance)

• Reactors (using negative tolerance)

• Feeder Cables and Bus Duct Systems (at lower temperature limits)


System Components Involved in SC Calculations• Overhead Lines (at lower temperature limit)

• Synchronous Motors

• Induction Motors

• Protective Devices

• Y0 from Static Load and Line Cable


Elements That Contribute Current to a Short-Circuit

• Generator

• Power Grid

• Synchronous Motors

• Induction Machines

• Lumped Loads(with some % motor load)

• Inverters

• I0 from Yg-Delta Connected Transformer


Elements Do Not Contribute Current in PowerStation

• Static Loads

• Motor Operated Valves

• All Shunt Y Connected Branches


)tSin(Vmv(t)

i(t)v(t)

Short-Circuit Phenomenon


Offset) (DC

TransientState Steady

t) - sin(

Z

Vm ) - tsin(

Z

Vmi(t)

(1) ) t Sin(Vmdt

di L Riv(t)

LR

-e

expression following theyields 1equation Solving

i(t)v(t)


DC Current

AC Current (Symmetrical) with No AC Decay

© 1996-2009 Operation Technology, Inc. – Workshop Notes: Short-Circuit ANSI Slide 305


AC Fault Current Including the DC Offset (No AC Decay)



Machine Reactance ( λ = L I )

AC Decay Current


Fault Current Including AC & DC Decay


1) The ANSI standards handle the AC Decay by varying machine impedance during a fault.

2) The ANSI standards handle the the dc offset by applying multiplying factors. The ANSI Terms for this current are:

•Momentary Current•Close and Latch Current•First Cycle Asymmetrical Current

ANSI

ANSI Calculation Methods


Sources•Synchronous Generators•Synchronous Motors & Condensers•Induction Machines•Electric Utility Systems (Power Grids)

ModelsAll sources are modeled by an internalvoltage behind its impedance.

E = Prefault VoltageR = Machine Armature ResistanceX = Machine Reactance (X”d, X’d, Xd)

Sources and Models of Fault Currents in ANSI Standards


Synchronous Reactance

Transient Reactance

Subtransient Reactance

Synchronous GeneratorsSynchronous Generators are modeled in three stages.

Synchronous Motors & CondensersAct as a generator to supply fault current. This current diminishes as the magnetic field in the machine decays.

Induction MachinesTreated the same as synchronous motors except they do not contribute to the fault after 2 sec.

Electric Utility SystemsThe fault current contribution tends to remain constant.


½ Cycle Network

This is the network used to calculate momentary short-circuit current and protective device duties at the ½ cycle after the fault.

1 ½ to 4 Cycle Network

This network is used to calculate the interrupting short-circuit current and protective device duties 1.5-4 cycles after the fault.

30-Cycle Network

This is the network used to calculate the steady-state short-circuit current and settings for over current relays after 30 cycles.


½ Cycle 1 ½ to 4 Cycle 30 Cycle

UtilityX”d X”d X”d

Turbo GeneratorX”d X”d X’d

Hydro-Gen with Amortisseur

winding

X”d X”d X’d

Hydro-Gen without Amortisseur

winding

0.75*X”d 0.75*X”d X’d

CondenserX”d X”d

Synchronous Motor

X”d 1.5*X”d

Reactance Representation forUtility and Synchronous Machine


½ Cycle 1 ½ to 4 Cycle

>1000 hp , <= 1800 rpm

X”d 1.5*X”d

>250, at 3600 rpm X”d 1.5*X”d

All others, >= 50 hp 1.2*X”d 3.0*X”d

< 50 hp 1.67*X”d

Reactance Representation for Induction Machine

Note: X”d = 1 / LRCpu


½ Cycle Currents(Subtransient

Network)

1 ½ to 4 Cycle Currents

(Transient Network)

HV Circuit BreakerClosing and Latching

CapabilityInterruptingCapability

LV Circuit Breaker Interrupting Capability ---

Fuse Interrupting Capability

---

SWGR / MCC Bus Bracing ---

Relay Instantaneous Settings

---

Device Duty and Usage of Fault Currents

from Different Networks

30 Cycle currents are used for determining overcurrent settings.


MFm is calculated based on:• Fault X/R (Separate R & X Networks)• Location of fault (Remote / Local generation)

SC Current Duty Device Rating

HV CB Asymmetrical RMSCrest

C&L RMSC&L RMS

HV Bus Asymmetrical RMSCrest

Asymmetrical RMSCrest

LV Bus Symmetrical RMSAsymmetrical RMS

Symmetrical RMSAsymmetrical RMS

Comparisons of Momentary capability (1/2 Cycle)

Momentary Multiplying Factor


SC Current Duty Device Rating

HV CBAdj. Symmetrical RMS* Adj. Symmetrical RMS*

LV CB & FuseAdj. Symmetrical RMS*** Symmetrical RMS

Comparisons of Interrupting Capability (1 ½ to 4 Cycle)

MFi is calculated based on:• Fault X/R (Separate R & X Networks)• Location of Fault (Remote / Local generation)• Type and Rating of CB

Interrupting Multiplying Factor


Calculate ½ Cycle Current (Imom, rms, sym) using ½ Cycle Network.

• Calculate X/R ratio and Multiplying factor MFm

• Imom, rms, Asym = MFm * Imom, rms, sym

HV CB Closing and Latching Duty


Calculate 1½ to 4 Cycle Current (Imom, rms, sym) using ½ Cycle Network.

• Determine Local and Remote contributions (A “local” contribution is fed predominantly from generators through no more than one transformation or with external reactances in series that is less than 1.5 times generator subtransient reactance. Otherwise the contribution is defined as “remote”).

• Calculate no AC Decay ratio (NACD) and multiplying factor MFi

NACD = IRemote / ITotal

ITotal = ILocal + IRemote

(NACD = 0 if all local & NACD = 1 if all remote)

• Calculate Iint, rms, adj = MFi * Iint, rms, Symm

HV CB Interrupting Duty


• CB Interrupting kA varies between Max kA and Rated kA as applied kV changes – MVAsc capability.

• ETAP’s comparison between CB Duty of Adj. Symmetrical kA and CB capability of Adjusted Int. kA verifies both symmetrical and asymmetrical rating.

• The Option of C37.010-1999 standard allows user to specify CPT.

• Generator CB has higher DC rating and is always compared against maximum through SC kA.

HV CB Interrupting Capability


LV CB Interrupting Duty

• LV CB take instantaneous action.

• Calculate ½ Cycle current Irms, Symm (I’f) from the ½

cycle network.

• Calculate X/R ratio and MFi (based on CB type).

• Calculate adjusted interrupting current Iadj, rms, symm =

MFi * Irms, Symm


Calculate ½ Cycle current Iint, rms, symm from ½ Cycle Network.

• Same procedure to calculate Iint, rms, asymm as for CB.

Fuse Interrupting Duty


L-G FaultsL-G Faults


Symmetrical Components

L-G Faults


Sequence Networks


0

ZZZ

V3I

I3I

021

efaultPrf

af 0

g Zif

L-G Fault Sequence Network Connections


21

efaultPrf

aa

ZZ

V3I

II12

L-L Fault Sequence Network Connections


0

ZZZZ

Z

VI

I0III

20

201

efaultPrf

aaaa 012

g Zif

L-L-G Fault Sequence Network Connections


Transformer Zero Sequence Connections


grounded.

solidly areer transformConnected Y/

or Generators if case thebemay This

I

: then trueare conditions thisIf

&

: ifgreater

becan faultsG -L case. severemost

theisfault phase-3 aGenerally

1f3

1021

fI

ZZZZ

Solid Grounded Devices and L-G Faults



•L-G Faults

•L-L-G Faults

•L-L Faults




•Phase Voltages



SC Study Case Info Page


SC Study Case Standard Page


Tolerance Adjustments

•Transformer Impedance

•Reactor Resistance

•Overload Heater Resistance Temperature

Corrections

•Transmission Line Resistance

•Cable Resistance

Adjust Fault Impedance

•L-G fault Impedance

SC Study Case Adjustments Page

Length Adjustments

•Cable Length

•Transmission Line Length


ToleranceLengthLength

ToleranceLengthLength

ToleranceZZ

onLineTransmissionLineTransmissi

CableCable

rTransformerTransforme

)1(*'

)1(*'

)1(*'

Adjustments can be applied Individually or Globally

Tolerance Adjustments

Positive tolerance value is used for IEC Minimum If calculation.

Negative tolerance value is used for all other calculations.


C in limit etemperatur ConductorTc

C in etemperatur base ConductorTb

etemperatur operating at ResistanceR'

retempereatu base at ResistanceR

Tb

TcRR

Tb

TcRR

BASE

BASEAlumi

BASECopper

)1.228(

)1.228(*'

)5.234(

)5.234(*''

Temperature Correction can be appliedIndividually or Globally

Temperature Correction


TransformersT1 X/R PS =12PT =12ST =12T2 X/R = 12

Power Grid U1X/R = 55

Lump1Y open grounded

Gen1Voltage ControlDesign Setting:%Pf = 85MW = 4 Max Q = 9Min Q = -3

System for SC Study



System for SC Study

Tmin = 40, Tmax = 90


System for SC Study


Short-Circuit Alerts

• Bus Alert

• Protective Device Alert

• Marginal Device Limit


Type of Device Monitored Parameter Condition Reported

MV Bus (> 1000 Volts)Momentary Asymmetrical. rms kA Bracing Asymmetrical

Momentary Asymmetrical. crest kA Bracing Crest

LV Bus (<1000Volts)Momentary Symmetrical. rms kA Bracing Symmetrical

Momentary Asymmetrical. rms kA Bracing Asymmetrical

Bus SC Rating

Device Type ANSI Monitored Parameters IEC Monitored Parameters

LVCB Interrupting Adjusted Symmetrical. rms kA Breaking

HV CB

Momentary C&L Making

Momentary C&L Crest kA N/A

Interrupting Adjusted Symmetrical. rms kA Breaking

Fuse Interrupting Adjusted Symmetrical. rms kA Breaking

SPDT Momentary Asymmetrical. rms kA Making

SPST Switches Momentary Asymmetrical. rms kA Making

Protective Device Rating


Run a 3-phase Duty SC calculation for a fault on Bus4. The display shows the Initial Symmetrical Short-Circuit Current.

3-Phase Duty SC Results



Unbalance Fault Calculation



TEMA 7


Transient Stability


Time Frame of Power System Dynamic Phenomena


Introduction

• TS is also called Rotor Stability, Dynamic Stability

• Electromechanical Phenomenon

• All synchronous machines must remain in synchronism with one another

• TS is no longer only the utility’s concern

• Co-generation plants face TS problems


Analogy

• Which vehicles will pushed hardest?

• How much energy gained by each vehicle?

• Which direction will they move?

• Height of the hill must they climb to go over?


Introduction (cont’d)

• System protection requires consideration of:Critical Fault Clearing Time (CFCT)Critical Separation Time (CST)Fast load transferringLoad Shedding…


Causes of Instability

• Short-circuits

• Loss of utility connections

• Loss of a portion of in-plant generation

• Starting of a large motor

• Switching operations (lines or capacitors)

• Impact loading on motors

• Sudden large change in load and generation


Consequences of Instability

• Synchronous machine slip poles – generator tripping

• Power swing

• Misoperation of protective devices

• Interruption of critical loads

• Low-voltage conditions – motor drop-offs

• Damage to equipment

• Area wide blackout

• …


Synchronous Machines

• Torque Equation (generator case)

T = mechanical torque

P = number of poles

air = air-gap flux

Fr = rotor field MMF

= rotor angle


Swing Equation


Synchronous Machines (cont’d)• Swing Equation

M = inertia constant

D = damping constant

Pmech = input mechanical power

Pelec = output electrical power


Rotor Angle Responses

• Case 1: Steady-state stable

• Case 2: Transient stable

• Case 3: Small-signal unstable

• Case 4: First swing unstable


Power and Rotor Angle (Classical 2-Machine Example)


Power and Rotor Angle (cont’d)


Power and Rotor Angle (Parallel Lines)


Both Lines In Service


One Line Out of Service


Equal Area Criterion


Equal Area - Stable


Equal Area – Unstable


Equal Area - Unstable


Power System Stability Limit

• Steady-State Stability Limit

After small disturbance, the synchronous generator reaches a steady state operating condition identical or close to the pre-disturbance

Limit: < 90


Power System Stability Limit (con’d)• Transient and Dynamic Stability Limit

After a severe disturbance, the synchronous generator reaches a steady-state operating condition without a prolonged loss of synchronism

Limit: < 180 during swing


Generator Modeling

• MachineEquivalent Model / Transient Model / Subtransient Model

• Exciter and Automatic Voltage Regulator (AVR)

• Prime Mover and Speed Governor

• Power System Stabilizer (PSS)


Generator Modeling (con’d)

• Typical synchronous machine data


Factors Influencing TS

• Post-Disturbance Reactance seen from generator. Reactance Pmax

• Duration of the fault clearing time.

Fault time Rotor Acceleration Kinetic Energy Dissipation Time during deceleration

• Generator Inertia.

Inertia Rate of change of Angle Kinetic Energy

• Generator Internal Voltage Internal Voltage Pmax


Factors Influencing TS

• Generator Loading Prior To Disturbance Loading Closer to Pmax. Unstable during acceleration

• Generator Internal Reactance

Reactance Peak Power Initial Rotor Angle Dissipation Time during deceleration

• Generator Output During Fault

Function of Fault Location and Type of Fault


Solution to Stability Problems• Improve system design Increase synchronizing power

• Design and selection of rotating equipment Use of induction machines Increase moment of inertia Reduce transient reactance Improve voltage regulator and exciter

characteristics


Solution to Stability Problems• Reduction of Transmission System

Reactance

• High Speed Fault Clearing

• Dynamic Braking

• Regulate Shunt Compensation

• Steam Turbine Fast Valving

• Generator Tripping

• Adjustable Speed Synchronous Machines


Solution to Stability Problems• HVDC Link Control

• Current Injection from VSI devices

• Application of Power System Stabilizer (PSS)

• Add system protections Fast fault clearance Load Shedding System separation


TEMA 8


Load Flow Analysis


FLUJO DE CARGA

Cálculo de los flujos de potencia.

Diversas representaciones de las cargas.

Cálculo de los perfiles de tensión.

Corrección del factor de potencia.

Diagnóstico automático de equipos.

Corrección automática de impedancias por temperatura.

Cálculo de pérdidas activas y reactivas.



System ConceptsSystem Concepts


jQP

IV

SS

IVS

LL

LN

*

13

*1

3

3

Lagging Power Factor Leading Power Factor

Inductive loads have lagging Power Factors. Capacitive loads have leading Power Factors.

Current and Voltage

Power in Balanced 3-Phase Systems


Leading Power Factor

Lagging Power Factor

ETAP displays lagging Power Factors as positive and leading Power Factors as negative. The Power Factor is displayed in percent.

jQ P

Leading & Lagging Power Factors

P - jQ P + jQ


B

2B

B

B

BB

MVA

)kV(Z

kV3

kVAI

B

actualpu

B

actualpu

Z

ZZ

I

II

B

actualpu

B

actualpu

S

SS

V

VV

B

2B

B

B

BB

S

VZ

V3

SI

ZI3V

VI3S If you have two bases:

Then you may calculate the other two by using the relationships enclosed in brackets. The different bases are:

•IB (Base Current)

•ZB (Base Impedance)

•VB (Base Voltage)

•SB (Base Power)

ETAP selects for LF:

•100 MVA for SB which is fixed for the entire system.

•The kV rating of reference point is used along with the transformer turn ratios are applied to determine the base voltage for different parts of the system.

3-Phase Per Unit System


Example 1: The diagram shows a simple radial system. ETAP converts the branch impedance values to the correct base for Load Flow calculations. The LF reports show the branch impedance values in percent. The transformer turn ratio (N1/N2) is 3.31 and the X/R = 12.14

2B

1B kV

2N

1NkV

Transformer Turn Ratio: The transformer turn ratio is used by ETAP to determine the base voltage for different parts of the system. Different turn ratios are applied starting from the utility kV rating.

To determine base voltage use:

2

pu

pu

RX

1

RX

ZX

Transformer T7: The following equations are used to find the impedance of transformer T7 in 100 MVA base.

RX

xR pu

pu

1BkV

2BkV


Impedance Z1: The base voltage is determined by using the transformer turn ratio. The base impedance for Z1 is determined using the base voltage at Bus5 and the MVA base.

06478.0)14.12(1

)14.12(065.0X

2pu

005336.014.12

06478.0R pu

The transformer impedance must be converted to 100 MVA base and therefore the following relation must be used, where “n” stands for new and “o” stands for old.

)3538.1j1115.0(5

100

5.13

8.13)06478.0j1033.5(

S

S

V

VZZ

23

oB

nB

2

nB

oBo

punpu

38.135j15.11Z100Z% pu

0695.431.3

5.13

2N1N

kVV utility

B

165608.0100

)0695.4(

MVA

VZ

22B

B


8.603j38.60Z100Z% pu

)0382.6j6038.0(1656.0

)1j1.0(

Z

ZZ

B

actualpu

The per-unit value of the impedance may be determined as soon as the base impedance is known. The per-unit value is multiplied by one hundred to obtain the percent impedance. This value will be the value displayed on the LF report.

The LF report generated by ETAP displays the following percent impedance values in 100 MVA base


Load Flow AnalysisLoad Flow Analysis


Load Flow Problem• Given

– Load Power Consumption at all buses

– Configuration

– Power Production at each generator

• Basic Requirement

– Power Flow in each line and transformer

– Voltage Magnitude and Phase Angle at each bus


Load Flow Studies• Determine Steady State Operating Conditions

– Voltage Profile

– Power Flows

– Current Flows

– Power Factors

– Transformer LTC Settings

– Voltage Drops

– Generator’s Mvar Demand (Qmax & Qmin)

– Total Generation & Power Demand

– Steady State Stability Limits

– MW & Mvar Losses


Size & Determine System Equipment & Parameters• Cable / Feeder Capacity

• Capacitor Size

• Transformer MVA & kV Ratings (Turn Ratios)

• Transformer Impedance & Tap Setting

• Current Limiting Reactor Rating & Imp.

• MCC & Switchgear Current Ratings

• Generator Operating Mode (Isochronous / Droop)

• Generator’s Mvar Demand

• Transmission, Distribution & Utilization kV


Optimize Operating Conditions• Bus Voltages are Within Acceptable Limits

• Voltages are Within Rated Insulation Limits of Equipment

• Power & Current Flows Do Not Exceed the Maximum Ratings

• System MW & Mvar Losses are Determined

• Circulating Mvar Flows are Eliminated


Assume VR

Calc: I = Sload / VR

Calc: Vd = I * Z

Re-Calc VR = Vs - Vd

Calculation Process

• Non-Linear System

• Calculated Iteratively

– Assume the LoadVoltage (Initial Conditions)

– Calculate the Current I

– Based on the Current,Calculate Voltage Drop Vd

– Re-Calculate Load Voltage VR

– Re-use Load Voltage as initial condition until the results are within the specified precision.


1. Accelerated Gauss-Seidel Method

• Low Requirements on initial values, but slow in speed.

2. Newton-Raphson Method

• Fast in speed, but high requirement on initial values.

• First order derivative is used to speed up calculation.

3. Fast-Decoupled Method

• Two sets of iteration equations: real power – voltage angle, reactive power – voltage magnitude.

• Fast in speed, but low in solution precision.

• Better for radial systems and systems with long lines.

Load Flow Calculation Methods


kV

kVAFLA

kV

kVAFLA

EffPF

HP

EffPF

kWkVA

Rated

Rated

RatedRated

1

33

7457.0

Where PF and Efficiency are taken at 100 % loading conditions

kV

kVA1000I

)kV3(

kVA1000I

kVA

kWPF

)kVar()kW(kVA

1

3

22

Load Nameplate Data


Constant Power Loads

• In Load Flow calculations induction, synchronous and lump loads are treated as constant power loads.

• The power output remains constant even if the input voltage changes (constant kVA).

• The lump load power output behaves like a constant power load for the specified % motor load.


• In Load Flow calculations Static Loads, Lump Loads (% static), Capacitors and Harmonic Filters and Motor Operated Valves are treated as Constant Impedance Loads.

• The Input Power increases proportionally to the square of the Input Voltage.

• In Load Flow Harmonic Filters may be used as capacitive loads for Power Factor Correction.

• MOVs are modeled as constant impedance loads because of their operating characteristics.

Constant Impedance Loads

© 1996-2008 Operation Technology, Inc. – Workshop Notes: Load Flow Analysis Slide 397


• The current remains constant even if the voltage changes.

• DC Constant current loads are used to test Battery discharge capacity.

• AC constant current loads may be used to test UPS systems performance.

• DC Constant Current Loads may be defined in ETAP by defining Load Duty Cycles used for Battery Sizing & Discharge purposes.

Constant Current Loads


Constant Current Loads


Exponential Load

Polynomial Load

Comprehensive Load

Generic Loads


Feedback Voltage •AVR: Automatic Voltage Regulation•Fixed: Fixed Excitation (no AVR action)

Generator Operation Modes


Governor Operating Modes• Isochronous: This governor setting allows the

generator’s power output to be adjusted based on the system demand.

• Droop: This governor setting allows the generator to be Base Loaded, meaning that the MW output is fixed.


Isochronous Mode


Droop Mode


Adjusting Steam Flow


Adjusting Excitation


Swing Mode•Governor is operating in Isochronous mode•Automatic Voltage Regulator

Voltage Control•Governor is operating in Droop Mode•Automatic Voltage Regulator

Mvar Control•Governor is operating in Droop Mode•Fixed Field Excitation (no AVR action)

PF Control•Governor is operating in Droop Mode•AVR Adjusts to Power Factor Setting

In ETAP Generators and Power Grids have four operating modes that are used in Load Flow calculations.


• If in Voltage Control Mode, the limits of P & Q are reached, the model is changed to a Load Model (P & Q are kept fixed)

• In the Swing Mode, the voltage is kept fixed. P & Q can vary based on the Power Demand

• In the Voltage Control Mode, P & V are kept fixed while Q & are varied

• In the Mvar Control Mode, P and Q are kept fixed while V & are varied


Generator Capability Curve


Field Winding Heating Limit

Armature Winding Heating Limit

Machine Rating (Power Factor Point)

Steady State Stability Curve

Maximum & Minimum Reactive Power


Field Winding Heating Limit Machine Rating

(Power Factor Point)

Steady State Stability Curve



Load Flow Loading Page

Generator/Power Grid Rating Page

10 Different Generation Categories for Every Generator or Power Grid in the System

Generation Categories


X

V)*COS(

X

*VVQ

)(*SINX

*VVP

X

V)(*COS

X

*VVj)(*SIN

X

*VV

jQPI*VS

22

2121

2121

22

2121

2121

222

111

VV

VV

Power Flow


Example: Two voltage sources designated as V1 and V2 are connected as shown. If V1= 100 /0° , V2 = 100 /30° and X = 0 +j5 determine the power flow in the system.

I

var536535.10X|I|

268j1000)68.2j10)(50j6.86(IV

268j1000)68.2j10(100IV

68.2j10I

5j

)50j6.86(0j100

X

VVI

22

*2

*1

21


2

1

0

1

Real Power FlowReactive Power Flow

Power Flow1

2

V E( )

Xsin

V E( )

Xcos

V2

X

0

The following graph shows the power flow from Machine M2. This machine behaves as a generator supplying real power and absorbing reactive power from machine M1.

S


ETAP displays bus voltage values in two ways

•kV value

•Percent of Nominal Bus kV

%83.97100%

5.13

min

alNo

Calculated

Calculated

kV

kVV

kV 8.13min alNokV

%85.96100%

03.4

min

alNo

Calculated

Calculated

kV

kVV

kV 16.4min alNokV

For Bus4:

For Bus5:

Bus Voltage


Lump Load Negative Loading


Load Flow Adjustments• Transformer Impedance

– Adjust transformer impedance based on possible length variation tolerance

• Reactor Impedance– Adjust reactor impedance based on specified tolerance

• Overload Heater– Adjust Overload Heater resistance based on specified tolerance

• Transmission Line Length– Adjust Transmission Line Impedance based on possible length

variation tolerance

• Cable Length– Adjust Cable Impedance based on possible length variation tolerance


Adjustments applied

•Individual

•Global

Temperature Correction

• Cable Resistance

• Transmission LineResistance

Load Flow Study Case Adjustment Page


Allowable Voltage DropNEC and ANSI C84.1


Load Flow Example 1 Part 2


Load Flow Alerts


Bus Alerts Monitor Continuous Amps

Cable Monitor Continuous Amps

Reactor Monitor Continuous Amps

Line Monitor Line Ampacity

Transformer Monitor Maximum MVA Output

UPS/Panel Monitor Panel Continuous Amps

Generator Monitor Generator Rated MW

Equipment Overload Alerts


Protective Devices Monitored parameters % Condition reported

Low Voltage Circuit Breaker Continuous rated Current OverLoad

High Voltage Circuit Breaker Continuous rated Current OverLoad

Fuses Rated Current OverLoad

Contactors Continuous rated Current OverLoad

SPDT / SPST switches Continuous rated Current OverLoad

Protective Device Alerts


If the Auto Display feature is active, the Alert View Window will appear as soon as the Load Flow calculation has finished.

© 1996-2009 Operation Technology, Inc. – Workshop Notes: Load Flow Analysis Slide 431


Advanced LF TopicsAdvanced LF Topics

Load Flow Convergence

Voltage Control

Mvar Control


Load Flow Convergence

• Negative Impedance

• Zero or Very Small Impedance

• Widely Different Branch Impedance Values

• Long Radial System Configurations

• Bad Bus Voltage Initial Values


Voltage Control

• Under/Over Voltage Conditions must be fixed for proper equipment operation and insulation ratings be met.

• Methods of Improving Voltage Conditions:

– Transformer Replacement

– Capacitor Addition

– Transformer Tap Adjustment


Under-Voltage Example• Create Under Voltage

Condition

– Change Syn2 Quantity to 6. (Info Page, Quantity Field)

– Run LF

– Bus8 Turns Magenta (Under Voltage Condition)

• Method 1 - Change Xfmr

– Change T4 from 3 MVA to 8 MVA, will notice slight improvement on the Bus8 kV

– Too Expensive and time consuming

• Method 2 - Shunt Capacitor

– Add Shunt Capacitor to Bus8

– 300 kvar 3 Banks

– Voltage is improved

• Method 3 - Change Tap

– Place LTC on Primary of T6

– Select Bus8 for Control Bus

– Select Update LTC in the Study Case

– Run LF

– Bus Voltage Comes within specified limits


Mvar Control

• Vars from Utility

– Add Switch to CAP1

– Open Switch

– Run LF

• Method 1 – Generator

– Change Generator from Voltage Control to Mvar Control

– Set Mvar Design Setting to 5 Mvars

• Method 2 – Add Capacitor

– Close Switch

– Run Load Flow

– Var Contribution from the Utility reduces

• Method 3 – Xfmr MVA

– Change T1 Mva to 40 MVA

– Will notice decrease in the contribution from the Utility


Panel SystemsPanel Systems


Panel Boards• They are a collection of branch circuits

feeding system loads

• Panel System is used for representing power and lighting panels in electrical systems

Click to drop once on OLVDouble-Click to drop multiple panels


A panel branch circuit load can be modeled as an internal or external load

Advantages:1. Easier Data Entry2. Concise System Representation

Representation


Pin 0 is the top pin of the panel ETAP allows up to 24 external load connections

Pin Assignment


Assumptions

• Vrated (internal load) = Vrated (Panel Voltage)

• Note that if a 1-Phase load is connected to a 3-Phase panel circuit, the rated voltage of the panel circuit is (1/√3) times the rated panel voltage

• The voltage of L1 or L2 phase in a 1-Phase 3-Wire panel is (1/2) times the rated voltage of the panel

• There are no losses in the feeders connecting a load to the panel

• Static loads are calculated based on their rated voltage


Line-Line ConnectionsLoad Connected Between Two Phases of a3-Phase System

A

B

C

Load

IBCIC = -IBC

A

B

C

LoadB

IB = IBC

Angle by which load current IBC lags the load voltage = θ Therefore, for load connected between phases B and C: SBC = VBC.IBC

PBC = VBC.IBC.cos θ

QBC = VBC.IBC.sin θ

For load connected to phase B SB = VB.IBPB = VB.IB.cos (θ - 30)QB = VB.IB.sin (θ - 30) And, for load connected to phase C SC = VC.ICPC = VC.IC.cos (θ + 30)QC = VC.IC.sin (θ + 30)


3-Phase 4-Wire Panel3-Phase 3-Wire Panel1-Phase 3-Wire Panel1-Phase 2-Wire Panel

NEC SelectionA, B, C from top to bottom or left to right from the front of the panel

Phase B shall be the highest voltage (LG) on a 3-phase, 4-wire delta connected system (midpoint grounded)

Info Page


Intelligent kV CalculationIf a 1-Phase panel is connected to a 3-Phase bus having a nominal voltage equal to 0.48 kV, the default rated kV of the panel is set to (0.48/1.732 =) 0.277 kV

For IEC, Enclosure Type is Ingress Protection (IPxy), where IP00 means no protection or shielding on the panel

Select ANSI or IEC Breakers or Fuses from Main Device Library

Rating Page


Schedule Page

Circuit Numbers with Column Layout

Circuit Numbers with

Standard Layout


Description TabFirst 14 load items in the list are based on NEC 1999Last 10 load types in the Panel Code Factor Table are user-definedLoad Type is used to determine the Code Factors used in calculating the total panel loadExternal loads are classified as motor load or static load according to the element typeFor External links the load status is determined from the connected load’s demand factor status


Rating Tab

Enter per phase VA, W, or Amperes for this load.

For example, if total Watts for a 3-phase load are 1200, enter W as 400 (=1200/3)


Loading Tab

For internal loads, enter the % loading for the selected loading category

For both internal and external loads, Amp values are calculated based on terminal bus nominal kV


Protective Device Tab

Library Quick Pick - LV Circuit Breaker (Molded Case, with Thermal Magnetic Trip Device) or

Library Quick Pick – Fuse will appear depending on the Type of protective device selected.


Feeder Tab


Action Buttons

Copy the content of the selected row to clipboard. Circuit number, Phase, Pole, Load Name, Link and State are not copied.

Paste the entire content (of the copied row) in the selected row. This will work when the Link Type is other than space or unusable, and only for fields which are not blocked.

Blank out the contents of the entire selected row.


Summary Page

Continuous Load – Per Phase and Total

Non-Continuous Load – Per Phase and Total

Connected Load – Per Phase and Total (Continuous + Non-Continuous Load)

Code Demand – Per Phase and Total


Output Report


Panel Code Factors

Code demand load depends on Panel Code Factors

The first fourteen have fixed formats per NEC 1999

Code demand load calculation for internal loads are done for each types of load separately and then summed up

34786407-8-shortcircuit-iec

Documents

workshop notes

operation technology

ac fault current

phase fault condition

gen xfmr

maximum current

phase grounded fault

ungrounded fault phase