kupdf.net_shortcircuit-iec as per ir.pdf

©1996-2009 Operation Technology, Inc. – Workshop Notes: Short-Circuit IEC
Short-Circuit Analysis
IEC 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)
– I2
t 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
-p
h
a
s
e
(85% of all faults).
•In industrial systems the situation IL
-G
> I3
-p
h
a
s
e
is rare.
Typically IL
-G
≅ .87 * I3
-p
h
a
s
e
•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

)
t
Sin(
Vm
v(t) θ
ω +
∗
=
i(t)
v(t)
Short-Circuit Phenomenon




 



 



 


 

Offset)
(DC
Transient
State
Steady
t
)
-
sin(
Z
Vm
)
-
t
sin(
Z
Vm
i(t)
(1)
)
t
Sin(
Vm
dt
di
L
Ri
v(t)
L
R
-
e
×
×
+
+
×
=
+
×
=
+
=
φ
θ
φ
θ
ω
θ
ω
expression
following
the
yields
1
equation
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

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 Faults
L-G Faults

Symmetrical Components
L-G Faults

Sequence Networks

0
Z
Z
Z
V
3
I
I
3
I
0
2
1
efault
Pr
f
a
f 0
=
+
+
×
=
×
=
g
Z
if
L-G Fault Sequence
Network Connections

2
1
efault
Pr
f
a
a
Z
Z
V
3
I
I
I 1
2
+
×
=
−
=
L-L Fault Sequence Network
Connections

0
Z
Z
Z
Z
Z
V
I
I
0
I
I
I
2
0
2
0
1
efault
Pr
f
a
a
a
a 0
1
2
=








+
+
=
=
=
+
+
g
Z
if
L-L-G Fault Sequence
Network Connections

Transformer Zero Sequence Connections

grounded.
solidly
are
er
transform
Connected
Y/
or
Generators
if
case
the
be
may
This
I
:
then
true
are
conditions
this
If
&
:
if
greater
be
can
faults
G
-
L
case.
severe
most
the
is
fault
phase
-
3
a
Generally
1
f3
1
0
2
1
∆
<
<
=
φ
φ f
I
Z
Z
Z
Z
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

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
include:
contributions
•Phase Voltages
& Reports

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
2
t
Gen
I2
t
Motor
Xfmr
I2
t
Cable
I2
t

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
t
A
T 234
0.0297log
T 234
Ι
=
 
+
 
+
 
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 amps
t = Time of short circuit in seconds
T1
= Initial operation temperature (750
C)
T2
=Maximum short circuit temperature
(1500
C)

Cable Short-Circuit Heating Limits
Recommended
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 any
lowest temperature rating of any connected termination
connected 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
– 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 Category
ANSI/IEEE C-57.109

Transformer Categories I, II

Transformer Categories III

Transformer
t
(sec)
I (pu)
Thermal
200
2.5
I
2
t = 1250
2
25
Isc
Mechanical
K=(1/Z)
2
t
(D-D LL) 0.87
(D-R LG) 0.58
Frequent Fault
Infrequent Fault
Inrush
FLA

M
Any Location – Non-Supervised

• 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
Protective system Winding and/or power system
grounded neutral grounded
Winding and/or power system
neutral ungrounded
Up to 10 MVA
Above 10 MVA
Up to 10 MVA Above
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 and
Infrequent 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
Inciden ce Zone*

Motor Protection
– 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 asymmetrical
asymmetrical 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 Motor
Ratings Range of ratings
Continuous 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 elements
3 CB
Fuses 3 FU
Undervoltage: 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
R
HP
C
FLC
TER
E
UM

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
Ratings Class El
(without
fuses)
Class E2 (with
fuses)
Nominal system voltage 2300-6900 2300-6900
Horsepower 0-8000 0-8000
Symmetrical MVA interrupting
capacity at nominal
system voltage
25-75 160-570
Types of Protective Devices Quantity NEMA Designation
Overload, or locked Rotor, or
both:
Thermal overload relay
TOC relay
IOC relay plus time delay
3
3
3
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
I2
T
(49)
MCP (50)
(51)
ts
tL
R
LRAs LRAasy
m

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 Action
Current
(peak
amps)
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
Peak
Let-Through
Amperes
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 2
CB 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)

Question
What 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 kcmil
CU - EPR
CB
Isc = 30,000 A
6 %
50/51 Relay: IFC 53
CT 800:5

Solution
A
Inrsuh 328
,
8
694
12
I =
×
=
A
338
.
4
800
5
I
I L
R =
×
=
Transformer: A
kV
kVA
L 694
16
.
4
3
000
,
5
I =
×
=
IL
CT
R
IR
Set Relay:
A
55
1
.
52
800
5
328
,
8
)
50
(
1
)
38
.
1
(6/4.338
0
.
6
4
.
5
338
.
4
%
125
= >
=
×
=
=
=
=
×
=
A
Inst
TD
A
TAP
A

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

Answer
A
t
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 Stability
Something between mechanical system and
electrical system – energy conversion
• It is a Electromechanical Phenomenon
Time frame in milliseconds
• All Synchronous Machines Must Remain in
Synchronism with One Another
Synchronous generators and motors
This is what system stable or unstable means

• Torque Equation (generator case)
T = mechanical torque
P = number of poles
φ a
ir = air-gap flux
Fr = rotor field MMF
δ = rotor angle

• Swing Equation
M = inertia constant
D = damping constant
Pm
e
c
h = input mechanical power
Pe
le
c = output electrical power

What Causes System Unstable
• From Torque Equation
T (prime mover)
Rotor MMF (field winding)
Air-Gap Flux (electrical system)
• From Swing Equation
Pmech
Pelec
Different time constants in mechanical and
electrical systems

What Causes System Unstable
• In real operation
Short-circuit
Loss of excitation
Prime mover failure
Loss of utility connections
Loss of a portion of in-plant generation
Starting of a large motor
Switching operations
Impact loading on motors
Sudden large change in load and generation

Effects When System Is Instable
Case 1: Steady-state stable
Case 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 δ = -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
∀ δ 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: δ < 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
• Fault
3-phase and single phase fault
Clear fault
Critical Fault Clearing Time (CFCT)
Critical System Separation Time (CSST)
• Bus Transfer
Fast load transferring
• Load Shedding
Under-frequency
Under-voltage
• Motor Dynamic Acceleration
Induction motor
Synchronous motor

• Critical Fault Clearing Time (CFCT)
• Critical Separation Time (CSST)
unstable
unstable
Cycle
Clear fault
Clear fault
1 cycle
unstable
stable 1 cycle
Clear fault
Clear fault
CFCT
Fault
unstable
unstable
Cycle
1 cycle
unstable
stable
1 cycle
CSST
Separation
Separation
Separation
Separation
Fault

-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
Ttra
n
s
fe
r ≤ 10 cycles
δ ≤ 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
δ

• Load Shedding

• Motor Dynamic Acceleration
Important for islanded system operation
Motor starting impact
Generator AVR action
Reacceleration

• 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 separation
Out-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(
13
cos
13
1
11
cos
11
1
7
cos
7
1
3
cos
5
1
(cos
3
2
1
h
h
h
d
ac
t
h
I
t
t
t
t
t
I
I
Φ
+
⇒
+
−
+
−
=
∑
∞
=
ω
ω
ω
ω
ω
ω
π

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

(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

(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

(cont’d)
• Switchgears
– Increased heating and losses
– Reduced steady-state current carrying capability
– Shortened insulation components life
• Relays
– Possibility of misoperation
• Metering
– Affected readings

(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 transformer
CAF = X/R = 7*0.0069/0.0012 =40.25
Resonant Current = 55*40.25 = 2214 A

Parallel Resonance (cont’d)
Cause:
Impacts: 1. Excessive capacitor fuse
operation
2. Capacitor failures
3. Incorrect relay tripping
4. Telephone interference
5. 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
THD
i
∑
∞
=
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
• Individual Harmonic Distortion (IHD)
- Ratio of a given harmonic to fundamental
- To track magnitude of individual harmonic
1
F
F
IHD i
=
• Root Mean Square (RMS) - Total
- Root Mean Square of fundamental plus all
harmonics
- Equal to fundamental RMS if Harmonics are
zero
∑
∞
=
1
2
i
F
RMS

Harmonic Distortion
• 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
i
F
ASUM

Harmonic Distortion
• 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
i
i
F
F
W
TIF

Harmonic Distortion
• I*T Product (I*T)
– A product current components (fundamental
and harmonics) and weighting factors
∑
=
⋅
=
•
H
h
h
h T
I
T
I
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 the
third harmonic
(h = 3, 9, 15, 21, …)
• Important issue for
grounded-wye systems
with 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
• 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
• Either standard phase shift or special phase
shift can be used

Reducing System
• 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 Starting
Dynamic 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 Ts
t <Tlo
a
d at s=1, then motor will not start
• If Tm=Tlo
a
d 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 frequency
S = (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
Load(kva)
Terminal Voltage
Terminal
Current
Terminal Voltage
0.8 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 Voltage
0.9 1.0
.8 kva
LR
Vt (pu)
Vt (pu)
.9 I LR
I LR
P
It
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 wm
0
T
T 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.
T
em
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.
T
em
W′S WS
Wm
0
2 P - poles
P - poles
P
R
Load
Nro. of poles variation
W′S =
WS
___
2

Rotor Z Variation
• Increasing rotor Z will shift peak torque towards lower
speed.
S
R
Q
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
1. 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:
POWER
FACTOR
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
MCC
M
Autotransformer starter
line
Vmcc
EX. 50% Tap
VMCC
50%
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
VMCC
50%
tap
5VMCC VM
RLR
XLR
RL XL
PFST ( with resistor) = 1-[pu tap setting ]² * [ 1- (PFST without resistor)²]
= 1- (0.5)² * [1-(PFST)²]

VMCC
50%
tap
5VMCC VM
RLR
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 statusclosing operation
– Close statusopening operation

MOV Modeling II
• Five stages of operation
Opening Closing
Acceleration 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
STALL
ACCL
I
MOV Voltage Limit
• Effect of Voltage Limit Violation
Tacc Tpos
Travel Tstl

TEMA 6

Short-Circuit
ANSI 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
-p
h
a
s
e
(85% of all faults).
•In industrial systems the situation IL
-G
> I3
-p
h
a
s
e
is rare.
Typically IL
-G
≅ .87 * I3
-p
h
a
s
e
•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)
– I2
t 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

)
t
Sin(
Vm
v(t) θ
ω +
∗
=
i(t)
v(t)
Short-Circuit Phenomenon




 



 



 


 

Offset)
(DC
Transient
State
Steady
t
)
-
sin(
Z
Vm
)
-
t
sin(
Z
Vm
i(t)
(1)
)
t
Sin(
Vm
dt
di
L
Ri
v(t)
L
R
-
e
×
×
+
+
×
=
+
×
=
+
=
φ
θ
φ
θ
ω
θ
ω
expression
following
the
yields
1
equation
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)
Models
All sources are modeled by an internal
voltage behind its impedance.
E = Prefault Voltage
R = Machine Armature Resistance
X = Machine Reactance (X”d, X’d, Xd)
Sources and Models of Fault
Currents in ANSI Standards

Synchronous Reactance
Transient Reactance
Subtransient Reactance
Synchronous Generators
Synchronous Generators are modeled
in three stages.
Synchronous Motors &
Condensers
Act as a generator to supply fault
current. This current diminishes as the
magnetic field in the machine decays.
Induction Machines
Treated the same as synchronous
motors except they do not contribute to
the fault after 2 sec.
Electric Utility Systems
The 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
Utility
X”d X”d X”d
Turbo Generator
X”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
Condenser
X”d X”d
α
Synchronous Motor
X”d 1.5*X”d α
Reactance Representation for
Utility 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
α
Reactance Representation for Induction
Machine
Note: X”d = 1 / LRCp
u

½ Cycle Currents
(Subtransient Network)
1 ½ to 4 Cycle Currents
(Transient Network)
HV Circuit Breaker
Closing and Latching
Capability
Interrupting
Capability
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 RMS
Crest
C&L RMS
C&L RMS
HV Bus Asymmetrical RMS
Crest
Asymmetrical RMS
Crest
LV Bus Symmetrical RMS
Asymmetrical RMS
Symmetrical RMS
Asymmetrical RMS
Comparisons of Momentary capability (1/2 Cycle)
Momentary Multiplying
Factor

SC Current Duty Device Rating
HV CB
Adj. Symmetrical RMS* Adj. Symmetrical RMS*
LV CB & Fuse
Adj. 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 (Im
o
m
,rm
s
,s
y
m
) using ½ Cycle Network.
• Calculate X/R ratio and Multiplying factor MFm
• Im
o
m
,rm
s
,A
s
y
m=
MFm
* Im
o
m
,rm
s
,s
y
m
HV CB Closing and
Latching Duty

Calculate 1½ to 4 Cycle Current (Im
o
m
,rm
s
,s
y
m
) 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 = IR
e
m
o
te
/ IT
o
ta
l
IT
o
ta
l
= IL
o
ca
l
+ IR
e
m
o
te
(NACD = 0 if all local & NACD = 1 if all remote)
• Calculate Iin
t,rm
s
,a
d
j
= MFi
* Iin
t,rm
s
,S
y
m
m
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 Iin
t,rm
s
,s
y
m
m
from ½ Cycle Network.
• Same procedure to calculate Iin
t,rm
s
,a
s
y
m
m
as for CB.
Fuse Interrupting Duty

L-G Faults
L-G Faults

Symmetrical Components
L-G Faults

Sequence Networks

0
Z
Z
Z
V
3
I
I
3
I
0
2
1
efault
Pr
f
a
f 0
=
+
+
×
=
×
=
g
Z
if
L-G Fault Sequence
Network Connections

2
1
efault
Pr
f
a
a
Z
Z
V
3
I
I
I 1
2
+
×
=
−
=
L-L Fault Sequence Network
Connections

0
Z
Z
Z
Z
Z
V
I
I
0
I
I
I
2
0
2
0
1
efault
Pr
f
a
a
a
a 0
1
2
=








+
+
=
=
=
+
+
g
Z
if
L-L-G Fault Sequence
Network Connections

Transformer Zero Sequence Connections

grounded.
solidly
are
er
transform
Connected
Y/
or
Generators
if
case
the
be
may
This
I
:
then
true
are
conditions
this
If
&
:
if
greater
be
can
faults
G
-
L
case.
severe
most
the
is
fault
phase
-
3
a
Generally
1
f3
1
0
2
1
∆
<
<
=
φ
φ f
I
Z
Z
Z
Z
Solid Grounded Devices
and L-G Faults

•L-G Faults
•L-L-G Faults
•L-L Faults
include:
contributions
•Phase Voltages
& Reports

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

Tolerance
Length
Length
Tolerance
Length
Length
Tolerance
Z
Z
onLine
Transmissi
onLine
Transmissi
Cable
Cable
r
Transforme
r
Transforme
)
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
e
temperatur
Conductor
Tc
C
in
e
temperatur
base
Conductor
Tb
e
temperatur
operating
at
Resistance
R'
re
tempereatu
base
at
Resistance
R
Tb
Tc
R
R
Tb
Tc
R
R
BASE
BASE
Alumi
BASE
Copper
=
=
=
=
+
+
=
+
+
=
)
1
.
228
(
)
1
.
228
(
*
'
)
5
.
234
(
)
5
.
234
(
*
'
'
Temperature Correction can be applied
Individually or Globally
Temperature Correction

Transformers
T1 X/R
PS =12
PT =12
ST =12
T2 X/R = 12
Power Grid U1
X/R = 55
Lump1
Y open grounded
Gen1
Voltage Control
Design Setting:
%Pf = 85
MW = 4
Max Q = 9
Min 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

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 transferring
Load 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
φ a
ir = air-gap flux
Fr = rotor field MMF
δ = rotor angle

Swing Equation

Synchronous Machines
(cont’d)
• Swing Equation
M = inertia constant
D = damping constant
Pm
e
c
h = input mechanical power
Pe
le
c = 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)

(cont’d)

(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: δ < 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: δ < 180°during swing

Generator Modeling
• Machine
Equivalent 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

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

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 Concepts
System Concepts

jQ
P
I
V
S
S
I
V
S
L
L
L
N
+
=
×
=
×
=
=
*
1
3
*
1
3
3 φ
φ
φ
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
2
B
B
B
B
B
MVA
)
kV
(
Z
kV
3
kVA
I
=
=
B
actual
pu
B
actual
pu
Z
Z
Z
I
I
I
=
=
B
actual
pu
B
actual
pu
S
S
S
V
V
V
=
=














=
=










=
=
B
2
B
B
B
B
B
S
V
Z
V
3
S
I
ZI
3
V
VI
3
S 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
2
B
1
B kV
2
N
1
N
kV =
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
R
X
1
R
X
Z
X






+






×
=
Transformer T7: The following equations are used to find
the impedance of transformer T7 in 100 MVA base.






=
R
X
x
R
pu
pu
1
B
kV
2
B
kV

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
.
0
X
2
pu =
+
= 005336
.
0
14
.
12
06478
.
0
Rpu =
=
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
.
1
j
1115
.
0
(
5
100
5
.
13
8
.
13
)
06478
.
0
j
10
33
.
5
(
S
S
V
V
Z
Z
2
3
o
B
n
B
2
n
B
o
B
o
pu
n
pu +
=












+
×
=
















= −
38
.
135
j
15
.
11
Z
100
Z
% pu +
=
×
=
0695
.
4
31
.
3
5
.
13
2
N
1
N
kV
V
utility
B =
=






= 165608
.
0
100
)
0695
.
4
(
MVA
V
Z
2
2
B
B =
=
=

8
.
603
j
38
.
60
Z
100
Z
% pu +
=
×
=
)
0382
.
6
j
6038
.
0
(
1656
.
0
)
1
j
1
.
0
(
Z
Z
Z
B
actual
pu +
=
+
=
=
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 Analysis
Load 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 = Slo
a
d / VR
Calc: Vd = I * Z
Re-Calc VR = Vs - Vd
Calculation Process
• Non-Linear System
• Calculated Iteratively
– Assume the Load
Voltage (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.
1. 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
kVA
FLA
kV
kVA
FLA
Eff
PF
HP
Eff
PF
kW
kVA
Rated
Rated
Rated
Rated
=
×
=
×
×
=
×
=
φ
φ
1
3
3
7457
.
0
Where PF and Efficiency are taken at 100 %
loading conditions
kV
kVA
1000
I
)
kV
3
(
kVA
1000
I
kVA
kW
PF
)
kVar
(
)
kW
(
kVA
1
3
2
2
×
=
×
×
=
=
+
=
φ
φ
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
Mode
•Fixed Field Excitation (no AVR
action)
PF Control
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 & θ are
varied
•In the Mvar Control Mode, P and Q are kept fixed while V & θ 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
*V
V
Q
)
(
*SIN
X
*V
V
P
X
V
)
(
*COS
X
*V
V
j
)
(
*SIN
X
*V
V
jQ
P
I
*
V
S
2
2
2
1
2
1
2
1
2
1
2
2
2
1
2
1
2
1
2
1
−
−
=
−
=






−
−
+
−
=
+
=
=
δ
δ
δ
δ
δ
δ
δ
δ










∠
=
∠
=
2
2
2
1
1
1
V
V
V
V
δ
δ
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
var
536
5
35
.
10
X
|
I
|
268
j
1000
)
68
.
2
j
10
)(
50
j
6
.
86
(
I
V
268
j
1000
)
68
.
2
j
10
(
100
I
V
68
.
2
j
10
I
5
j
)
50
j
6
.
86
(
0
j
100
X
V
V
I
2
2
*
2
*
1
2
1
=
×
=
−
−
=
+
−
+
=
+
−
=
+
−
=
−
−
=
+
−
+
=
−
=

2
1
0
1
Real Power Flow
Reactive Power Flow
Power Flow
1
2
−
V E
⋅
( )
X
sin δ ∆
( )
⋅
V E
⋅
( )
X
cos δ ∆
( )
⋅
V
2
X
−
π
0 δ ∆
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
.
97
100
%
5
.
13
min
=
×
=
=
al
No
Calculated
Calculated
kV
kV
V
kV 8
.
13
min =
al
No
kV
%
85
.
96
100
%
03
.
4
min
=
×
=
=
al
No
Calculated
Calculated
kV
kV
V
kV 16
.
4
min =
al
No
kV
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 Line
Resistance
Load Flow Study Case
Adjustment Page

Allowable Voltage Drop
NEC 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 Topics
Advanced 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 Systems
Panel 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 OLV
Double-Click to drop multiple panels

A panel branch circuit load can be modeled as an
internal or external load
Advantages:
1. Easier Data Entry
2. 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 Connections
Load Connected Between Two Phases of a
3-Phase System
A
B
C
Load
IB
C
IC = -IB
C
A
B
C
LoadB
IB = IB
C
Angle by which load current IB
C
lags the load voltage = θ°
Therefore, for load connected between phases B and C:
SB
C
= VB
C
.IB
C
PB
C
= VB
C
.IB
C
.cos θ
QB
C
= VB
C
.IB
C
.sin θ
For load connected to phase B
SB = VB.IB
PB = VB.IB.cos (θ - 30)
QB = VB.IB.sin (θ - 30)
And, for load connected to phase C
SC = VC.IC
PC = VC.IC.cos (θ + 30)
QC = VC.IC.sin (θ + 30)

3-Phase 4-Wire Panel
NEC Selection
A, 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 Calculation
If 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 Tab
First 14 load items in the list are based on NEC 1999
Last 10 load types in the Panel Code Factor Table are user-defined
Load Type is used to determine the Code Factors used in calculating the total
panel load
External loads are classified as motor load or static load according to the element
type
For 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

kupdf.net_shortcircuit-iec as per ir.pdf

More Related Content

Similar to kupdf.net_shortcircuit-iec as per ir.pdf (20)

Recently uploaded (20)

kupdf.net_shortcircuit-iec as per ir.pdf