Introduction Inter-area oscillations involve wide areas of the power grid and numerous power system components. Therefore, identifying the components influencing negatively the oscillations damping is extremely important. Power system oscillations usually contain multiple frequency components (modes), which are determined by generator inertia, transmission line impedance, governor, and excitation control, etc. The oscillation behavior is sensitive to the following parameters:  The load model  The operating conditions  The presence of fast exciters  The topology

1. Power System Oscillations
Introduction
Inter-area oscillations involve wide areas of the power grid and numerous power
system components. Therefore, identifying the components influencing
negatively the oscillations damping is extremely important. Power system
oscillations usually contain multiple frequency components (modes), which are
determined by generator inertia, transmission line impedance, governor, and
excitation control, etc.
The oscillation behavior is sensitive to the following parameters:
 The load model
 The operating conditions
 The presence of fast exciters
 The topology
Nature of electromechanical oscillations
Electromechanical oscillations are of the following types:
 Intra plant mode oscillations
 Local plant mode oscillations
 Inter area mode oscillations
 Control mode oscillations
 Torsional modes oscillations between rotating plant
1. Intra plant mode oscillations
Machines on the same power generation site oscillate against each other at 2.0 to
3.0 Hz depending on the unit ratings and the reactance connecting them. This
oscillation is termed as intra plant because the oscillations manifest themselves
within the generation plant complex. The rest of the system is unaffected.
2. Local plant mode oscillations
In local mode, one generator swings against the rest of the system at 1.0 to 2.0
Hz. The impact of the oscillation is localized to the generator and the line
connecting it to the grid. The oscillation may be removed with a single or dual
input PSS that provides modulation of the voltage reference of the automatic
voltage regulator (AVR) with proper phase and gain compensation circuit.

2. 3. Inter area mode oscillations
This phenomenon is observed over a large part of the network. It involves two
coherent groups of generators swinging against each other at 1 Hz or less. The
variation in tie-line power can be large as shown in below figure. The oscillation
frequency is approximately 0.3 Hz. The damping characteristic of the inter area
mode is dictated by the tie-line strength, the nature of the loads and the power
flow through the interconnection and the interaction of loads with the dynamics
of generators and their associated controls.

3. 4. Control mode oscillations
These are associated with generators caused by poorly tuned exciters, governors,
HVDC converters and SVC controls.
5. Torsional mode oscillations
These modes are associated with a turbine generator shaft system in the
frequency range of 10-46 Hz. A typical oscillation is shown in below figure.
Usually these modes are excited when a multi-stage turbine generator is
connected to the grid system through a series compensated line. A mechanical
torsional mode of the shaft system interacts with the series capacitor at the
natural frequency of the electrical network.
Role of Oscillations in Power Blackouts
Inter area oscillations have led to many system separations but few wide-scale
blackouts. Noteworthy incidents related to Low Frequency Oscillation are:
 United Kingdom (1980), frequency of oscillation about 0.5 Hz.
 Taiwan (1984, 1989, 1990, 1991, 1992), frequency of oscillation around
0.78 – 1.05 Hz.
 West USA/Canada, System Separation (1996), frequency of oscillation
around 0.224 Hz.
 Scandinavia (1997), frequency of oscillation about 0.5 Hz.
 China Blackout on 6 March (2003), frequency of oscillation around 0.4 Hz.
 US Blackout on 14 August (2003), frequency of oscillation about 0.17 Hz.

4.  Italian Blackout on 28 September (2003), frequency of oscillation about
0.55 Hz.
 The inter area oscillations in the Western Electricity Co-ordination Council
(WECC) caused Blackout in 1996 clearly identifies inadequate damping
Some other constraints related to inter area oscillations are:
 The inter area oscillations limit the flow of Active power transfer on
Tie lines between coherent generator group.
 The inter area oscillations increase the stress on generator prime
movers.
Additional Causes of Oscillations
Power system oscillations are started when changes, such as the loss of an
element or a load adjustment, are made to the power system. In addition, certain
characteristics or equipment in the power system can either cause or effect power
system oscillations. These causes are:
 Cyclic Loads( Furnaces)
 Governor Control Systems
 HVDC Systems
 Generator Pole Slipping
1. Cyclic Loads
Power system load constantly changes. Most of the time, the changes are small
when compared to the total system load. At times, however, major loads may be
added and removed in a cyclic nature. From a power system perspective these
cyclic loads are similar to power oscillations. Large cyclic loads are especially
dangerous if connected to weak transmission systems. The impacts of large
cyclic loads can be minimized by providing dedicated feeders from the main
transmission system.
2. Governor Control System
Generator governor control systems arrest frequency deviations. Governors have
droop settings to allow generators to share and respond to load changes in
proportion to their size. If the droops are set incorrectly, generators could
compete for load changes. The result is power oscillations as the system’s
generators fight each other to make load changes. For example, assume that an
isolated system with several generators operates all governors with 0% droop.
When load changes occur, every generator tries to respond. The result is an
oversupply of generation. Next, every generator cuts generation. Power and
frequency oscillations result as the system’s generators repeatedly increase then
decrease generation levels.

5. 3. HVDC Systems
HVDC (high voltage direct current) systems can cause frequency and power
oscillations. The power converters at the ends of an HVDC transmission line
convert power between AC and DC. The HVDC control system’s operation must
be coordinated with AC system generation levels to ensure the HVDC does not
cause AC system frequency disturbances.
For example, assume an HVDC control system is functioning improperly. The
HVDC converter is absorbing power from the AC system in an unexpected and
undesired manner. The AC system generation is not coordinated with the power
absorbed by the HVDC converter.
4. HVDC Modulation
HVDC systems can also be used to dampen AC system power oscillations. The
power that flows in an HVDC system is removed from the AC system at the
rectifier end of the HVDC. Assume that a low frequency oscillation is occurring
in the AC system. If power could be removed from the AC and input to the
HVDC at the proper frequency, the AC system oscillation could be dampened or
modulated. HVDC modulation systems remove AC system energy in such a
manner as to dampen AC system oscillations. Several of the HVDC systems in
use within NERC use forms of HVDC modulation.
5. Generator Pole Slipping
Power transfer from a generator is dependent on the voltage phase angle between
the generator and the system. A generator transmits the maximum amount of
MW to the system when the angle is 90. When the angle is 0, the MW output
from the generator is zero. If the angle goes beyond 90 the generator may lose
control of its torque angle and enter an unstable condition. If the MW output of a
generator is less than its mechanical power input and the torque angle is greater
than 90, there may be too little strength in the magnetic bond that holds the rotor
in-step with the stator. The rotor spins out of control with the rotor field poles
slipping past the stator windings. This condition is called slipping poles. When a
generator slips poles it alternately sends power (both MW and Mvar) out to the
system and absorbs it from the system. This creates a very large angle and power
oscillation.

6. Role of the System Operator
A system operator may from time to time detect oscillations in the power system.
Most oscillations are damped by the system with no need for system operator
response. However, some oscillations may sustain themselves or grow in
magnitude until a system operator response is needed.
Detecting Oscillations
During the normal monitoring duties of a system operator, oscillations may be
detected through PMU or SCADA indication.
Responding to Oscillations
The typical case is that a system operator does not become aware of oscillations
unless a severe disturbance occurs or the oscillations reach large enough
amplitudes to register on strip-chart recorders. Once a system operator
determines that oscillations are present, the following guidelines are offered:
 The most effective tool to preventing and controlling oscillations is to hold
power transfers within established
limits. A weak power system (excessive transfer or elements out-of-service
makes any system weak) is more susceptible to oscillations than a strong power
system.
 A system operator can strengthen a power system by either returning
elements to service or reducing power transfers. If lines are out-of service,
the system operator should return the lines to service as soon as possible.
 If series capacitors are out-of-service a system operator should consider
returning the capacitors to service.
 Adjusting system generation patterns may be an option for reducing power
transfers.
 Shedding load is an option that all system operators are empowered to use
but typically only after less drastic options are attempted.
 Maintaining high system voltages also strengthens the system as it allows a
reduction in phase angle.
Generator voltage regulators should be in automatic mode to ensure
dynamic reactive support when needed.
 System operators should ensure that all available PSS are in-service as
intended. PSS are designed to dampen low frequency oscillations, and
system transfer limits may be dependent on maintaining PSS in-service.
 If oscillations are strongest in the area of a particular generator consider
reducing load on that generator or increasing the excitation current. If the
oscillations persist and could lead to serious trouble consider tripping the
offending generator. A system operator must often rely on power plant

7. operators for early detection of generator oscillations. The staff at the plant
is often the first to know if their plant is oscillating.
 If oscillations are strongest in the area of a particular load, the load may be
the problem. Is it a cyclic load? Are large motor loads causing the area
power system to oscillate? A system operator may have to trip a load to rid
the system of these type oscillations.
Tools to control Inter area Oscillations.
 Tuning of Power System Stabilizers (PSSs)
PSSs are the most commonly used devices for enhancing the damping of the
inter-area modes of oscillations. A PSS in combination with an AVR uses the
auxiliary stabilizing signals for producing a damping torque component which
controls the excitation system of the generating units. Commonly used signals for
the PSS include changes in shaft speed, terminal frequency and output power. A
PSS provides supplemental damping to the oscillation of synchronous machine
rotors through the generator excitation.
 Install STATCOMM, UPCs Unified Power Controllers, SVC like FACTS
technologies.
 Install Energy Storage Devices ESDs
 Install Supplementary Damping Controllers (SDCs)
 Install (Thyristor Controlled Series Capacitors, TCSC)
 Power Trading is also a good solution