Wide area monitoring systems (WAMS) are essentially based on the new data acquisition technology of phasor measurement and allow monitoring transmission system conditions over large areas in view of detecting and further counteracting grid instabilities.

1. WAMS Applications

2. CONTENTS
1 SITUATIONALAWARENESS
2 SIGNAL TRENDING ANDALARMING
3 REAL-TIME STABILITY MONITORING
4 STATE ESTIMATION
5 FAULT DETECTION AND LOCATING
6 SPECIAL PROTECTIONS SCHEME
7 WIDE-AREA CONTROL FUNCTIONS

3. 1- SITUATIONAL AWARENESS

5. What is WAMS ?
• It’s a collective technology to monitor power system
dynamics in real time, identify system stability
related weakness and helps to design and implement
countermeasures . (IEEE)

6. • It is based on Phasor measurement units (PMUs)
which can deliver precisely time synchronized values
of voltage and current phasors and other power
system related quantities like frequency, breaker
positions.

7. Need of WAMS
• In order to avoid major regional blackouts such as those
occurred in North America and Canada in 2003.
• When constant monitoring applications are available
immediate action can be taken if some failures are
detected.

8. Components of WAMS
• Phasor Measurement Unit (PMU)
• Phasor Data Concentrator(PDC)
• Global Positioning System (GPS for Time
Synchronization of the phasors)
• Communication channel( Preference to optical fiber
cable )

9. • Visualization and analysis tools
• Wide area situational awareness system.
• Wide area protection and control

10. Advantage of PMU

11. They are devices which use synchronization signals from
the global positioning system (GPS) satellites and provide
the phasor voltages and currents measured at a given
substation.
A phasor is a complex number that represents both the
magnitude and phase angle of the sine waves found in
electricity.
PMU can have different Data Rate i.e. 60, 30, 10 frame
per second.
PMU
Input
Secondary
sides ofthe
3Φ P.T.or
C.T.
Corresponding
Voltage or
Current
phasors
Output

12. Lets Have a closer view of SCADA and PMUs

13. SCADA and PMU

14.  SCADA can only provides steady, low sampling density,
and non synchronous information of the network.
 Controlling centre cannot know the dynamic operation
states of the system.
 Instant action cannot be taken in case of failures.
 WAMS enables us to observe the power system
synchronously in more elaborate time scale.
 WAMS requires data to be sent and captured at very
fast rate.

16. Technology can Change what we See : Lets See How

17. On our Path to Make the grid Smart and safely
operate we have :
• PMU data
• RTU data
• GIS data
• Outage data
• Market data
So now We have BIG DATA
Need to Analyse  Process  Visualize  Operate

18. Lets visit the world of PMU Advancement
• More Visual Aids rather than Watching Number for
Operators : A change that is required with increasein
the system Complexity and Big Data
Real-time Applications
• Wide-area situational awareness
• Frequency stability monitoring and trending
• Power oscillation monitoring

19. • Voltage monitoring and trending
• Alarming and setting system operating limits, event
detection and avoidance
• Resource integration
• Real time Dynamic State estimation
• Dynamic line ratings and congestion management
• Outage restoration
• Operations planning

20. Offline Application
• Base lining power system performance
• Event analysis
• Dynamic system model calibration and validation
• Power plant model validation
• Load characterization
• Special protection schemes and islanding
• Primary frequency (governing) response

21. WAMS in Western Region
• 5 PMUs (1 Nos. Bhadrawati, 2 Nos. Jabalpur, 2Nos
Raipur)
• Different Vendors: GE,SEL,NI (More on way like
Hitachi, Qualitrol)
• PDC : OpenPDC, GE PDC (planning for iPDC and OSIpi)

22. Application under development
• Oscillation Monitoring Systems
• Model validation.
• Dynamic Line Loadability.
• Voltage stability analysis.
• Dynamic & hierarchical State estimation
• Wide area situational awareness.
• Online stability assessment – Early warning.

23. Situational Awareness (SA)
• A simple definition of SA is “knowing what is going on
around you.” A more detailed definition involves
comprehending enough of the complex system status to
make informed decisions in a time critical manner to
positively affect the system state.

24. • A key question then is whether the PMU data helps
operators and engineers make better, more timely
decisions; or does it just add to the information clutter,
wasting time.

25. Where We’ve Come From

26. Moving Forward Seventy Years

27. Where We Are At

28. Adding in PMUs
• SCADA analog measurements have been used for several
decades with scan rates of once every few seconds
• PMUs add much faster scan rates (30 samples per
second) and direct measurement of bus angle across
systems

29. To improve SA, PMU information can be used in a number of
ways Real-time, direct visualization, in essentially a raw
form (i.e., bus angles).
• Real-time, but embedded in other applications, such as SE
or for assessing system dynamics
• Real-time, but embedded in data-mining applications to
give historical info in real-time
• Off-line, to develop better system models and
understanding; this includes post-event analysis

30. What Does A Bus Angle Indicate?
θ= B-1P
• The equation indicates that the angle at a particular
bus is the vector product of a row of the inverse of the
B matrix with the net power injection vector P.
• B matrix is sparse, its inverse is not.
• Angles are given with respect to a system reference

31. A Power Flow Bus Angle Contour

34. State of Art: Angle Contours

35. State-of-Art: Contours (EPRI)

36. State-of-Art: Dials and Pie Charts

37. State-of-Art: Dynamic Line Formatting

39. SIGNAL TRENDING ANDALARMING
• ABB’s PSGuard Wide Area Monitoring system (WAMS) is a
corner-stone technology to improve the visibility and
situational awareness in both today’s and the future
electrical grids. PSGuard collects, stores, transmits and
analyzes critical data from key points across the power
networks and over large geographical areas.

40. Its state-of-the-art portfolio of Wide Area Monitoring
applications is designed to detect ab-normal system
conditions and evaluate large area disturbances in order
to preserve system integrity and maintain acceptable
power system performance.

41. Key benefits of PSGuard wide area monitoring
system
Improved power system operation
• The operators are additionally provided with online
information on the power system status at the right time.
Better use of existing equipment
• The online information on the current power system status
(e.g. remaining transmission capacity) allows transmission
lines to be operated closer to the safety limits. Therefore,
more power can be transmitted over existing transmission
lines and the construction of new lines can be deferred.

42. Increased power transmission capacity
• Instability limits that are calculated online permit an
increase in transmission capacity for power
transmission lines while maintaining the same level of
security. The additional transmission capacity can
increase profitability.

43. Lowered risks of power system instabilities
• Early recognition of incipient power system instabilities
allows counter measures to be initiated early, so that
the spreading of large area disturbances can be
prevented. This helps to significantly reduce the costs
caused by outages.

44. Improved power system planning
• Enhanced knowledge about the dynamic power system
behavior enables countermeasures to be prepared more
precisely, and provides improved data for the planning
of system extensions.

46. SIGNAL TRENDING AND ALARMING
• The PSGuard operator workplace provides
powerful views of the wide area system,
allowing the system operator to easily and
quickly identify network disturbances in real
time as well as evaluate past events for post-
mortem analysis.

47. System Supervision
• The PSGuard System Supervision enables the operator
to navigate to Phasor Measurement Units (PMUs)
directly and provides all of the necessary information
to supervise the condition of the PMU. The PMU status,
communication status as well as GPS synchronization
can be viewed at a glance.

49. Dynamic Trend Display
• The PSGuard trend display enables operators to observe
the development of events in real time. The trend
display offers access to historical data and can be
selected for all elements in the system. Standard
functions of PSGuard trends include:
− Individual axis scaling
− Adjustable time scope
− Online integration of new traces
− Zooming, time and value rulers, etc.

50. • Trend views are available for all PSGuard application
outputs as well as raw measurement values. Which
means that every measured and every calculated value
can be analyzed and compared visually over long time
spans, both in real-time or offline.

51. Events and Alarms
• PSGuard provides notifications through its integrated
Events and Alarms pane. User defined events and
alarms provide the operator with the information
needed to react immediately to events in the system.

53. Single Line Display
• The PSGuard single-line representation provides the
operator with an overview of the power system,
including complete access to the Wide Area Monitoring
information in his network using easy-to-understand
symbols and buttons to access detailed information in
the system.

55. REAL-TIME STABILITY MONITORING
Voltage Stability Monitoring
• The Voltage Stability Monitoring (VSM) application
provides power system operators with valuable online
information to assess the present power margin with
respect to voltage stability. A power margin is the
amount of additional active power that can be
transported on a transmission corridor without
jeopardizing voltage stability.

56. This monitoring functionality and its outputs are intended
as decision support for operators. Actions the operator
may take to improve voltage stability may range from
generation rescheduling or actions on the reactive
compensation, blocking of tap changers in the load
area or in extreme cases load shedding.

57. • The VSM application is designed to monitor transmission
corridors and it therefore delivers the dynamic current
and voltage phasors and resulting calculations in real
time.

58. Benefit:
Early warning against voltage collapses, Immediate stop of
cascading effects, and Protection against uprising voltage
instabilities.

59. STATE ESTIMATION
• The essential tool used by system operators for real
time analysis of the power system is the State
Estimator (SE).
• The SE acts to filter errors in the system measurements
by computing the optimal bus-bar voltage state based
on the redundant raw information available.

60. • This voltage estimate is used to monitor and analyze
the current static state of the system. Because of the
SE’s inherent data concentration, it has been proposed
that information sharing for visualization be placed
post-SE processing, as illustrated in figure.
• Recently, such a wide-area state estimate (WASE) be
used as the tool used for wide area monitoring and
visualization of the power system.

61. Post-processing Wide Area Visualization

62. • The classical state estimator currently used is based on
SCADA (Supervisory Control and Data Acquisition)
measurements.
• Weaknesses of the SCADA measurement system are the
asynchronicity of the measurements, which introduce
errors in the state estimation results during dynamic
events on the electrical network.

63. • As previously noted, the main goal of the power
systems state estimator is to find a robust estimate for
the unknown complex voltage at every bus in the
modeled network.
• Since inexact measurements – such as those from a
SCADA system - are used to calculate the complex
voltages, the estimate will also be inexact.

64. • This introduces the problem of how to devise a “best”
estimate for the voltages given the available
measurements. Of the many criteria used to develop a
robust state estimator, the following three are regarded
as the most common

65. 1. Maximum Likelihood: maximizes the probability that
the estimated state variable is near the true value.
2.Weighted Least-Squares (WLS): minimizes the sum of
the squared weighted residuals between the estimated
and actual measurements.
3. Minimum Variance: minimizes the expected value of
the sum of the squared residuals between components
of the estimated state variable and the true state
variable.

66. • The phasor measurement unit (PMU) is a power system
device capable of measuring the synchronized voltage
and current phasor in a power system. PMUs are quickly
becoming the ultimate tool for wide-area accurate
data acquisition.
• Many power utilities have already placed several PMU’s
in their systems, but currently these PMUs are used
mainly for manual data acquisition and post-processing.

67. • Because they provide an accurate measurement, PMUs
may be integrated into the basic SE for improved local
performance.
• In addition, because PMUs can provide such accurate,
synchronized data over wide areas, they are perfectly
suited for integration into wide-area monitoring
methods, particularly WASE.

68. • Wide-area monitoring systems, consisting of a network
of Phasor Measurement Units (PMU) provide
synchronized phasor measurements, which give an
accurate snapshot of the monitored part of the network
at a given time.

69. FAULT DETECTION AND LOCATING

70.  Adapt protection to be appropriate with system
condition
Benefits of using PMU
 Improved backup protection
 Adaptive protection setting to avoid cascading outage

71. SPECIAL PROTECTIONS SCHEME
TRANSMISSION LINE BACKUP PROTECTION USING
SYNCHROPHASORS
• Relays that combine time-synchronized measurements
and programmable logic control capabilities can use
synchrophasor measurements from both ends of a two-
terminal transmission line to provide backup
protection(see Figure).

72. Relays exchange synchrophasors for backup line
protection in a two-terminal application

73. • Line protection relays calculate synchrophasors at
specific rates (e.g., 60 times per second).
Communications channels make local and remote time-
stamped currents available to the relays at each end of
the line.

74. • These relays time-align local and remote currents on a
per-phase basis, calculate sequence components, and
make this information available to faulted-phase
identification (FPI) logic and protection elements, such
as negative-sequence (87LQ) and zero-sequence (87LG)
current differential elements. The FPI logic makes
these synchrophasor-based elements suitable for single-
pole tripping (SPT) applications

75. • In the present implementation, the synchrophasor-
based backup protection elements detect faults with
fault resistance (RF) greater than 300 ohms within 160
milliseconds. This RF coverage is similar to that of
negative-sequence voltage-polarized directional
elements (67Q).

76. Distributed Bus Differential Protection
• This section describes a backup bus differential
protection scheme (BDPS) that uses synchrophasors and
is suitable for as many as 64 terminals.
• This scheme consists of one SVP (synchrophasor vector
processor) and relays with synchrophasor measurement
and control capabilities that measure the currents of
all the bus terminals and send trip commands to the
terminal breakers, as Figure illustrates.

77. • The scheme uses the topology processor available
within the SVP to adapt the differential element to
different bus configurations and operating conditions.

78. The SVP connects to 16 relays with synchrophasor
measurement and control capabilities. Each relay can
monitor as many as four terminals. The BDPS performs
the following tasks:
• Processes the bus topology to determine the
appropriate protection zones.
• Detects bus faults using current phasors and protection
zone information.
• Transmits trip signals to the appropriate relays to clear
the bus fault

79. Detecting Power Swing
• The SVP and relays can simplify and improve system
integrity protection schemes (SIPS) that use
synchrophasors. The SIPS that detects power swings and
out-of-step conditions and activates remedial actions to
prevent power system instability.

80. • The SIPS consists of two relays with synchrophasor
measurement and control capabilities and one SVP.
• The relays also include programmable logic capabilities
to program outputs and perform remedial actions. This
SIPS is suitable for two-area power systems.

81. System Integrity Protection Schemes for Two Area
Power System
• In a two-area power system, the electrical center is the
point that corresponds to half of the total impedance
between the two sources. The electrical center of the
system can be at a transmission line or at any other
part of the system. The proposed SIPS requires that the
system electrical center must be between the relays
that acquire the synchrophasor measurements.

82. • The SIPS for out-of-step tripping (OOST) that processes
20 synchrophasor messages per second. Figure shows an
alternative to the SIPS that uses the SVP to collect
synchrophasor data from two relays at 60 messages per
second. In this approach, the SVP runs the SIPS OOST
element and sends remedial action commands to the
relays that acquire the synchrophasor measurements.

83. SIPS suitable for two-area power systems that
uses two relays and one SVP for power swing
detection

84. 7- WIDE-AREA CONTROL FUNCTIONS
• WAMACS Automated Control describes a set of functions
that are typically automated within a substation, but
are not directly associated with protection, fault
handling, or equipment maintenance.
• In general, they serve to optimize the operation of the
power system and ensure its safe operation by
preventing manually genera ted faults. These functions
include:

85. • Changing transformer taps to regulate system voltage
• Switching capacitor banks or shunts in and out of the
system to control voltage and reactive load
• Interlocking of controls to prevent unsafe operation
• Sequencing controls to ensure safe operation
• Load balancing of feeders and transmission lines to
reduce system wear and resistive losses
• Restoring service quickly in the event of a fault, with or
without operator confirmation

86. • The functions described in this use case were
traditionally performed by individual devices acting
alone.
• When implemented this way, they did not have any
effect on the communications system. However, in the
last five to seven years, these functions have been
distributed across the substation.
• That is, the software logic controlling the function now
often resides on a different device than the one which
provides the inputs or outputs to the process.

87. • This change has taken place because the use of
substation LANs has made it economical to place
Intelligent Electronic Devices (IEDs) close to the
equipment they are monitoring and controlling.
• Logic has therefore either been centralized, with a
single Substation Computer using the IEDs as remote
controllers, or it has been distributed among the IEDs
themselves. In either case, the communications system
has now become part of the automation functions.

88. • Voltage Regulation using Tap Changers
• Volt/VAR Regulation using Capacitor or Shunt Control
• Interlocking
• Sequenced Controls
• Load Balancing
• Automated Service Restoration