COMPREHENSIVE APPROACH TO
POWER SYSTEM SECURITY
COMP
Copyright © P. Kundur
This material should not be used without the author's consent
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Power System Security
Security of power systems depends on three
factors:
 The Physical System
 the integrated generation, transmission and
distribution system, and loads
 protection and controls
 The Business Structures
 owning and operating entities
 performance and service contracts
 The Regulatory Framework
 roles and responsibilities of individual entities
 well chosen, clearly defined and properly
enforced
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Challenges to Secure Operation of
Today's Power Systems
 Large complex power systems
 thousands of devices requiring harmonious
interplay
 Complex modes instability
 global problems
 different forms of instability:
rotor angle, voltage, frequency
 "Deregulated" market environment
 many independent entities with diverse
business interests
 lack of integrated and inter-regional
planning
 power systems can no longer be operated
conservatively within pre-established limits
 A comprehensive approach to system security is
required
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Comprehensive Approach to System
Security
1. Proper selection, design and application of
power system controls and protective relaying
2. Development and deployment of a good
“defense plan” against extreme contingencies
3. Development of a well documented and
organized plan for rapid and safe restoration of
the power system
4. Use of state-of-the-art techniques for on-line
dynamic security assessment to determine
stability margins and identify any corrective
actions
5. Implementation of a Reliability Management
System (RMS) for setting, monitoring and
enforcing security related standards
6. Development and application of real-time wide
area Monitoring and Control
 an emerging technology
7. Widespread use of distributed generation
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Power System Controls and
Protective Relaying
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Normal State Controls
 Generator controls:
 excitation controls: AVR, PSS
 prime-mover, energy supply system controls
 Transmission controls:
 voltage regulators
 switched reactors/capacitors, SVCs
 HVDC and FACTS controls
 Secondary/tertiary voltage control:
 used by EDF, ENEL
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Preventive and Emergency Controls
Preventive Controls
 Generation shifting
 Increase in VAR reserve
Emergency Controls
 Generator tripping
 Generation runback/fast valving
 Load shedding
 Dynamic braking
 Transient excitation boosting
 HVDC link rapid power ramping
 Controlled system separation
 Transformer tap-changer blocking
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Power System Controls in the New
Environment
 Efficient utilization of facilities while ensuring
security:
 greater dependence on controls
 Successful energy trading (buying, wheeling and
selling of power):
 can overwhelm existing controls
 need for more sophisticated controls using
advanced technologies
 New business structure of owning and operating
entities impacts:
 what controls are used
 how they are designed and deployed
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Implications of Ownership
 Industry will comprise corporate entities having
diverse roles and business interests
 Physical functioning of the integrated power
system will remain the same
 Control of individual equipment should
 not to be left to owner’s discretion
 be vested with the independent system operator
 Specification and design of controls:
 part of overall system planning/design
 carried out by an independent entity
 Otherwise security and overall economy will be
sacrificed:
 defeats the very purpose of restructuring
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Generator Controls
 Essential to recognize the critical role of
generator controls
 Use of fast exciters, AVR, PSS and speed
governor should be mandatory
 No difficulty in motivating power plant owners to
install controls:
 needed to meet local plant needs
 enhance plant operability and stability
 Financial incentives for controls needed to:
 meet global system needs
 enhance overall system performance
 Many of the existing equipment are old and
outdated
 need for upgrading on a prioritized basis
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Coordinated Design of Robust
Controls
 Increasing use of:
 multi-purpose controllers
 multiple controllers to solve a common problem
 Satisfactory and harmonious performance of
different controllers with overlapping spheres of
influence requires:
 coordination and integration
 Controller design must consider performance
under all probable conditions:
 wide range of conditions encountered during
normal operation
 severe system upsets: coordination with
protective systems
 Addressed in a recent report by CIGRE
TF38.02.16: “Impact of Interactions among
Power System Controls”
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Analytical Techniques for Design of
Normal Controls
 Proper design techniques and procedures to
ensure:
 utilization of full potential of the controller
 no adverse interaction with other controls or
with protective systems
 Key design issues:
 selection of devices and input signals
 robustness
 coordination
 impact on overall system performance
 Complementary use of small-signal analysis and
nonlinear time-domain simulation
cont’d
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Analytical Techniques (cont’d)
 Small-signal analysis using eigenvalue
techniques provides valuable information
useful in control design:
 transfer function residues, participation
factors, frequency response, controllability
and observability
 examination of interaction with other
controls
 Nonlinear time-domain (short- and long-term)
simulations assist in:
 establishing signal limits
 assessment of performance during large
disturbances
 checking adverse interaction with protective
systems
 designing emergency controls
cont’d
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Analytical Techniques (cont'd)
 Design one controller at a time with all other
relevant devices/controls modelled
 Robustness to changing system conditions
achieved by:
 considering different operating conditions
 using engineering judgement
 Robustness to parameter uncertainty
achieved by:
 carrying out sensitivity analysis
 Alternatively, robust controller design
technique may be used:
 for example, H-infinity approach
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Improved Protective Relaying
 State-of-the-Art protective relaying for
generating units and transmission lines
 Adaptive relaying with settings that adapt to the
real-time system states
 Replacement of zone 3 and other backup
relaying on important lines with improved
relaying
 Improved protection and control at power plants
to minimize unit tripping for voltage and
frequency excursions
 Protective relay improvements to prevent
tripping of critical elements on overload
 control actions to relieve overload
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Defense Plans Against Extreme
Contingencies
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Extreme Contingencies (ECs)
 Major system disturbances:
 result of contingencies more severe than
normal design contingencies
 occurrence rare, but impact very high
 likely to be experienced more often in the
new environment
 Brought about by a combination of events:
 multiple outages caused by severe weather
conditions
 inadequate design of system and equipment;
equipment malfunction
 human error
 Examples of major system upsets:






French system, 1978 and 1987
WSCC system, July and August 1996
Brazilian system, March 1999
NE U.S.A. and Ontario, August 2003
Italian System, September 2003
Sweden and Denmark, September 2003
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Defense Plans to Minimize Impact of
Extreme Contingencies
 Judicious choice of several forms of emergency
controls will provide protection against different
forms of possible disturbances
 Key design and implementation issues:
 detection
 control action
 timing
 automation and Adaptiveness
 side effects on equipment and system
 coordination
CIGRE TF 38.02.19 report on "System Protection
Schemes in Power Networks" published in 2001
provides a good summary of emergency controls used
by utilities worldwide, future trends and suggested
design procedures
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Steps in the Development of a
Defense Plan
 Detailed modeling of power system, including
fast and slow processes triggered by EC’s:
 includes wide range of protection and controls
 Identification of scenarios of ECs:
 based on past experience, knowledge of unique
characteristics of system
 probabilistic approach
 Simulation and analysis of contingencies:
 extended time-domain simulation
 Identification of measures to minimize the
causes of ECs:
 improved protection/controls;
better coordination
 Development of a comprehensive set of
emergency controls to mitigate consequences of
ECs
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Guidelines for Design and
Deployment of a Good Defense Plan
 Should, as far as possible, provide coverage
against all possible ECs
 Simplicity, reliability,and low cost should be
prime considerations
 Inadvertent operation of emergency controls
must not severely affect system security
 Response-based emergency controls should
generally be preferred:
 as opposed to those based on direct detection
of outages
 Various emergency controls should be
coordinated:
 complement each other
 act properly in a complex situation triggering
several controls
 Ensure compatibility of defense plans
developed by neighboring utilities
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Power System Restoration
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Power System Restoration
 Even if power systems are designed and
operated in the best possible manner:
 impossible to prevent all contingencies which
could cause widespread blackouts
 While the physical extent of the blackout is a
concern, the duration is equally important:
 detailed restoration plans required
 The new competitive environment requires a well
documented and organized plan:
 to ensure that the system, with its numerous
independent entities, can be
re-energized safely and quickly
 Successful system restoration has been a
challenge for traditional monopolistic
environment:
 will be a greater challenge in the new
competitive structure with many owners
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Power System Restoration Process
 Assessment of the system status and initial
cranking sources
 Identification and preparation of restoration
paths to build subsystems
 Resynchronization of subsystems and
restoration of loads
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Key Issues for System Restoration
 Ensuring sufficient black start capability with
due regard to:
 generator startup times and loading rates;
governor droop characteristics, and VAr
capability
 Maintaining voltages and other key parameters
within acceptable bounds
 avoid tripping of critical elements or equipment
damage
 Developing a consistent switching strategy
throughout the procedure
 Coordinating system protection schemes
 Organizing the restoration plan with well defined
roles for each participant
 Training all participants in the restoration
procedure
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Analytical Tools for Developing
Restoration Plans
 Steady-state analysis:
 power flow analysis, including examination of
sustained overvoltages; fault level calculation;
harmonic analysis
 Quasi steady-state analysis:
 operator training simulator, long-term dynamic
simulation
 Dynamic analysis:
 transient stability (TS) programs for verifying
subsystem resynchronization
 extended TS programs for verifying startup of
auxiliaries of power plants, i.e., large induction
motors
 ElectroMagnetic Transients Program (EMTP) for
analysis of switching transients
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Reliability Management System
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Reliability Management System
(RMS)
 In the monopolistic structure, power systems were
owned and operated by a few vertically integrated
entities:
 planning and operating standards were developed
cooperatively and implemented voluntarily
 In the competitive environment, with many new
players, global management of power system
reliability requires a process that is legislated
 Roles and responsibilities of individual entities
should be well chosen, clearly defined and properly
coordinated and enforced
 For proper functioning of the overall system
 a “shared vision” is necessary among all the
entities involved
 a good monitoring system for ”standards”
violations
 The RMS approach provides a contractual method
of dealing with the many entities of a single
interconnected system:
 ensures overall system security through a well
defined and enforceable criteria
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Components of Reliability
Management System
 A typical Reliability Management System has
four components:
1. Reliability criteria applicable to Control Area
operators
 operating reserves, disturbance control,
control performance standards, operating
transfer capability
2. Reliability criteria applicable to generators
 requirements for AVR and PSS
 “grid codes” for new sources of generation
3. Reliability criteria applicable to transmission
system users
4. Excuse of performance
 excused non-compliance, specific excuses
 For each component, the reliability system
specifies:
 participants, criteria, data reporting, compliance
standard, non-compliance standard, sanctions
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On-Line Dynamic Security
Assessment
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Dynamic Security Assessment
(DSA)
 A challenging task
 changing system conditions; complexity and
size of power systems
 Historically based on off-line studies
 system operated conservatively within
pre-established limits
 On-line DSA essential in the new competitive
environment
 evaluation of available transfer capability (ATC)
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Components of DSA
 All forms of system instability must be
addressed
 Two categories important for on-line assessment
 Transient (angle) stability
 Voltage stability
 Small-signal (angle) stability
 control problem addressed in system
design
 on-line assessment important for some
systems
 Here we provide a description On-line Voltage
Stability and Transient Stability Tools developed
at Powertech Labs Inc.
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On-Line Voltage Stability
Assessment Package
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Key Elements of VSA
 Interface with EMS; Model Initialization
 Contingency screening and selection
 Determination of secure operating region
 using static analysis
 Determination of remedial actions
 Fast time-domain simulation
 validation and checking
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Contingency Selection Module
 Impractical to consider every conceivable
contingency
 A limited number (typically 20) critical
contingencies determined for detailed studies
 Performance Indices based on a few power flow
solutions and reactive reserve not reliable
 A fast screening method used:
 based on exact margin to voltage collapse and
full power flow solutions
 number of power flow solutions 1.2 to 2.0 times
number of contingencies
 Supplemented with user-specified contingencies
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Fig. 4 Automatic Critical Contingency Selection
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Security Computation Module
 Engine for voltage stability analysis
 static analysis with detailed models
 Secure region is defined by a number of
Coordinates (SRCs)
 key system parameters: MW generation, area
load, interface transfers, etc.
 Voltage stability determined by
 existence of powerflow solution
 MVAr reserves of key reactive sources
 post-contingency voltage decline
 Specialized powerflow dispatcher and solver to
quickly search for stability limit
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Modelling:
 generator capability curves
 governor response, economic dispatch, AGC
 nonlinear loads
 control of ULTCs, switched shunts, etc.
Inputs and Outputs:
 Inputs
 list of contingencies produced by screening and
ranking (+user defined)
 base case powerflow from state estimator
 definition of SCRs
 voltage security criteria and definition of
parameter of stress
 Output
 secure region in secure region space
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Secure Operating Region
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Secure Operating Region
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Remedial Measures Module
 Determines necessary remedial measures to
 ensure sufficient stability margins
 expand the secure region
 Preventative control actions:
 taken prior to a contingency
 caps/reactor switching, generation redispatch,
voltage rescheduling
 Corrective (emergency) control actions:
 applied following a contingency
 load shedding, generator runback, transformer
tap changer blocking
 Ranking of each remedial measure using
sensitivity analysis
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Ranking and Applying Remedial
Measures
 Objective is to identify the most effective
remedial measures to give the desired stability
margin
 Obtain solved power flow case for the most
severe contingency
 gradually introduce the effect of the contingency
 bus injection compensation technique
 Compute the sensitivities of reactive power (or
bus voltage) to different control measures
 rank the remedial measures
 Apply controls one at a time in order of ranking
until power flow solves for the most severe
contingency
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Expanding the Secure Region:
Remedial Measures
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Fast Time-Domain Simulation
Module
 Determines the essential dynamic phenomena
without step-by-step numerical integration
 when chronology of events significant
 for validating the effect of remedial measures
 Focuses on the evolution of system dynamic
response driven by slow dynamics
 transformer tap changers, field current limiters,
switched caps
 Captures the effects of fast dynamics by solving
associated steady state equations
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Fig. 3 VSAT Structure
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Transient Stability Assessment
Package
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Transient Stability Assessment
(TSA)
 Time-domain simulations essential
 modeling detail and accuracy
 Sole dependence on time-domain simulations
has severe limitations
 high computational burden
 no stability margin/sensitivity information
 requires considerable human interaction
 Supplementary techniques for speeding up and
automating overall process
 Methods available for deriving useful indices
 Transient Energy Function (TEF)
 Signal Energy Analysis
 Extended Equal Area Criterion (EEAC)
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Key Elements of TSA
 Interface with EMS; Model Initialization
 Contingency screening and selection
 Simulation engine
 detailed modeling
 time-domain simulation
 speed enhancement
 Post-processing of detailed simulation
 stability margin index using EEAC
 power transfer limit search
 remedial measures
 damping calculation using PRONY
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A Practical Tool for TSA
 Overall architecture similar to that of VSA
 Time-domain program, with detailed models and
efficient solution techniques, forms simulation
engine
 EEAC used for screening contingencies,
computing stability margin, stability limit search,
and early termination of simulation
 “Prony analysis” for calculation of damping of
critical modes of oscillation
 A powerflow dispatcher and solver for finding
the stability limit
 a fully automated process
 No modeling compromises;
can handle multi-swing instability
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EEAC
 Integrates the dynamic response in the
multimachine space, and maps the resultant
trajectory into a set of one-machine-infinitebus planes
 by applying complementary cluster center of
inertia (CCCI) transformations
 keeps all dynamic information in the
multimachine space
 stability analysis can be quantitatively
performed for the image OMIB systems
 has the same accuracy and modeling
flexibility
 fast, quantitative
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EEAC
 Loss of transient stability in a power system
always starts in a binary splitting of generators:
 critical cluster of generators
 rest of the system
 At any given
point in the timedomain
trajectory of the
system, the
system can be
visualized as a
one-machineinfinite-bus
(OMIB) system
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EEAC
 The classical equal area criterion can be
extended to the visual OMIB system
Stability margin of the system is defined as
Ad  Aa

100
x
if the system is stable Ad  Aa 

Ad

A  Aa
100 x d
if the system is unstableAa  Ad 

Aa
Thus, -100   , and
if the system is stable
 if the system is unstable
 can be used as a stability index
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Use of EEAC Theory
 Contingency screening
 stability margin gives an indication of the
relative severity
 Corrective measures for maintaining secure
system operation
 critical cluster of generators (CCG) provides
valuable information
 Power transfer limit search
 stability limit can be determined in four iterations
using stability margin
 each iteration involves a detailed simulation and
computation of stability index
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Results - Test System
System description




BC Hydro system
1430 buses
186 generators
4 HVDC links
Interface


GMS and PCN output
Base case transfer = 3158
MW
Contingency


Three phase fault at GMS 500
kV bus
Tripping of one of two 500 kV
lines from GMS to WSN
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Limit Search Results
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Speed Enhancement: Parallel
Processing
 Code parallelization
 differential equations easily parallelized, but
not network equations
 speed-ups limited by serial slowdown effect
 up to 7 times speed-up can be achieved with
20-30 processors
 not an effective way
 Conventional serial computers offer much
faster computational per-CPU
 Best approach is to use multiple processors
 Perform TS analysis and VS analysis in parallel
 For multiple contingencies
 perform initialization only once
 run contingencies on multiple processors
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TSAT Structure
Solved Powerflow
+
Dynamic Data
Transaction
Definitions
Contingency
Screening & Ranking
(EEAC)
Full
Contingency List
Must Run
Contingencies
Powerflow
Dispatcher
Time-Domain
Simulation
Increase
Transfer
Stability
Indices
No
Security Limit?
Yes
Sufficient
Margin?
No
Remedial
Measures
Yes
STOP
Fig. 8 TSAT Structure
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Computational Performance of DSA
 Target cycle time from capture of state
estimation to completion of security assessment
for all specified transactions:
 20 minutes
 TSA and VSA functions performed in parallel
 distributed processing on separate CPUs
 This can be readily achieved with low cost PCs
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Example of Computational
Performance of VSAT
Computation times for a 4655 bus, 156
generator system on a 1.7 GHz Pentium 4 PC
with 256 MB memory:
 Screening 300 contingencies to select 20 critical
contingencies: 20 secs
 Detailed security analysis of base case with 20
critical contingencies: 1.2 secs
 One transaction limit search with 20 critical
contingencies: 12 secs
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Example of Computational
Performance of TSAT
Computation times for a 4655 bus, 156
generator system on a 1.7 GHz Pentium 4 PC:
 Screening 100 contingencies for ranking
10 critical contingencies: 75 secs
 Detailed security analysis of 10 contingencies
including 3 second time domain simulations and
stability index calculation: 75 secs
 A four-iteration power transfer limit search for
one contingency: 120 secs
 Total time for complete power transfer limit
calculation, including screening of 100
contingencies, stability limit search with an
optimal order of 10 contingencies: 5 mins
NOTE: Both TSAT and VSAT have distributed
processing capability, allowing each contingency or
each transfer limit search to be processed in parallel
on separate CPUs
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Summary
 On-line DSA is a complex problem
 It is a challenge to provide comprehensive
analysis with the required
 accuracy, speed, and robustness
 A practical tool for use with large complex
systems has been built by
 drawing on techniques developed over many
years;
 enhancement and integration of these
techniques;
 use of specialized software designs and
distributed hardware architectures
 May be used for real time application, or
previous day to post ATC
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New and Emerging Technologies
 Real-Time Monitoring and Control
 Risk-Based Security Assessment
 Intelligent Control
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Real-Time Monitoring and
Control
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Real-Time Wide Area Monitoring
 Advances in communications technology have
made it possible to:
 monitor power system over a wide area
 remotely control many functions
 Wide Area Monitoring:
 phasor measurement units (PMUs) provide time
synchronized measurements with an accuracy of
1 microsecond, utilizing Global Position System
(GPS)
 PMUs send measured voltage and current
phasors to a Centralized Monitoring System,
typically at 100 millisecond intervals
 Data stored and processed for various
applications
 Results displayed on a Graphical User Interface
 Examples of Wide Area Monitoring Systems:
 North American Western Interconnected System's
Wide Area Measurement System (WAMS) project;
BPA, EPRI, DOE as participants
 ETRANS Wide Area Monitoring (WAM) project for
the Swiss Power Grid; developed by ABB
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Wide Area Monitoring Current
Applications
 On-line monitoring of transmission corridors for
loading
 Fast detection on critical situations
 voltage stability
 power system oscillations
 transmission overloading
 Additional input values of system variables for
state estimator
 Disturbance recording
 for calibration of power system model
 validation of stability analysis software
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WAM Potential Future Applications:
Wide Area Emergency Control
 Prevention of partial or total blackout of power
systems
 trigger emergency controls based on system
response and measurements
 Research into the application of "Multisensor
Data Fusion" technology
 process data from different monitors and
integrate information
 determine nature of impending emergency
 make intelligent control decisions in real time
 A fast and effective way to predict onset of
emergency conditions and take remedial control
actions
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Risk-Based
Dynamic System Assessment
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Dynamic Security Assessment
Current Practice
 The utility practice has been to use deterministic
approach
 build strong systems and operate with large
security margins
 overly conservative, but cost could be passed on
to captive customers
 The deterministic approach has served the
industry well
 high security levels
 study effort minimized
 In the new environment, with a diversity of new
participants, the deterministic approach not
readily acceptable
 need to account for the probabilistic nature of
conditions and events
 need to quantify and manage risk
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Risk-Based Dynamic Security
Assessment
 Examines the probability of power system
becoming unstable and its consequence
 Computes indices that measure security level or
degree of exposure to failure
 capture all cost consequences
 Notion of security posed in a language and form
understood by marketers and financial analysts
 Possible with today’s computing and analysis
tools
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Intelligent Control
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Power System Control
 Overall control functions highly distributed
 several levels of control
 involve complex array of devices
 Human operators provide important links at
various levels
 acquire and organize information
 make decisions requiring a combination of
deductive, inductive, and intuitive reasoning
 “Intuitive reasoning” allows quick analysis of
unforeseen and difficult situations and make
corrective decisions
 most important skill of an operator
COMP - 69
1539pk
Utilities
OPERATIONS
PLANNING
System Models
Load Forecast
Contingency Lists
Security Criteria
MONITORED
QUANTITIES
Energy Providers
Power Marketers
Off-Line
Security Limits
Transaction Requests
State Estimator
Build Model for
Current System State
Look-up tables of
Security Limits
SYSTEM
CONTROL
CENTER
Automatic
Local
Controls
Controls
CONTROL
DECISIONS
CONTROL
ACTIONS
Generation
Human Controls
Automatic
Local
Controls
Human
Other Control
Centers
Transmission and Distribution
Interconnected
Human Controls
Automatic
Local
Controls
Power Systems
Customers
Human Controls
COMP - 70
1539pk
Intelligent Control of Power
Systems
 Future power systems more complex to operate
 less structured environment
 Current controls do not have
 “human-like” intelligence
 Add intelligent components to conventional
controls
 learn to make decisions quickly
 process imprecise information
 provide high level of adaptation
 Overall control of power systems
 utilize both conventional methods and decision
making symbolic methods
 intelligent components form higher level of
control
COMP - 71
1539pk
Distributed Generation
COMP - 72
1539pk
Distributed Generation (DG)
 Offer significant economic, environmental and
security benefits
 Microturbines
 small, high speed power plants
 operation on natural gas or gas from landfills
 Fuel Cells
 combines hydrogen with oxygen from air to
generate electricity with water
 hydrogen may be supplied from an external
source or generated inside fuel cell by reforming
a hydrocarbon fuel
 Not vulnerable to power grid failure due to
system instability or natural calamities !
 Protection and controls for DG should be
designed so that units continue to operate when
isolated from the power grid
COMP - 73
1539pk