WIDE AREAprotection and monitoringAs interconnected power system size grew over the years, the magnitude of system-wide disturbances in power systems

grew as well. Protection and control actions are needed to arrest the propagation of large power disturbances, stop

the power system degradation and restore the system to a normal state. Control centers have the obligation to act,

WIDE AREAwith limited information, on a very complex situation and often use heuristics and pre-defined procedures to be able

to normalize the situation quickly. Local protection systems, which only rely on locally available measurements, are not

capable to protect the entire power system. Miroslav Begovic, Georgia Institute of Technology, USA

Oper ating on tight margins and with less redundancy, power systems are sometimes just a couple of unexpected (and unlikely) contingencies away from a blackout, as the experience from the years past has repeatedly shown. Transformation of power networks into modern structures makes them harder to protect, through addition of non-utility generators, heavy tie line transfers in a growingly competitive environment, and deployment of fast control devices. The need is great for automated systems with advanced monitoring and better real-time interfaces for operator interactions. Advancements of measurement devices and communication technology in wide-area monitoring and controls, FACTS devices, and new procedures provide for more efficient ways to detect and control large disturbances.

System integrity protection scheme (SIPS) is a concept of using local as well as selected remote measurements and sending the necessary system information to a processing location to formulate the emergency control and protective actions for the power system. With new technologies, more "intelligent" equipment is deployed at the local level to formulate an efficient response to ongoing disturbances. Traditional contingency / event based remedial action systems can be made to act with proper local supervision for security.

Decentralized subsystems make local decisions based on local measurements and assorted remote information. They can send pre-processed information to higher hierarchical levels. A major feature of the SIPS is their ability to receive remote information and commands and to send selected local information to the other locations in the system.

Modern Protection Infrastructure Experience reveals similar patterns in genesis of such

disturbances. Among common causes are: Unfavorable pre-existing conditions (i.e. generator/line

maintenance) Tendency of cascading overloads to spontaneously

develop under heavily loaded, contingency-challenged system conditions

Inadequate VAr support Poor right-of-way maintenance Incomplete or misleading alarms Inability of operators to respond due to the lack of

training or limitations of resources at their disposal Inadequate planning/operation studies Unavailability of automated actions to initiate

appropriate response, such as automatic and pre-planned separation of the power system

While it is not practically possible to completely eliminate blackouts, with reasonable means probability of the blackouts could be substantially reduced.

Improved communication facilities and better data handling capability have greatly enhanced modern SCADA/EMS systems. Availability of critical functions of 99.99% or better is expected for reliable system operation. Alarm monitoring systems should always be in top operating condition. New alarm processing techniques should be deployed to deal with the avalanche of data during major disturbances.

Phasor measurement units (PMUs) and high bandwidth and high-speed communication networks can provide time-tagged measurements from the entire system, enabling improved, faster and more accurate state estimators. Development of SIPS may provide for superior management of system disturbances. Those schemes are designed to operate on pre-planned, automatic corrective actions, as a result of system studies. The primary goal of SPS schemes is to improve security of the power system. Periodic studies should be done and protection designs reviewed to prevent misoperation. As a tradeoff between dependability and security, designers can increase the security of protection design in the areas vulnerable to blackouts. As an example, transmission line pilot protection Permissive Overreach Transfer Trip scheme (POTT), which is more secure, could be used instead of the more dependable Directional Comparison Blocking (DCB).

Design and ArchitecturesThe SIPS encompasses Special Protection Schemes (SPS),

Remedial Action Schemes (RAS), as well as additional schemes such as underfrequency (UF), undervoltage (UV), out-of-step (OOS), etc. These additional schemes are not used in the conventional North American definition of SPS and RAS.

A traditional protection scheme is focused on a specific piece of equipment (line, transformer, generator, bus bar, etc.). SIPS is applied to the overall power system (or a strategic part) and may require multiple detection and actuation devices and communication infrastructure. The scheme architecture can be defined by the location of the sensing, decision making, and control devices and the impact the SIPS has on the electrical system. Impact classifications are:

1) Local (Distribution System) – All sensing and control devices are typically located within one distribution substation. Operation generally affects only a very limited portion of the distribution system.

2) Local (Transmission System) - All sensing and control devices are typically located within one transmission substation. Operation affects only a single small power company, or portion of a larger utility. This category includes SIPS with impact on power plants.

3) Subsystem - More complex, involving sensing of multiple power system parameters and states. Information can be collected both locally and from remote locations while decision-making is performed at one location.

Development of new SIPS will provide for superior management of system disturbances.

Miroslav Begovic

is Professor in the

School of Electri-

cal and Computer

Engineering at

Georgia Institute

of Technology,

Atlanta.

He received his

BSEE and MSEE

from Belgrade

University and

PhDEE from

Virginia Tech

University. Miroslav

is a Fellow of IEEE,

a member of the

Power System

Relaying and

Dynamic

Performance

Committees,

and serves in

different IEEE lead-

ership positions.

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by Miroslav Begovic, Georgia Institute of Technology, USA

SPTInput Interface

GPSTime

Synchronization

Power SystemVariablesDatabase

SupervisionService,

Maintenance andUpdate Interface

High SpeedCommunication

Interface

Substation Control System

SPT

Power System Transducers and Measurement Devices

Local and Remote Signals andMeasurement

Power System Actuators

Local or Remote ControlSignals

Power System

SPTOutput Interface

Low SpeedCommunication Interface

SPTDecision Making Logic

ParameterSetting

Database

Other SPTDevice

Other Interface

Other SPTDevice

2) Hierarchical Architecture - There may be several steps in the corrective action. Local measurements may be transmitted to multiple control locations. Immediate action can be followed by further analysis. Typical logic involves use of operating nomograms, state estimation and contingency analysis.

The design of the System Protection Terminal (SPT) addresses standard requirements for protection terminals. The terminal is connected to the substation control system. For time tagging applications, a GPS-based synchronization function is used. SPT uses a high-speed communication link to transfer data between the terminal databases, which contain all updated measurements and binary signals recorded in the substation. The decision-making logic contains all the algorithms necessary to derive appropriate output control signals, such as circuit-breaker trip, AVR-boosting, and tap-changer action, to be performed in the substation. The input data is stored in the database. A low speed

Telecommunications facilities are used to transfer information and remote corrective actions. The operation has a significant impact on an entire large utility or balancing authority area.

4) System wide - The most complex, with multiple levels of arming and decision making and communications. Local and telemetry data are obtained from multiple locations and can initiate multi-level corrective actions. Multi-level logic is used for different types of power system contingencies. Operation has a significant impact on an entire interconnected system. Design of the SIPS may involve redundancy or backup functions, and may involve some form of voting or vetoing decisions.

There are two main types of SIPS architectures: flat and hierarchical.

1) Flat Architecture - the measurement and operating elements are co-located. The decision and corrective actions may need a communication link for remote information and/or to initiate actions.

1 System Protection Terminal

System

Protection

Terminals

(SPT) could

concurrently

facilitate

multiple SIPS

actions.

PAC.AUTUMN.2009

21

2 Propagation of disturbances

Soon to be

published

report of the

IEEE Power

Systems

Relaying

Committee will

report on

world wide

industry

experiences

with various

types of SIPS.

report of the IEEE PES Power System Relaying Committee and also summarized as a journal article for wider engineering readership.

Wide area monitoring with PMUsWhile true wide area SIPS are very demanding systems

in terms of infrastructure support (fast data acquisition, communication networks with guaranteed bandwidth, fast and reliable actuation), monitoring of system-wide events can be accomplished with much fewer resources, especially when it is done as part of the forensic analysis of the disturbances. It may be considered as a transitional step to developing a better understanding of the system behavior and formulating a target list of applications which could cost-effectively share the same infrastructure (such as state estimation, voltage stability protection and emergency control, dynamic line ratings, etc.) Developing a portfolio of possible applications would lead to a more cost-effective sharing of resources as long as they are integrated to satisfy the most demanding aspects of every application planned to be used concurrently. Most designs for such systems are built around the networks on phasor measurements, which can also be used in non-networked configuration for ex-post tracking of system wide events.

The concept of phasor measurement is a spin-off of the symmetrical component distance relay, one of the early microprocessor-based relay designs. The first prototypes of

communication link for SCADA communication and operator interface is also available as an enhancement for the SCADA state estimator. Actions initiated by SCADA/EMS, such as optimal power flow, could be activated via the system protection terminal. The power system operator should also have access to the terminal, for supervision, maintenance, update, parameter setting, change of setting groups, disturbance recorder data collection, etc. The most appropriate types of SIPS actions are:

Generator Rejection Load Rejection Under-Frequency Load Shedding Under-Voltage Load Shedding Adaptive Load Mitigation Out-of-Step Tripping Voltage Instability Advance Warning Scheme Angular Stability Advance Warning Scheme Overload Mitigation Congestion Mitigation System Separation Shunt Capacitor Switching Tap-Changer Control SVC/STATCOM Control Turbine Valve Control HVDC Controls Power System Stabilizer Control Discrete Excitation Dynamic Breaking Generator Runback Bypassing Series Capacitor Black-Start or Gas-Turbine Start-Up AGC Actions Busbar Splitting

In 1996, joint Working Groups of IEEE and CIGRE published a noted article. The objective was to investigate the worldwide use of special protection schemes and to report on their designs, functional specifications, reliability, costs and operating experiences. The report encompassed over 100 schemes and provided a wealth of information on the direction the industry was taking in coping with increasingly complex disturbances.

In 2004, the System Protection Subcommittee of the IEEE Power System Relaying Committee started an initiative to update the industry experience on SPS and SIPS by creating a new worldwide survey. The survey is divided into two parts: Part 1 identifies the purpose of the schemes with subsections of "Type" and "Operational Experience". Part 2 concerns engineering, design, implementation, technology, and cyber security. The survey inquires about design and implementation, as well as the operation experience. Information is collected on the application, design, implementation, operation, and maintenance of new and next generation SIPS and providing reasonable countermeasures to slow and/or stop cascading outages caused by extreme contingencies (safety net). The results of the survey, containing almost one thousand different schemes obtained from all over the world will soon be published as a special

2003 Blackout images courtesy of NOAA.

Before blackout

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picture courtesy of Adam Hart-Davis

Frequency (active power imbalance) disturbances spreading across power networks is akin to propagation of ripples in laminar fluids

a drop of water, which are often used to visualize the spreading of the frequency perturbations through vast distances in power networks. Disturbances caused by relatively minor active power imbalances are possible to track if a number of strategically positioned PMUs are used to provide information about timing and nature of the initial transients. Figure 3 illustrates such an event which occurred in the San Francisco area in 1999 and was captured by a number of PMUs installed across the WSCC system. The ease with which active power/frequency disturbances may be observed spreading across large networks have led to proposals to use networks of frequency recorders to track such events. It has also contributed to proposals to develop deeper understanding of how frequency perturbations propagate through electrical networks.

It is believed that very minor active power disturbances can produce system wide effects. Power excursions of 0.276 Hz (Figure 4) have preceded the loss of a major transmission line during genesis of the system wide blackout in WSCC on August 10, 1996. The entire system has collapsed within 6 minutes from the occurrence of that disturbance, believed to have been caused by spontaneous arcing between the transmission line and a tree in the right-of-way. If that speculation is true, then it could be seen as demonstration that, in the realm of large power networks, the flapping of butterfly wings in certain places can literally produce a storm in the remote corners of the system.

Even when the amount of load drop is only 0.5% of the system load (Figure 4), it may reveal facts about the disturbance: sudden changes in frequency indicate switching events, initial frequency upswing indicates a surplus of generation (loss of load) whose magnitude reflect the amount of load lost in the disturbance. Subsequent larger oscillations are the consequences of generator trips. Very small disturbances may have complicated evolution and consequences, and ex-post analysis may require a large number of measurements, precise time tagging of different events and additional information. It may not be easy to propose general rules for analysis of system disturbances via non-EMS networks of PMUs.

Frequency disturbances will become more frequent (and important) with deeper penetration of renewable generation resources, especially photovoltaic and wind. Both are dependent upon stochastic inputs (as Figure 5 illustrates using field data from the system installed since 1996 on Georgia Institute of Technology campus). Some countries, like Spain, already have 11 percent of their available generation capacity in wind resources. In contrast, voltage disturbances areas are usually localized around the point of inception of the disturbance, especially in strong systems. Analysis of such events is more effective through use of EMS based techniques,

phasor measurement units (PMUs) were designed and built by the research team of Professor Arun Phadke at Virginia Tech in the mid-80s. Built on the hardware platform using Motorola 68020 microprocessors and VME bus, early PMUs were synchronized using the outrageously expensive stand-alone GPS receivers then available. They provided the single pulse per second synchronization signal which was used to enable the 720 Hz sampling rate needed by PMUs to obtain phasors from 60 Hz voltages and currents. The sampling rates used at the time were dictated by the relative simplicity of calculations needed to obtain phasors from a sliding window of data containing 12 samples per cycle.

The first tests of PMUs (in the late 80s and 90s) were done by several US utilities (BPA, AEP, NYPA, Georgia Power Co., FP&L, etc.) in stand-alone configuration, due to the limited infrastructure availability. Consequently, various uses were developed for non-networked groups of PMUs strategically placed across the power system. Many of them were really deploying PMUs as highly performing disturbance recorders.

The data obtained from the first PMUs were very sufficiently detailed to estimate the phase angle dynamics across the system using ex post estimation. Among the first field tests were those performed at the Georgia-Florida interconnection, known for its challenging dynamics. Over the years, the capabilities of the equipment allowed for many more innovative uses of the PMU equipment.

Different classes of disturbances provide different signatures in the network. In general, power/frequency disturbances produce system wide effects and allow to observe the propagation of the disturbance across the network. Figure 2 shows the propagation of ripples created by

Networks of synchronized phasor measurements are able to accurately track the propagation

of disturbances in large power systems.

Wider use

of PV

and wind

generation

will create

more

frequency

disturban-

ces.

2003 Blackout images courtesy of NOAA.

PV and wind generation are becoming more common

After blackout

In the realm

of large power

networks,

'flapping of the

butterfly wings'

in some places

can

literally produce

a 'storm' in the

remote parts of

the system.

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P4: Summary Plot for SF_9812081614BcaseID = SF_9812081614B casetime = 09/23/99_09:14:06

0.10

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15: 47: 36Ross-Lexington time trips/McNary generation drops off

15: 48: 51Out-of-Step separation

15: 42: 03Keeler-Allston trips

0.276 Hz 0.252 Hz0.264 Hz3.46% damping

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Time in SecondsReference time = 15: 35: 30 PDT

but it is possible to identify certain signatures of problematic situations by using special monitoring strategies. Very often, voltage disturbances such as loss of a shunt capacitor bank, are only detected in the first few tiers of buses surrounding the point of inception of the disturbance (tier #1 consists of buses directly connected to the point of disturbances, tier #2 are buses connected to tier #1, etc.)

Direct TestsDirect (staged) tests are an excellent way to explore the

system dynamics. Broadly, they can be classified as Topology Switching Tests (simple opening or closing of the breakers); Tests with large inputs (using controllers capable of producing GW scale disturbances, such as dynamic brakes, SVCs, thyristor-controlled series capacitors (TCSCs) or similar devices); Tests with medium-level inputs (using injectors such as HVDC controllers, which may be used to inject the disturbances of the order of 0.1 % of the system load); Tests with low-level random and pseudo-random inputs (signals as small as 0.01—0.05% of the system load may be sufficient to drive the system dynamic response).

Example: Control of Inter-area oscillationsThe frequency of inter-area disturbances has increased

significantly in recent years (in some systems reaching hundreds annually). The variety of circumstances surrounding the onset of power oscillations needs an adaptive approach to ensure fast detection and effective mitigation. Knowing generator coherency in real-time is important in such cases. Phasor measurement based technologies have the potential to significantly enhance SIPS (system integrity protection schemes). A new method for generator coherency

determination determines generator coherency based on real-time tracking of generator speeds in the network. The new method establishes the coherency faster than conventional angle monitoring due to its lower sensitivity to transient distortion. The low frequency spectra of inter area oscillations tend to produce phase-aligned peaks in coherent machines. Their accurate determination requires use of advanced DSP techniques. Once coherent groups are determined, separation schemes may be initiated. Important issues involve the geographical structure of the scheme, wide area data processing and the choice of remedial actions.

Figure 6 demonstrates the application of such instantaneous measurements for identification of the coherent groups of generators during development of inter-area oscillations in the system. The initiating disturbance on a 68-bus, 16-machine test system is a line outage. The consequence is development of inter area oscillations which develop over time and can be tracked on any one of the generators by calculating time evolution of the low frequency spectrum of its speed and identifying the dominant modes of oscillation (0.22 Hz, 0.36 Hz and 0.60 Hz). The machines which have identical phase angles corresponding to the peaks of any oscillation modes are forming coherent groups, which can be identified in real-time by tracking the low frequency spectra of the machine speeds as the disturbance evolves. Subsequent control actions may be designed around such real-time monitors and allow for an adaptive scheme for system separation.

Example: Voltage Collapse Analysis Voltage instabilities are often investigated using static

bifurcation model. This model assumes that the power system is described with a set of differential equations. As system loading varies slowly, the stable equilibrium moves in the state space and can become unstable or even disappear. In both cases, the system loses its stability. In the latter case, it means that the systems with heavy, increasing loads tend to suffer declining voltages and progressively larger reactive losses up to the point when the voltages suddenly collapse, driving the entire system into a blackout. If the equilibrium point becomes unstable, the system loses its stability through

New monitoring and protection technologies will promote speed and accuracy enhancement to network functions.

3 Frequency deviations 4 Malin-round mountain #1 MWFigure 4: Power oscillations at 0.276 Hz have developed prior to the Keeler-Allston line trip which unchained the system wide blackout in the WSCC system in 1996. The oscillations are believed to have been triggered by the arcing between the tree and a transmission line.

Figure 3: Frequency deviations in response to a 600 MW load loss in the San Francisco area observed through a network of PMUs, some of which thousand or more miles away.

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either abrupt appearance of self-sustained oscillations or a growing oscillatory transient. This type of oscillatory instability is called Hopf bifurcation (HB), and can possibly explain a number of events observed in power systems world wide, when unexplained self-sustained oscillations develop, sometimes without any obvious cause.

Bifurcation does not account for the large disturbances found in some voltage collapses. However, some concepts of bifurcations can be reused to study large, sudden disturbances as well. One key idea is to split dynamics into fast and slow dynamics. When studying the slow dynamics, the fast dynamics can be approximated as instantaneous. During the fast transients, the slow variables can be considered as practically constant.

Voltage stability of the system can be improved by implementing various remedial measures, such as adding reactive compensation near load centers (e.g., shunt capacitor banks, Static Var Compensators (SVCs), synchronous condensers, etc.), strengthening the system by building new transmission lines, varying the operating conditions, such as voltage profile and generation dispatch, coordinating relays and controls (e.g., control of transformer tap changers), etc. The factors that influence the choice of the measure are the dynamic characteristics of the collapse, the state of the system parameters, and the system sensitivity to a certain measure.

Are PMUs needed or not for voltage stability monitoring and protection? The answer depends on sensitivity to inaccuracy of the implemented scheme. Voltage stability is an inherently system phenomenon. The complete model assumes the knowledge of the complete state vector, obtained as the system is undergoing changes. That is not possible in conventional installations, where state estimation is refreshed relatively infrequently (every several minutes).

The conventional approach to defense would be an under-voltage (UV) load shedding with fixed set points. UV relays are widely available; they are often implemented in transmission networks. The advantage is simplicity and robustness of the scheme, which relies on local voltage measurements only. The disadvantage is also the simplicity – the relay settings are not adapted to changing network conditions, which, depending on the loading levels and the level of reactive support, may vary within a wide range. That may, under some circumstances, render the scheme useless, or even trigger the protection under normal and secure operating regimes with depressed voltages.

The accurate model of voltage collapse requires the complete state vector (phasors across the entire network). Under such circumstances, deployment of the advanced analysis techniques (direct, iterative, or continuation methods) could be used to assess the margin or sensitivities of the system to voltage collapse, identify the critical contingencies, and formulate the optimal remedial actions. There are a number of EMS packages currently in use which claim to accomplish some, or all of those functions. The limitation of this approach is that the evaluation is tied to a latency time of the underlying monitoring system, which

may mean that the mitigation is applied to a system which has changed by the time of actuation, and that the assessment cannot be done fast enough to deal with fast transient aspects of voltage dynamics.

Finally, only a network of PMUs covering the entire system redundantly (and equipped with a reliable and redundant information exchange infrastructure) could provide a fast and accurate medium for monitoring and transfer of information, which could be used to formulate the real-time monitoring and control strategies not only for quasi-steady-state types of voltage instabilities, but also be used for mitigation of dynamic voltage dips using SVCs and other dynamic reactive support devices. In addition, such a network would be fast enough to be used for other applications, such as defense against transient and cascading instabilities in the transmission network, which require fast response times not afforded by currently available alternatives to PMUs. PMUs would also allow shortening the refresh times for various network optimization functions, such as active and VAr loss minimization optimal power flows, which would help accomplish better tracking of the optimal states and reduce the cost of system operation. Considered in conjunction with a portfolio of complementary applications, PMUs offer unprecedented speed and accuracy enhancement to network functions, which make a proposal for their implementation much easier to justify.

6 Evolving spectra in development of inter-area oscillations

5 PV system daily power generation Figure 5: The DC and AC power outputs during daily operation of the 340 kW photovoltaic system on Georgia Institute of Technology campus on a clear sunny day (left) and intermittently cloudy day (right). Similar fluctuations are observed in daily operation of large wind farms.

Figure 6: Time-frequency distributions on one of the generators’ speeds during development of an inter-area oscillation in a simulated 68-bus, 16-generator system model. Horizontal axes are time and frequency (corresponding to different time instants).

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