Real-Time Grid Reliability Management

The Eastern Interconnection Phasor Projects (EIPP) is a Department of Energy (DOE) and Consortium for Electric Reliability Technology Solutions (CERTS) initiative to deliver immediate value of phasor technology to the Eastern Interconnection (EI) participants. With the current EI phasor network comprising of approximately 25 Phasor Measurement Units (PMU) and 5 Phasor Data Concentrators (PDC) is operational, this paper focuses on the efforts by the EIPP Real-Time Applications Task Team (RTTT) to develop and deploy real-time wide area monitoring capabilities on grid dynamics to operators and reliability coordinators through the Real-Time Dynamics Monitoring System^tm (RTDMS) as well as some of the planned activities that are currently underway.

The Real-Time Voltage Security Assessment (RTVSA) project is designed to be part of the suite of advanced computational tools for congestion management that is slated for practical applications in California within the next couple of years. Modern voltage assessment methods include the development of such advanced functions as identification of weak elements, automatic selection of remedial actions and automatic development of composite operating nomograms and security regions. With all the research advancements in the area of Voltage Security Assessment over the past few decades, the feasibility of deploying production-grade VSA tools that run in real time and integrate with existing EMS/SCADA systems utilizing results from the state estimator, are increasingly becoming a reality.

Some advanced contemporary real-time applications already promote the idea of using the security regions with the composite boundaries limited by stability, thermal, and voltage constraints. At the same time, the majority of these tools are still based on the static system power flow models and implement such traditional approaches as sink-source system stressing approach, P-V and V-Q analyses, V-Q sensitivity and modal analysis. Unfortunately, many of the most promising methods suggested in the literature have not been implemented yet in the industrial environment, including the state-of-the-art direct method to finding the exact Point of Collapse. Currently there exists no real-time monitoring tool for voltage security assessment. The problems of voltage security will be exacerbated by the effects of multi-transfers through the network. These sets of simultaneous transfers are manifest because of the buying and selling of electric power across the boundaries of control areas. Moreover the point of production and the point of delivery may be in geographically distant locations.

The RTVSA application is based on an extensive analysis of the existing VSA methodologies, by surveying the leading power system experts' opinion worldwide, and also with feedback from industrial advisors. Through this process, a state-of-the-art combination of approaches and computational engines was identified and selected for implementation in this project. The suggested approach is based on the following principles and algorithms:

• Use the concepts of local voltage problem areas and descriptive variables influencing the voltage stability problem in each area. Utilize information about the known voltage problem areas and develop formal screening procedures to periodically discover new potential problem areas and their description parameters.
• Use the descriptive variable space to determine the sequence of stress directions to approximate and visualize the boundary. The stress directions are based on pre-determined generation dispatches and load scaling patterns..
• Use hyperplanes to approximate the voltage stability boundary.
• To calculate the approximating hyperplanes, apply a combination of the parameter continuation techniques and direct methods as suggested in this report. Introduce a sufficient additional security margin to account for inaccuracies of approximation and uncertainties of the power flow parameters.
• Compute the control actions most effective in maintaining a sufficient security margin.
• Produce a list of abnormal reductions in nodal voltages and highlight the elements and regions most affected by potential voltage problems. The list of most congested corridors in the system will be ranked by the worst-case contingencies leading to voltage collapse.

The initial framework of this project was originally formulated by California ISO. The key elements of the suggested approach which are the use of parameter continuation, direct methods, and the hyperplane approximation of the voltage stability boundary were approved by a panel of leading experts in the area in the course of a survey conducted by Electric Power Group, LLC (EPG) in 2005. These concepts were also verified in the course of face-to-face personal meetings with well-known university professors, industry experts, software developers and included email discussions and telephone exchanges. CERTS industrial advisors approved these developments during various CEC Technical Advisory Committee (TAC) meetings conducted in the past years.

In 2005, the project development team successfully implemented the parameter continuation predictor-corrector methods. Necessary improvements were identified and developed. The PSERC parameter continuation program and MATLAB programming language were used in the project. During 2006-07, research work included the implementation of Direct Methods to quickly and accurately determine the exact Point of Collapse (PoC), Boundary Orbiting techniques to trace the security boundary, the investigation of descriptive variables, and the validation of techniques for analyzing margin sensitivities.

The above mentioned techniques have been tested using a ~6000 bus state estimator model covering the entire Western Interconnection and for the Southern California problem areas suggested by California ISO. These results are presented within this report.

Over the past 40 years, more than 30 major blackouts worldwide were related to voltage instability and collapse. Among them, at least 13 voltage-related blackouts happened in the United States, including two major blackouts in the Western Interconnection in 1996 and a wide-scale blackout in the Eastern Interconnection in 2003. Several times, the blackout investigation teams indicated the need for on-line power flow and stability tools and indicators for voltage performance system-wide in a real-time. These recommendations are not yet completely met by the majority of U.S. power system control centers. The gap between the core power system voltage and reliability assessment needs and the actual availability and use of the voltage security analysis tools was a motivation to come forward with this project. The project's aim was to develop state-of-the-art methodologies, prototypes, and technical specifications for the Real-Time Voltage Security Assessment (RTVSA) tools. These specifications can be later used by selected vendors to develop industrial-grade applications for California Independent System Operator (CA ISO), other California Control Area Operators, and utilities in California.

An extensive analysis of existing VSA approaches was conducted. This included research by Consortium for Electric Reliability Technology Solutions (CERTS), surveys from the leading experts' opinion worldwide, feedback from industrial advisors, and brainstorm meetings with the projects' industry and academia consultants. A state-of-the-art combination of approaches and computational engines was identified and selected for implementation in this project. Subsequently, a multi-year project roadmap was developed which has guided the CERTS research on evaluating and demonstrating the recommended approaches on the CA ISO test cases.

The initial framework of this project was originally formulated in close consultation with the California ISO. The key elements of the suggested approach which are the use of parameter continuation, direct methods, and the hyperplane approximation of the voltage stability boundary were approved by a panel of leading experts in the area in the course of a survey conducted by Electric Power Group, LLC (EPG) at the project's onset in 2005. These concepts were also verified in the course of face-to-face personal meetings with well-known university professors, industry experts, software developers, and included email discussions and telephone exchanges. CERTS industrial advisors approved these developments during various CEC Technical Advisory Committee (TAC) meetings conducted in the past years.

In 2005, the project development team successfully implemented the parameter continuation predictor-corrector methods. Necessary improvements were identified and developed. The Power Systems Engineering Research Center (PSERC) parameter continuation program and MATLAB programming language were used in the project. During 2006-07, research work included the implementation of Direct Methods to quickly and accurately determine the exact Point of Collapse (PoC), Boundary Orbiting techniques to trace the security boundary, the investigation of descriptive variables, and the validation of techniques for analyzing margin sensitivities. These techniques were tested using a ~6000 bus state estimator model covering the entire Western Interconnection and, for the Southern California problem, areas suggested by California ISO, and results were reported.

At the completion of the project, a functional specification document was developed which describes the design, functional and visualization requirements for a Real-Time Voltage Security Assessment (RTVSA) tool, as well as CA ISO's preferences on certain implementation and visualization techniques.

Over the past 40 years, more than 30 major blackouts worldwide were related to voltage instability and collapse. Among them, at least 13 voltage-related blackouts happened in the United States, including two major blackouts in the Western Interconnection in 1996 and a wide-scale blackout in the Eastern Interconnection in 2003. Several times, the blackout investigation teams indicated the need for on-line power flow and stability tools and indicators for voltage performance system-wide in a real-time. These recommendations are not yet completely met by the majority of US power system control centers. The gap between the core power system voltage and reliability assessment needs and the actual availability and use of the voltage security analysis tools was a motivation to come forward with this project. The project aims to develop state-of-the-art methodologies, prototypes and technical specifications for the Real-Time Voltage Security Assessment (RTVSA) tools. These specifications can be later used by selected Vendors to develop industrial-grade applications for California Independent System Operator (CA ISO), other California Control Area Operators, and utilities in California.

Currently CA ISO's real time operations do not have a real-time dispatcher's Voltage Security Assessment tool and corresponding wide-area visuals to effectively manage the voltage and VAR resources on the transmission system and to identify the following:

• Voltage security margin calculation
• Worst-case contingencies leading to voltage collapse
• Abnormal reductions of nodal voltages
• Contingency ranks according to a severity index for system problems
• System conditions with insufficient stability margin
• Weakest elements within the grid
• Controls to increase the available stability margin and avoid instability

The objectives of this report are to present a comprehensive survey of algorithms available worldwide for the purpose of performing voltage security assessment, make recommendations on the most appropriate techniques, and describe a framework along with the algorithms that have been included in the prototype RTVSA tool.

The California Energy Commission (CEC), with input from CA ISO, requested an initiative to explore better avenues to optimize utilization of the existing transmission. As the first step to achieve this objective, Consortium for Electric Reliability Technology Solutions (CERTS)/Electric Power Group (EPG) formulated a survey to reach out to experts in this field for comments, information, suggestions, and recommendations. The choice of the PSERC (Power Systems Engineering Research Center) engine as a basis for building the VSA prototype was motivated by the results of the survey (described in Section 4). The algorithmic details can be found in Section 5.

Voltage stability is the ability of a power system to maintain acceptable voltages at all buses in the system under normal operating conditions and after being subjected to a disturbance. A system enters a state of voltage instability when a disturbance, increase in load demand, or change in system condition cause a progressive and uncontrollable decline in voltage. The main factor causing voltage instability is the inability of the power system to meet the demand for reactive power. Voltage collapse is the process or sequence of events accompanying voltage instability which leads to a low unacceptable voltage profile in a significant part of the system.

Objectives

Develop functional specifications for a Real-Time Voltage Security Assessment (RTVSA) tool that monitors voltage stability margin in real time, and help the real time dispatchers to manage this margin by controlling VAR resources, generation dispatch, and other resources on the transmission system. This application is expected to seamlessly integrate with the CA ISO's real-time network analysis sequence (EMS) and run automatically after each successful state estimation process at every 5 minute intervals or on demand. The tool will help to identify the following:

1. Available voltage security margin
2. The most dangerous stresses in the system leading to voltage collapse
3. Worst-case contingencies resulting in voltage collapse and/or contingencies with insufficient voltage stability margin
4. Contingency ranking according to a severity index for voltage stability related system problems
5. Weakest elements within the grid and the regions most affected by potential voltage problems
6. Controls to increase the available stability margin and avoid instability
7. Information about voltage problems at the look-ahead operating conditions and for the worst-case contingencies (contingencies with large severity ranks) that may appear in the future
8. A real-time dispatcher's situational awareness-type wide area graphic and geographic displays.

Approach

An extensive analysis of existing VSA approaches was conducted. This included research by Consortium for Electric Reliability Technology Solutions (CERTS), surveys from the leading experts' opinion worldwide, feedback from industrial advisors and brainstorm meetings with the projects' industry and academia consultants. A state-of-the-art combination of approaches and computational engines was identified and selected for implementation in this project. Subsequently, a multi-year project roadmap was developed which has guided the CERTS research on evaluating and demonstrating the recommended approaches on the CA ISO test cases.

This document describes the design, functional and visualization requirements for a Real-Time Voltage Security Assessment (RTVSA) tool, as well as CA ISO's preferences on certain implementation and visualization techniques.

The Consortium for Electric Reliability Technology Solutions (CERTS) has been working with NERC, Regional Transmission Organizations, Independent System Operators, and other electric industry organizations to research, develop, and disseminate new methods, tools and technologies to protect and enhance the reliability of the U.S. electric power system under the emerging competitive electricity market structures. The monitoring system offers a base from which grid security and market efficiency can be improved to help protect the market from "gaming" and other forms of market manipulations. CERTS has developed the Grid Real-Time Performance Monitoring and Prediction Platform (Grid-3P) to manage grid reliability and monitor market performance in real time. The purpose of the Supplier and Control Area Performance Monitoring System is to provide real-time intelligence on grid operations that will enable operators to monitor performance of Suppliers to provide competitive services and respond to their performance in a predictable manner.

The Consortium for Electric Reliability Technology Solutions (CERTS) has been working with NERC, Regional Transmission Organizations, Independent System Operators, and other electric industry organizations to research, develop, and disseminate new methods, tools and technologies to protect and enhance the reliability of the U.S. electric power system under the emerging competitive electricity market structures. This Summary Report provides a description of the Real-Time Voltage Monitoring and VAR Management System tool being developed to provide the capability to monitor grid and market performance in real-time and manage grid reliability.

The ACE-Frequency Monitoring System using CERTS' Grid-3P, will enable NERC Reliability Coordinators to monitor ACE-Frequency performance and compliance with performance operational guides within their jurisdictions, and will also allow NERC Staff and Subcommittees to analyze and assess control data to improve reliability performance. The ACE-Frequency Real-Time Monitoring System translates raw operational control data into meaningful operations performance information for end users. Should an abnormal interconnection frequency occur, a Real-Time Interconnection Abnormal Frequency Notification (AFN) is automatically issued via email or beepers describing the date, time, and magnitude of the frequency abnormality to specific Operational Authorities, NERC Resources Subcommittee members, and NERC Staff. The notification recipients using the ACE-Frequency Monitoring System functionality can quickly assess the abnormality's root cause by drilling down from wide-area to local-area visualization displays that include appropriate information and analysis graphs to easily identify and assess those control area(s) out of compliance and potential originators of the notified interconnection frequency abnormality.

The key elements of the ACE-Frequency Monitoring System include the following:

• Enables monitoring of ACE for each of the 123 Control Areas operating in the U.S. The data is updated every one to four minutes.
• The Grid-3P visualization infrastructure provides color coded graphics displays indicating status of a region control area, reliability authority or interconnection.
• Monitoring functions that provide details of various functions allowing users to drill down to the desired level of data and graphic displays for key diagnostics.
• The Real Time Interconnection Abnormal Frequency Notification (AFN) issues email notifications and enables the user to assess the root-cause for abnormal frequencies.
• ACE-Frequency Data Collection Tool archives raw data from the NERC Database for review and analysis.

This paper presents experimental results associated with the human factors aspects of using color contours to visualize electric power system bus voltage magnitude information. Participants were divided into three groups: the first group only one-line numeric data, the second only one-line contour data, while the third saw both. The purpose of the experiment was to determine how quickly participants could both acknowledge low voltage violations and perform corrective control actions. Results indicated the contour only visualization resulted in the quickest voltage violation acknowledgments, while the numeric data only visualization resulted in the quickest solution times. Testing was done using a modified version of the IEEE 118 bus system.

This user guide is intended for the operations engineering staff that will be utilizing synchronized phasor measurement (SPM) base applications to measure and analyze post disturbance analysis. This will be done via an integration of three separate tools. They are as follows:

• PSMTools — Pacific Northwest National Lab
• Synchronized Phasor Management Outlook Tool — Southern California Edison
• Streamreader and PhasorFile Tools — Bonneville Power Administration

Information for hands-on use of these tools is presented in the Tools section of this User's Guide. Theoretical background information, such as systems architecture, engineering value information, and fundamentals that are not directly applicable to the hands-on use of the tools, is available in the Appendix.

For the purposes of this Users Guide, these three tools will collectively be referred to as Synchronized Phasor Measurement Tools (SPM).

PSMTools R 12 — The system developed at Pacific Northwest National Lab (PNNL), was developed for analysis only, and was not designed for monitoring.

Phasor Management Outlook Tool R 0.9 — The system developed at Southern California Edison was intended for both monitoring and analyzing the data.

StreamReader and PhasorFile Tools R 1.0 — The system developed at Bonneville was intended for monitoring the data only. There is no function for analysis.

The four major processes for the utilization of synchronized phase measurements are:

• Data Acquisition
• Post Disturbance Analysis
• Result analysis, Model Validation, and Remediation Planning
• RAS Threshold Validation

Further details for each of these high level processes can be found in the Appendix.

This guide is intended for post disturbance analysis and model validation only. Once the data has been gathered, the raw data can be cleaned and filtered and the post disturbance analysis can begin. Phase-2 of the CERTS project will produce a complement user guide for dispatchers.

This paper describes an experimental approach to formally testing the usability of different power system visualizations. In particular, the ability of participants to assess and correct power system voltage problems was tested. Participants were divided into three groups: the first group only saw tabular data, the second group one line data, while the third group saw one-line data and a color voltage contour. The time to acknowledge the voltage violations and the time to correct the violations were assessed.

Evidence of reliability challenges comes from increasing incidence of transmission congestion, price spikes, voltage degradation, and managed and unmanaged outages are all indicators of stress on the system. Traditional grid operations and reliability management strategies and tools did not envision today's high-pressure environment in which there are increased demands on existing corridors to support greater trade. In particular they did not envision reliance on a competitive market for the buying and selling of electricity and reliability-related (or ancillary) services. Operators are being constantly challenged to manage these increasingly unpredictable power flows with an aging and increasingly inflexible transmission infrastructure. The tools and technologies available for this task - developed originally to support centrally-planned, vertically-integrated operations—are currently inadequate for managing reliability in competitive, region-wide electricity markets.

In 1999, for the first phase of its work in the area of Real-Time Grid Reliability Management, CERTS created prototypes for operational software tools to help dispatchers maintain and enhance electric system reliability (see Figure 1). The Department of Energy's Transmission Reliability program funded the initial development of the prototypes. The California Energy Commission's Public-Interest Energy Research Program is currently funding demonstrations of the prototypes at the California Independent System Operator (ISO). CERTS is also in discussions with utilities and ISO's in other regions of the country, as well as the North American Electric Reliability Council for additional demonstrations and extensions of these prototypes.

CERTS is developing a series of integrated computer base reliability adequacy tools that will help power system Operating Authorities (e.g. ISOs, RTOs and Security Coordinator) comply with the North American grid reliability standards. As part of the integrated approach, an Ancillary Services Performance, Tracking and Predictive Adequacy Application (ASPTP) is being developed for a Host Control Area located within the Western System Coordinating Council (WSCC).

The purpose of this document is to define the functional and design specifications for a ASPTP application for Ancillary Services such as Regulation, Operating Reserves Spinning, Operating Reserves Non-Spinning and Replacement Reserves. The functionality of this application has been identified and defined based on current market processes used to acquire Ancillary Services in California and on the reliability standards of three organizations, a) NERC and its Policy 1 and 10, which addresses generation control and ancillary services. b) The WSCC and its reliability policies and guidelines and, c) additionally, feedback from other CERTS related projects.

This paper demonstrates the use of a slow coherency based generator grouping algorithm and a graph theoretic approach to form controlled islands as a last resort to prevent cascading outages following large disturbances. The proposed technique is applied to a 30,000-bus, 5000-generator, 2004 summer peak load, Eastern Interconnection data and demonstrated on the August 14, 2003 blackout scenario. Adaptive rate of frequency decline based load shedding schemes are used in the load rich islands to control frequency. The simulation results presented show the advantage of the proposed method in containing the impact of the disturbance within the islands formed and in preventing the impact of the disturbance from propagating to the rest of the system. This is demonstrated by the significant reduction in line flows in the rest of the system and by improved voltage and relative angle characteristics. Based on the suggestion in the joint US-Canadian task force final report on the blackout, load shedding without any islanding is also performed and results obtained are compared with the proposed controlled islanding method. The islanding method outperforms the load shedding only method in reducing the transmission line flows but both methods have similar effects on voltage and relative angle behavior.

The project overall objective is to contribute to transmission system reliability by understanding large, cascading failure blackouts. The project analyzes cascading failure and large blackout risk by developing and studying power system and probabilistic models of cascading failure. These models show that blackout risk can sharply increase at a critical loading as power system loading is increased and can explain the distribution of blackout sizes observed in NERC data. The probabilistic models show how to relate the tendency for failures to propagate to the probability of various sizes of blackouts.

Slow coherency has effectively proved its capability in determining sets of generator groups among weak connections in any given power system. In this paper, we provide two comprehensive approaches to deal with islanding the actual system based on the grouping information, by using the minimal cutsets technique in graph theory. The issue of minimal cutsets has been widely discussed in areas related to network topology determination, reliability analysis, etc. The results of this paper also show potential in application to power system islanding. The verification of the islanding scheme is provided based on a WECC 179-Bus, 29-Generator test system.

As economic pressures result in greatly expanded utilization of facilities, the issue of power system security analysis is key to reliable operation at maximum efficiency. Security analysis in this context refers to the ability of a power system to withstand pre-specified disturbances called contingencies. This report presents results on the identification of the current state of power system security analysis for operations and the potential integration of the various existing power system security analysis tools. Current security analysis consists of numerous software tools (some off-line and some on-line) that predict operator guidelines for transaction scheduling. A survey of selected operators in representative locations in both the East and Western US was conducted to determine the effectiveness of current tools and the need for future improvements. The primary outcome of that survey indicated that:

• There is a wide variation of satisfaction with the quality of the models used
• Network model reduction is done offline
• Virtually all operators are satisfied with their SCADA systems
• Virtually all operators have operational online power flow tools
• Most operators are satisfied with their state estimation tools
• Most operators are satisfied with their static contingency analysis tools
• Very few optimal power flow (OPF) tools are in use
• Almost no security constrained OPF tools are in use
• Some voltage analysis or dispatch is done off line
• Almost all transient stability analysis is done off line
• Virtually no midterm, long-term, or eigenvalue stability analysis is performed

This project also investigated alternative frameworks for the integration of existing tools into a comprehensive package that can be more responsive to changing conditions and simultaneous transactions. This portion of the project leveraged resources with a Power Systems Engineering Research Center (PSERC) project by the same title. These alternative frameworks build on the availability of raw data from existing security tools for both static and dynamic considerations as follows:

• On-line estimation of security margins using current operating practices
• Creation of families of estimators, each specialized for specific system limits
• Testing of estimators on simulated systems
• Automate the process of evaluating security margins in off-line studies

The results show that it is possible to accurately estimate security margins for large systems on-line. The main limitation of the approach resides in the ability of time-consuming off-line studies to accurately model system dynamics. Directions for further development are proposed in a Roadmap For Future Security Analysis.

We generalize an analytically solvable probabilistic model of cascading failure in which failing components interact with other components by increasing their load and hence their chance of failure. In the generalized model, instead of a failing component increasing the load of all components, it increases the load of a random sample of the components. The size of the sample describes the extent of component interactions within the system. The generalized model is approximated by a saturating branching process and this leads to a criticality condition for cascading failure propagation that depends on the size of the sample. The criticality condition shows how the extent of component interactions controls the proximity to catastrophic cascading failure. Implications for the complexity of power transmission system design to avoid cascading blackouts are briefly discussed.

Electric power transmission systems are a key infrastructure and blackouts of these systems have major direct and indirect consequences on the economy and national security. Analysis of North American Electrical Reliability Council blackout data suggests the existence of blackout size distributions with power tails. This is an indication that blackout dynamics behave as a complex dynamical system. Here, we investigate how these complex system dynamics impact the assessment and mitigation of blackout risk. The mitigation of failures in complex systems needs to be approached with care. The mitigation efforts can move the system to a new dynamic equilibrium while remaining near criticality and preserving the power tails. Thus, while the absolute frequency of disruptions of all sizes may be reduced, the underlying forces can still cause the relative frequency of large disruptions to small disruptions to remain the same. Moreover, in some cases, efforts to mitigate small disruptions can even increase the frequency of large disruptions. This occurs because the large and small disruptions are not independent but are strongly coupled by the dynamics.

A model has been developed to study the global complex dynamics of a series of blackouts in power transmission systems [1, 2]. This model has included a simple level of self-organization by incorporating the growth of power demand and the engineering response to system failures. Two types of blackouts have been identified with different dynamical properties. One type of blackout involves loss of load due to lines reaching their load limits but no line outages. The second type of blackout is associated with multiple line outages. The dominance of one type of blackouts versus the other depends on operational conditions and the proximity of the system to one of its two critical points. The first critical point is characterized by operation with lines close to their line limits. The second critical point is characterized by the maximum in the fluctuations of the load demand being near the generator margin capability. The identification of this second critical point is an indication that the increase of the generator capability as a response to the increase of the load demand must be included in the dynamical model to achieve a higher degree of self-organization. When this is done, the model shows a probability distribution of blackout sizes with power tails similar to that observed in real blackout data from North America.

Electric power transmission systems are a key infrastructure and blackouts of these systems have major direct and indirect consequences on the economy and national security. In particular, electric power blackouts have cascading effects on other vital infrastructures. While it is useful to analyze the detailed causes of individual blackouts, in this paper we focus on the intrinsic dynamics of series of blackouts and how this complex system dynamics impacts the assessment and mitigation of blackout risk. Indeed, the mitigation of failures in complex systems needs to be approached with care.

Catastrophic disruptions of large, interconnected infrastructure systems are often due to cascading failure. For example, large blackouts of electric power systems are typically caused by cascading failure of heavily loaded system components. We introduce the CASCADE model of cascading failure of a system with many identical components randomly loaded. An initial disturbance causes some components to fail by exceeding their loading limit. Failure of a component causes a fixed load increase for other components. As components fail, the system becomes more loaded and cascading failure of further components becomes likely. The probability distribution of the number of failed components is an extended quasibinomial distribution. Explicit formulas for the extended quasibinomial distribution are derived using a recursion. The CASCADE model in a restricted parameter range gives a new model yielding the quasibinomial distribution. Some qualitative behaviors of the extended quasibinomial distribution are illustrated, including regimes with power tails, exponential tails, and significant probabilities of total system failure.

Catastrophic disruptions of large, interconnected infrastructure systems are often due to cascading failure. For example, large blackouts of electric power systems are typically caused by cascading failure of heavily loaded system components. We introduce the CASCADE model of cascading failure of a system with many identical components randomly loaded. An initial disturbance causes some components to fail by exceeding their loading limit. Failure of a component causes a fixed load increase for other components. As components fail, the system becomes more loaded and cascading failure of further components becomes likely. The probability distribution of the number of failed components is an extended quasibinomial distribution. Explicit formulas for the extended quasibinomial distribution are derived using a recursion. The CASCADE model in a restricted parameter range gives a new model yielding the quasibinomial distribution. Some qualitative behaviors of the extended quasibinomial distribution are illustrated, including regimes with power tails, exponential tails, and significant probabilities of total system failure.

As power system loading increases, larger blackouts due to cascading outages become more likely. We investigate a critical loading at which the average size of blackouts increases sharply to examine whether the probability distribution of blackout sizes shows the power tails observed in real blackout data. Three different models are used, including two simulations of cascading outages in electric power transmission systems. We also derive and use a new, analytically solvable model of probabilistic cascading failure which represents the progressive system weakening as the cascade proceeds.

This document is the first year report of a two-year CERTS (Consortium for Electric Reliability Technology Solutions) project studying large scale blackouts and cascading failures of electric power transmission systems. The project is inventing new methods, models and analysis tools from complex systems, selforganized criticality, probability, and power systems engineering so that the risks of large blackouts and cascading failures can be understood and mitigated from novel global and top-down perspectives.

Currently there are no well functioning reserve markets in use in the US. There is some evidence that a well functioning reserve market can help mitigate price spikes and solve the capacity problem. Currently reserves are thought of as having time dependent properties, that is, they must be spinning or able to synchronize in ten minutes or able to synchronize in thirty minutes. However, it is well known that given a network that can become constrained on voltage or real power flows, reserves must also be spatially located in order to handle all the contingencies that could occur. To date, there is no credible science-based method for assigning reserves in this way. Virtually all methods are ad-hoc and are based on engineering judgment and experience. The purpose of this work is to develop a sound basis and a methodology for assigning both real energy as well as reactive reserves.

A complete system for automated monitoring of multiple circuit breakers is developed for DOE by Texas A&M University. This system is characterized by a wireless-based architecture for data communication between newly developed Circuit Breaker Monitors (CBMs), as well as concentrator computer with intelligent software for automated analysis.

Circuit breakers are very important elements of the electrical power system. Usually, circuit breakers are manually initiated to interrupt current flow during normal operating conditions. They may also be automatically initiated to interrupt short-circuit currents during faults. The ability to operate a breaker and isolate a portion of the power system is very critical task and circuit breakers must be very reliable.

This document consists of three parts. The first two parts give the hardware and software prototype specification respectively. The third part provides details of the filed demonstration. The solution is aimed at automating the analysis of switching sequences using GPS-synchronized records from the control circuitry collected by CBM devices installed at each breaker.

Hardware report is described in PART 1. It defines improvements in the circuit breaker monitoring (CBM) device made during the year 2006. Signal conditioning board, communication protocol and time synchronization module have been modified and upgraded. These modifications are necessary to enable monitoring over the entire power system and to reduce cost of the device. Report presents lab and field-test setups. Two CBM units are developed and installed at CNP substation in south Houston area. Functional requirement specification for automated circuit breaker monitoring device is created and attached in the appendix. Final reports for year 2003 and 2005 are also provided in the appendices of PART 1.

The software specification is given in PART 2. This part of the report describes the types of sequences to be analyzed and their properties of interest. The specification outlines the system architecture pointing out how multiple CBM devices are synchronized using GPS receivers located in substations. The specification gives details of the requirements for the application software consisting of modules that perform signal processing for feature extraction and expert system reasoning for analysis conclusions. The specification of the software also includes detailed requirements for the user interface, which is needed at a location where the users of the information are situated. The specification outlines requirements for software testing.

Third part (PART 3) presents in-service demonstration of hardware and software developed for DOE by Texas A&M University. The topology builder software is used to provide spatial component of the sequence analysis. This tool enables user to draw topology of the power system, which should be analyzed. The Sequence Analyzer application, which makes it possible to track sequence of events and make conclusions about their effect, is demonstrated. Finally, status of hardware is briefly presented, which is specified in more details in PART 1.

This solution is developed and tested at a prototype stage and is now ready for further design tuning and filed deployment leading to a commercial product.

The intent of this document is to lay a general foundation for effective and systematic management of data and information for real-time performance monitoring of large power systems. It does so through a consideration of overall data applications, and by drawing upon industry experience in the operation of wide area measurement systems. The treatment of these topics is intendedly broad, and digressions into underlying details have been avoided so far as possible. The reader may note, for example, that the distinction between data and information is not absolute—e.g., the information produced by one process may serve as raw input for some later process at higher level. There is also some ambivalence in terms such as "archive" and "real time." Their meaning was fairly clear for analog data streams, but it is much less so for high performance digital systems. Such terminology should be interpreted according to context, and with support from the various cited references. A Glossary is provided in Section 9 as a guide to acronyms.

Circuit breakers (CBs) are very important elements in the power system. They are used to switch other equipment in and out of service. Circuit breakers need to be reliable since their incorrect operation can cause major issues with power system protection and control. Today's practice in monitoring circuit breaker operation and status in real time is reduced to the use of Remote Terminal Units (RTUs) of Supervisory Control and Data Acquisition (SCADA) system to assess CB status. More detailed information about the control circuit performance may be obtained by CB test equipment typically used for maintenance diagnostics [1].

This paper addresses two important issues: a) how improved CB monitoring may be implemented in real-time, and b) what would be the benefits of such an implementation.

The results reported in this paper are coming from two research projects, conducted using funding from CenterPoint Energy and DOE-CERTS aimed at development of software for automated analysis of CB data and the other covering development of the CB data acquisition unit respectively. The paper is devoted to description of a prototype implementation of a real-time CB monitoring system. The system consists of a new CB monitoring data acquisition IED that is located at circuit breaker and captures detailed information about its operation in real-time. The CB files are transferred to the concentrator PC where the application software performs automated analysis and makes an assessment about the operational status of the breaker. The software is based on signal processing and expert system processing. Application example using actual field data is discussed.

The paper ends with some conclusions, acknowledgments and a list of references.

This Software Requirements Specification defines the functions of a simulation power grid model. The model defines grid control functions that focus on real-time control and related communication of information among entities that share the operation of the power grid. Deregulation of the power markets necessitates increased communications among entities who have economic motivation to restrict access to important information from other market participants. New power market concepts will impact how planning and real-time control are performed. The simulation power grid model provides the tool for investigating issues of distributed computing, data sharing, data access, communication system capacity, and communications reliability. The model enables researchers to develop intelligent distributed control agents for managing Area Control Error and transmission security. The software requirements specification is defined using a subset of the Unified Modeling Language, a class diagram describing all of the objects along with their attributes, methods, and some modified use cases.

With deregulation of the power generation sector, the necessity for an enhanced and open communication infrastructure to support an increasing variety of ancillary services is apparent. A duplex and distributed communication system seems to be the most suitable solution to meet and ensure good quality of these services. Parameters needed and additional limits introduced by this new communication topology must be investigated and defined. This paper focuses on the communication network requirements for a third party load frequency control service. Data communication models are proposed based on queuing theory. Simulation is performed to model the effects of certain types of signal delays on this ancillary service.

This paper shows how a competitive ancillary service market for voltage control/reactive power might operate and what it might look like, given the eminently local nature of the service. An automatic voltage control would dynamically manage the reactive power available in a certain geographic region and a local market in reactive power could then be developed similarly to that proposed for the load-following ancillary service. Coordination among these regions would be required.

The goal is to be able to receive, on a local PDC, all the phasor data collected by a remote PDC. For a fully configured PDC, this means 16 PMUs, with 10 phasors per PMU for a total of 160 phasors. For a fully configured expanded PDC, this means 32 PMUs, with 10 phasors per PMU for a total of 320 phasors.

Accurate knowledge and prediction of system behavior is essential to the reliable and economic operation of large power systems. This paper describes the efforts underway to meet this need in the western system.

Intelligent agents and multi-agent systems promise to take information management for real-time control of the power grid to a new level. This report presents our concept for intelligent agents to mediate and coordinate communications between Control Areas and Security Coordinators for real-time control of the power grid. An appendix describes the organizations and publications that deal with agent technologies.

The restructuring of the U.S. power industry will surely lead to a greater dependence on computers and communications to allow appropriate information sharing for management and control of the power grid. This report describes the operating environment for system operations that control the bulk power system as it exists today including the role NERC plays in this process. Some high-level functional requirements for new approaches to control of the grid are listed followed by a description of the next research steps that are needed to identify specific information management functions.