Power System Analysis, Planning and Operations (PSAPO)...

Power System Analysis, Planning and Operations (PSAPO) Summary of 2008 Products

Program Product Id Product Description Product

Type Manager Date

P39 1016954 TI

Program on Technology Innovation: Power System Oscillation Detection and Contribution Identification Using Wide-Area GPS Synchronized Phasor Measurements

Technical Update

Zhang, Guorui 27-Jun-08

P39 1016993 Multiple Uses of Substation Data

Technical Update Myrda, Paul 30-Jun-08

P39 1018178 TI

Program on Technology Innovation: Next Generation Monitoring, Assessment, and Control

Technical Update Zhang, Pei 22-Jan-09

P39 1018392

Program on Technology Innovation: An Investigation of the Stability Region Concept Applied to Stability-Constrained Optimal Power Flows

Technical Update Zhang, Pei 31-Mar-09

P39 1018451

Competitive Path Analysis Using Mathematical Programs with Equilibrium Constraints

Technical Update

Entriken, Robert 30-Mar-09

P39 1018715

Evaluation of the Effectiveness of Automatic Generation Control (AGC) Alterations for Improved Control with Significant Wind Generation

Technical Update

Brooks, Daniel 26-May-09

P39 1018716

Evaluation of the Impacts of Wind Generation on HELCO AGC and System Performance - Phase 2

Technical Update

Brooks, Daniel 26-May-09

P39.001 1015990

Situation Awareness in Power System Operations: Guidelines and Recommendations for Supporting Situation Awareness

Technical Update

Lee, Stephen Ting-Yee 7-Nov-08

P39.002 1015991 Best Practices in State Estimation

Technical Update Min, Liang 1-Dec-08

P39.002 E228175 Next Generation State Estimation Workshop

Technical Resource Min, Liang 14-Oct-08

P39.003 1015993

Controlled System Separation: Key Issues, Industry Practices and State-of-the-Art Technologies

Technical Update Zhang, Pei 21-Nov-08

P39.003 1015994

Prototyping a Decision Support Tool for Evaluation of System Restoration Strategy Options

Technical Update Zhang, Pei 4-Dec-08

P39.003 E228176 Workshop on System Restoration Technical Resource Zhang, Pei 12-Nov-08

P39.004 1015995

Identification of Critical Voltage Control Areas and Determination of Required Reactive Power Reserves



Type Manager Date

P40.001 1015997

PCF v1.0 Probabilistic Transmission Congestion and Constraints Forecast, Version 1.0 Software Min, Liang 12-Dec-08

P40.001 E228177 Workshop on Probabilistic Planning Technical Resource Min, Liang 19-Aug-08

P40.002 1015998 Grid Shunt Reactive Power Compensation

Technical Update

Entriken, Robert 26-Nov-08

P40.003 1015999 Comprehensive Load Modeling for System Planning Studies

Technical Report

Brooks, Daniel 31-Mar-09

P40.004 1016000

Automated Model Validation for Power Plants Using On-Line Disturbance Monitoring

Technical Report

Pourbeik, Pouyan 31-Mar-09

P127 1018186

Summary of Recommendations from NERC Reliability Readiness Evaluations

Technical Update

Lee, Stephen Ting-Yee 20-Oct-08

P127 1018402 2008 CIM-XML Interoperability Including CIM-Based Tools Test

Technical Report

Becker, David 4-Dec-08

P127 1018440 The 2008 Transmission Planning Interoperability Test

Technical Report

Becker, David 27-Feb-09

P127 1018587 Vision for a Holistic Power Supply and Delivery Chain

Technical Update

Lee, Stephen Ting-Yee 6-Feb-09

P127.001 1016038 A Vision of Self-Healing Protection and Control


P127.002 E228182 Conduct EPRI CIM/GID WS for general multiple utility audiences

Technical Resource

Becker, David 23-Sep-08

P127.004 1016042 EPRI Power System Dynamics Tutorial

Technical Report

Zhang, Guorui Delayed

P127.004 E228184 OTS User Group Meeting and Workshop for Operator Training

Technical Resource

Zhang, Guorui 13-Nov-08

P127.005 E228185 Technical Conference on ERO Reliability Standards

Technical Resource

Lee, Stephen Ting-Yee 30-Aug-08

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Program Product Id Product Description Product Type Manager Date

P39 1016954

Program on Technology Innovation: Power System Oscillation Detection and Contribution Identification Using Wide-Area GPS synchronized Phasor Measurements

Technical Update Zhang, Guorui 27-Jun-08

Abstract Generator and load drops can be detected in real-time with high dynamic accuracy using wide-area frequency measurement systems. This report describes the research and development of a screening tool that can also detect frequency oscillations using the Internet based Frequency Monitoring Network (FNET) and similar systems. It includes analyses of the characteristics of low-frequency oscillations in the time domain and the frequency domain and a preliminary investigation of possible ways of using wide-area measurements to mitigate low-frequency oscillations. Background Frequency perturbations after events like generation trips travel through a power system grid with finite speed and therefore arrive at particular Frequency Disturbance Recorders (FDRs) at different times. The FDRs sample the voltages at different locations; calculate the frequency, angle, and magnitudes of the voltage; and send the data to an Information Management System (IMS) through Internet. Event location algorithms can use data from this system to triangulate the location of an initiating event and estimate its size. It is desired to extend this trigger capability to the detection of oscillations. The oscillations of interest, in general, have a frequency of less than 1-2 Hz. Objective • To develop and implement oscillation triggering methods using FNET data • To analyze low-frequency oscillations characteristics in the time domain and the frequency domain • To make a preliminary study of low-frequency oscillation mitigation

Approach The project team adapted an oscillation-screening tool for use in real-time oscillation detection and tested it with field data from the FNET. The tool employs the oscillation envelope method. The team studied low-frequency oscillation in both the time and the frequency domain using simulations and FNET field measurements made during several disturbances in the Eastern Interconnection in 2007. They also made a survey of recent literature on low-frequency oscillation mitigation including some preliminary results on controlling system dynamics by strengthening transmission corridors. Results This report describes the test results of an oscillation-screening tool using FNET field data. Although the current tool employs the oscillation envelope method, the "sequential peaks" detection method and the fast Fourier transform (FFT) approach may have their merits and should be tested and implemented in future works. The modular approach of the current design should allow multiple oscillation trigger algorithms to be incorporated without major structural changes. In the course of studying low-frequency oscillation characteristics, it was concluded that almost all the inter-area oscillations in the Eastern Interconnection involved a very large number of generators. This finding provides practical information for developing control strategies and guiding the placement of control devices—local mode oscillations, not the focus of this study, are typically dominated by one or two machines and are relatively easy to manage locally. With the assistance of wide-area measurements provided by phasor measurement units (PMUs) and FNET, more powerful tools are now at hands to help detect and analyze the oscillations in bulk power systems, discover new phenomena, and develop new control methods for interconnected power grids. EPRI Perspective From the FNET measurements alone, over 4 years worth of continues system dynamic performance data have been recorded (including frequency, angle, and voltage) in the Eastern Interconnection, WECC and ECORT interconnections. With such wealth of information, it is very likely that all the oscillation patterns or modes are fully characterized and can now be exploited for the design of control and damping systems. For example, with a sufficient number of power system stabilizers (PSS) in any of the 3 systems, wide area control should already be close to reality. The coordination of a group of wide spread power system stabilizers using wide area measurements is well within reach and is a promising area for further research.



P39 1016993 Multiple Uses of Substation Data Technical Update Myrda, Paul 30-Jun-08 Abstract This report describes a suite of modules developed under the Multiple Uses of Substation Data project. The modules are aimed at the integration and automated analysis of data coming from several Intelligent Electronic Devices (IEDs) such as Digital Protective Relays, Digital Fault Recorders and Circuit Breaker Monitors. Once data are collected, automated analysis processes the files to extract relevant information. The modules convert non-operational data to information that may be used by variety of applications at Control Center level. The results obtained from the application may be integrated with such utility applications as: Substation Automation, Supervisory Control and Data Acquisition (SCADA), Energy Management System (EMS), Geographic Information System (GIS), Outage Management, Asset Management, and Lightning Detection. IED data are currently used quite differently. Usually data from IEDs are collected manually and then sent to protection engineers for analysis. Often the data are in the original vendors’ format and can only be displayed using the vendors’ tool. Integrating data for analysis purposes from several different vendors are used is not straightforward due to the use of different data formats and the fact that different vendors may use different terminology for the same signals and settings in the IEDs. Because of these complications, the process of analyzing data becomes a complex and time consuming job that only a skilful person with lot of experience can do. Products developed under this project perform the analysis process automatically, convert data from all devices to a single format, generate reports for each IED type, and fill out a database with processed information, which in turn can be displayed using single visualization tool that makes all information accessible immediately after the occurrence of an event. Objective These applications are aimed at substation groups that consist of protection engineers and maintenance staff, as well as control center groups that consist of dispatchers and operators. Substation groups can be informed about faults immediately and can make quick decisions on responses. Maintenance personnel can be informed about the status of the equipment and any maintenance actions rapidly and without a need to go to the field to perform periodic tests. The control center group can get additional information from IEDs that can improve interpretation of alarms and system restoration procedures. The challenge is to integrate support for these various application tasks across the utility enterprise. The solution requires close collaboration between different utility groups. The objective of this report was to illustrate what is involved in this demanding process and what are the expected benefits once the products are successfully deployed. Approach: The project team demonstrated how the gradual deployment of the modules and proposed applications can work as a cost-effective retrofit strategy. The deployment of the developed modules does not require change in the existing use of the equipment and can be performed without disturbing existing operations. It only requires the addition of processing and communication infrastructure so that the existing data are fully utilized. Results: The main benefit of this project is to increase the efficiency of the utility personnel responsible for analyzing faults, repairing damaged equipment, and restoring a system. At present, IED data records cannot be efficiently analyzed manually due to the overwhelming number of records captured by devices in the system. Also, use of different vendor specific programs increases personnel training costs due to the distinctively different features and look and feel of different packages. There is slow response if several records supplied by different IEDs for the same event must be uploaded and analyzed. Indeed, it is impossible to efficiently integrate data coming from different IED types and models when different IED systems and services must be integrated. The applications developed in this project make it possible to handle all these tasks more efficiently. Application, Value and Use: The modules developed in this project, along with modules developed by third parties and integrated with the project modules, may be used to develop a variety of applications supporting protection group, as well as maintenance or operations staff. The core of the applications is customized report generation and conversion of non-operational data to real-time information. Due to competitive market conditions, each utility needs to respond to system disturbances in the most effective possible way. The solution proposed in this report recognizes the value of IED data integration and processing in speeding up the restoration of the system after loss of service. The use of the developed applications and generated information allows utilities to increase the efficiency of their personnel and meet reporting standards imposed by the regulatory and oversight bodies such as FERC and NERC, Inc. EPRI Perspective: This report attempts to fully utilize IED data recorded at substation level. This development will help utility industry meet many internal and external goals. The internal goals for increased personnel productivity and more reliable system operation are met through introducing automated data processing and integration of operational and non-operational data. The external goals of meeting reporting standards of FERC and NERC, Inc. are met by performing real-time analysis of disturbances and creating comprehensive reports explaining the cause-effect sequences in system operation automatically.



P39 1018178

Program on Technology Innovation: Next Generation Monitoring, Assessment, and Control

Technical Update Zhang, Pei 22-Jan-09

Abstract Power system operation technologies such as computerized one-line diagram visualization, state estimation, contingency analysis, and distance relay were developed upwards of 50 years ago, However, technological advances in communication, computing, and algorithms have made it possible to reexamine methods for performing real-time monitoring, assessment, and control. This report describes the vision, infrastructure, and technology roadmap for future smart control centers. Objective The challenges lie in how to transform the existing control centers in terms of three core functions—monitoring, assessment, and control—to future smart control centers. The present technologies for these functions have a number of limitations, which prevent flexible, efficient, and sustainable power system operation. The objective of this report is to present a vision of next generation monitoring, assessment, and control technologies and provide a roadmap for achieving that vision in future smart control centers. Approach The proposed vision of next generation monitoring, assessment, and control functions is based on analysis of cutting-edge technology in communication and control. Such an analysis will help ensure that the eventual long-term vision is technologically viable. In developing this report, the authors reviewed key literature on self-healing protection and control systems and the Intelligrid. Results This report reviews the present monitoring, assessment, and control technologies in power system control centers in detail. Several popular commercial-grade products for self-healing protection and control are briefly examined. The report then describes the vision of the future smart monitoring, assessment, and control functions. That discussion compares the vision with the present technologies and points out technology and infrastructure gaps. Finally, this report presents a roadmap for implementing prospective monitoring, assessment. and control technologies in future smart control centers. Application, Value and Use The proposed self-healing protection and control framework can improve overall performance of existing protection and control systems. Implementation of the proposed self-healing protection and control framework will reduce the likelihood of cascading failures and will therefore increase system reliability. To implement the self-healing protection and control framework, however, the existing computing and communication infrastructures need to be improved and a variety of technical issues must be resolved through further research and development. EPRI Perspective The functions of the proposed future smart control centers can be applied to all U.S. power system control centers if implemented correctly, so the value and impact are broad. Future control centers are expected to utilize wide-area information for online, measurement-based security assessment in order to implement an automatic and decentralized control strategy. Hence, the system will be hybrid, integrated, coordinated, supervisory and hierarchical. This vision for future smart control centers is critical to implementing the overall framework of the future smart control grid, also known as the Intelligrid.



P39 1018392

Program on Technology Innovation: An Investigation of the Stability Region Concept Applied to Stability-Constrained Optimal Power Flows

Technical Update Zhang, Pei 31-Mar-09

Abstract This report presents the formulation of optimal power flow with linear dynamic stability constraints. Intensive off-line dynamic simulations were performed to capture the system instability separation modes corresponding to system disturbances and to further derive the linear coefficients for each hyperplane. Optimal power flows with and without the dynamic stability region constraints were computed, and dynamic simulations based on two sets of power flow solutions were performed. Comparison of the two sets of dynamic simulation results shows that the schedules based on optimal power flows with dynamic stability constraints can provide better system transient stability. Objective Current system operations can experience dramatic changes in operating conditions because generation is scheduled using hourly offers. This situation can make it difficult for system operators to assess power system dynamic stability in real time. Usually, system operators assess power system dynamic stability using the available transfer capability (ATC) within transmission corridors or the small-area nomograms that define the local limitations of transmission and generation, and then they reschedule energy delivery to maintain system transient stability. There are two issues with this practical approach. First, both the ATC and the nomograms are generated from off-line numerical integration of limited scenarios. They cannot cover the full dynamic stability limitations of an entire control area. Second, the rescheduling actions to move the operating point away from the ATC limits or nomogram boundaries usually are out-of-market actions and may not be cost-efficient. In this research, an OPF problem is proposed to solve the energy-scheduling problem with dynamic stability region constraints that are represented approximately by a set of hyperplanes that defines the space of stable operations. The investigation presents the feasibility of implementation and demonstrates the improvement in system transient stability based on the simulation of dynamic stability region–constrained OPF. Approach This research presents the formulation of the optimal power flow problem subject to the dynamic stability region constraints. Exploring a variety of cases demonstrates the effectiveness and benefits of representing the boundary of a dynamic stability region by a set of hyperplanes. Results Power system dynamic stability is critical for power system operations. Incorporating dynamic stability region constraints into optimal power flow (OPF) applications provides system operators with the energy schedules that allow the system to operate with sustained dynamic stability after disturbances. Using hyperplanes to represent the boundaries of the dynamic stability region makes modeling the dynamic stability region constraints in an OPF problem straightforward. Dynamic simulations based on energy schedules generated by an OPF subject to the dynamic stability region constraints demonstrate verified improvements in system transient stability. Application, Value and Use This research emphasizes the impact of the dynamic stability region constraints on the energy schedule, and so provides a rapid and preventive method to address power system dynamic stability issue in on-line operations. This method forms the core of an approach that can be applied to electricity market applications. EPRI Perspective Unlike the optimal power flow with static stability constraints, where the constraints represent the steady-state thermal limits or transmission capability, the optimal power flow with dynamic stability region constraints generates energy schedules that can ensure the transient stability of a system after disturbances. This report demonstrates the application of a dynamic stability region in energy scheduling and proves the sufficiency of representing the dynamic stability region approximately by the hyperplanes.



P39 1018451 Competitive Path Analysis Using Mathematical Programs with Equilibrium Constraints

Technical Update Entriken, Robert 30-Mar-09

Abstract This report extends a proposed method for detecting the potential to manipulate electricity markets in the presence of transmission scarcity. A screening method is used presently in different markets, which relies on cursory measures of transmission scarcity and competitive behavior. The extended method utilizes a Mathematical Program that maximizes profits for combinations of market participants in the presence of potentially scarce transmission resources. This new method incorporates production costs and obeys transmission limitations. As a result, it has the potential to reveal additional information about market competitiveness. Objective Market power is a crucial issue in wholesale electricity markets. Independent System Operators (ISOs) and regulators need tools for identifying bottlenecks that enable the exercise of market power. Once problems with scarcity and concentration of ownership are identified, counter measures can then be devised to mitigate impacts on market prices as well as strengthen market and system operations. The example in this report is taken from a proposal documented by the California ISO. Actual power systems are much more complex, and in practice these calculations are part of critical operations of markets and part of the monitoring tools. Further work on this subject, with additional case studies and efforts to fortify the calculations for large-scale systems, can reveal additional insights into the roles that transmission scarcity and production efficiency play in competitive markets. The most important recipients of these results are market monitors, who are mandated to explore and ensure market competitiveness. Approach A key goal of this report was to enhance the competitive path analysis to utilize equilibrium constraints for market conditions along with profit maximization to extract any possible opportunity to gain from transmission scarcity. The approach is to apply these methods an existing model and proposed technique and explore whether the addition of production cost information and transmission capacity constraints will create additional insights and/or alter the conclusions regarding priorities for mitigation. The goals are largely conclusive, despite potential differences between the models, that the enhanced method produces refined results with slightly different priorities. It also identified new modes of profit making, not found with the proposed method. While the proposed method identifies many potential cases for mitigation, the enhanced technique shows which cases carry more opportunity for profits. Results The enhanced approach provides a measure of pivotal status of market participants. Rather than based on system configuration and supply/demand information alone, it also reveals possibility of weakness in the transmission network that may be gamed via the strategic bidding. The results could assist Independent System Operators (ISOs) in operating the wholesale electricity market more efficiently. Regulators and system planners may also be benefitted in identifying the key system bottlenecks and prioritize improvements. Application, Value and Use Applications of competitive path analysis are directly related to mitigation of market power. However, in long time frames, this analysis provides insight into investment incentives and the potential for new investments to ensure competitive trading of electricity across regions. As the practices of national or continental planning become more prominent to properly coordinate energy planning across sectors, the type of economic modeling portrayed in this report will likewise become more prominent for its ability to balance resources across economic sectors and diverse regions. EPRI Perspective EPRI has pioneered the development and application of market simulation for the study of decision-making associated with electricity markets. While the use of computers to model markets in this way is relatively new, others have used people in similar market experiments for some time. Multi-agent simulation with optimal bidding techniques requires a significant investment of time. Its benefits, however, may be impossible to achieve with other methods. This type of simulation, utilizing fundamental modeling, is currently the best tool for understanding crucial but rarely experienced market phenomena such as energy crises. Its use for investigating market competition reveals details not observable with standard techniques.



P39 1018715

Evaluation of the Effectiveness of Automatic Generation Control (AGC) Alterations for Improved Control with Significant Wind Generation

Technical Update Brooks, Daniel 26-May-09

Abstract Wind power represents a significant fraction of the total generation capacity of the Hawaii Electric Light Company (HELCO) system, and HELCO system operators have observed instances where the short-term variability of the existing wind generation has resulted in increased frequency fluctuations. The existing automatic generation control (AGC) system has sometimes exacerbated these frequency fluctuations. To deal with this problem, HELCO contracted with AREVA to implement functional changes to the existing HELCO AGC as part of an energy management system (EMS) upgrade. The changes implemented by AREVA to the HELCO AGC can be grouped into three basic categories: general tuning of AGC parameters, changes to base AGC code modules, and the introduction of new AGC functions. This report evaluates the impact of wind generation on HELCO’s system frequency performance and regulation and assesses the effectiveness of the AREVA AGC modifications in improving system control in the presence of wind generation. Objective HELCO operates as a small isolated grid without the benefits of interconnection to neighboring control areas to provide system support through tie lines during a contingency. As a result, the HELCO system is more susceptible than mainland control areas to a range of negative impacts associated with fluctuations from load and/or generation. HELCO was concerned that with increasing wind penetration levels on the island (an additional 20 MW was scheduled to go online in 2007), the existing AGC would be unable to compensate for the resulting increased frequency fluctuations. Approach The project team compared historical AGC data sets recorded during low- and high-wind generation periods to estimate the impact that wind generation has on HELCO system frequency/ACE performance and AGC actions. Two sets of comparisons were made: one for HELCO’s base AGC configuration prior to AGC modifications and another for the system after AREVA implemented various changes to its AGC. Results: While many factors contribute to area control error (ACE) and frequency variations, wind generation is a significant driver. Furthermore, the amount of AGC activity is higher during the high-wind periods for both the pre- and post-modification data sets. The data show that the general tuning of AGC parameters had the largest impact on AGC performance of any single modification, reducing the total number of control actions and associated MW travel 60-75% relative to the control activity that occurred during high-wind conditions prior to the AGC tuning. An increase in area control error (ACE) and frequency deviation variability accompanied this reduced control activity, however. Other AGC modifications resulted in some increased level of total AGC control activity accompanied by slight to moderate improvements in frequency/ACE performance. Application, Value and Use: Although follow-up analysis conducted on more substantial data sets would validate the current study results, this initial assessment of the impacts of AGC alterations on the HELCO system provided a framework and baseline for ongoing study of the control problems wind generation presents to a generating system as it achieves significant penetration. EPRI Perspective: For the HELCO system, successful system control is likely to require an increased emphasis on improving the remote control characteristics at the generators themselves: optimizing ramp rates; minimizing time delays; and allowing greater range of control, which may require improvements on the generator control systems. Additionally, engineering expertise will be required at the control center for monitoring and adjustment of both unit and area level AGC parameters to optimize system performance. Even with these actions, the tolerable trade-offs between increased control activity and frequency degradation may limit the amount of wind generation that can be integrated into the system, especially if the wind capacity is concentrated in a common geographic region or single location. To study this problem, additional data analysis was performed in a Phase 2 effort using HELCO system AGC data collected during the summer of 2007, by which time an additional 20 MW of wind generation had become operational at the south end of the Island. This analysis, documented in EPRI report 1018716, provides further insight into control/performance tradeoffs under high wind penetrations that could reach as much as 35% of nightly minimum load levels.



P39 1018716 Evaluation of the Impacts of Wind Generation on HELCO AGC and System Performance – Phase 2

Technical Update Brooks, Daniel 26-May-09

Abstract: The Hawaiian Electric Light Company (HELCO) is integrating 33 MW of wind generation into its daily system operations. The percentage of load served by wind generation can at times be as high as 33% and result in serious integration problems for the utility. This project analyzed 819 hours of HELCO automatic generation control (AGC) and frequency performance data in order to quantify the impacts of wind variability on system frequency and AGC control actions and to identify potential mitigation strategies. Objective: HELCO’s system operations have directly experienced direct impacts from wind variability. These impacts have included a larger ambient frequency band due to sub-minute variations, large frequency excursions due unexpected sub-hourly (tens of minutes) wind ramps, increased regulating and load following duties on conventional generators, and increased fuel costs associated with maintenance of higher regulating reserves and dispatch of diesel units to arrest frequency excursions. In response to these impacts, HELCO system operations requested this study, which quantifies the technical impacts associated with the integration of existing wind levels into the system and identifies potential mitigating strategies. Approach: The project team conducted statistical analysis and large frequency deviation event analysis 819 hours of 4-second resolution AGC data collected over 36 days from June 5 – July 10, 2008. Results: Statistical analysis and large frequency deviation event analysis on HELCO historical operation data support the following conclusions: • Wind generation variability for the existing 33 MW of wind generation on the HELCO system degrades

frequency performance and increases AGC activity more significantly than load variability. • Large wind ramping events can result in large frequency deviation events. • The extent to which wind ramps negatively impact system performance depends on the availability of

regulating capacity and the time of day that the wind ramp occurs. • HELCO system operators are unable to predict wind behavior and accordingly struggle to know the optimal

mitigating action to arrest wind related frequency excursions and when to take that action. • Dealing with the additional variability of wind generation results in real cost implications for HELCO including

increased O&M on regulating units due to the additional duty and more frequent use of quick start diesels to respond to wind-related frequency events.

HELCO is already operating at penetration levels of 16-33%. The collected AGC performance data analyzed in this study show that HELCO system operators are struggling to manage the challenges that the 33 MW of wind generation can pose. In order to ensure system security/reliability with the existing wind plant, HELCO should evaluate the cost benefit of obtaining/developing the following operational tools required specifically for dealing with the wind generation challenges: • HELCO should continue to pursue advanced short-term wind generation forecasting. The most significant

benefit to HELCO’s system operation would likely be obtained through improved intra-hour and near-term forecasting of ramp events. HELCO is pursuing research in this area through a project that with a leading commercial forecasting firm.

• HELCO should investigate whether the increased cost of maintaining higher regulating up reserve margins during periods when wind plants are operating just at or above rated wind speed can be justified on the basis of the improved system security, even though the cost of additional reserves is very high relative to most power systems due to the particular mix of dispatchable generation on the HELCO system.

• Future wind power contracts in the island power systems should include additional wind power management and control provisions. HELCO should investigate whether existing wind plant operators can be persuaded to use modern turbine control systems more fully to provide MW smoothing, frequency regulation, and/or system inertia to the HELCO grid.

• HELCO should investigate if supplemental technologies, such as battery storage, can be used to smooth the additional second-to-second variability experienced on the HELCO system as a result of the need to increase the AGC no-control deadband.

Application, Value and Use: Although the recommendations proposed in this study may have economic, technical, or legal drawbacks, these mitigating measures should be considered to ensure system security and reliability for the HELCO system with its current and projected levels of wind generation penetration. EPRI Perspective: At high penetration levels, the additional variability and uncertainty associated with wind generation does impact AGC activity and frequency performance. Improved short-term forecasting, new technologies, better control systems/methods, and the ability to store energy are expected to aid system operators with wind integration problems in the future.



P39.001 1015990

Situation Awareness in Power System Operations: Guidelines and Recommendations for Supporting Situation Awareness

Technical Update Lee, Stephen 07-Nov-08

Abstract Recent emphases on situation awareness (SA) in the power industry have highlighted the lack of SA-related research in this domain. New paradigms are needed to guide research and systems design to improve operations by enhancing the SA of operators. This report describes research on three critical topics related to human factors (HF) and SA in the power systems industry: (1) the use of color, (2) the use of automation and its impact on situation awareness, and (3) predictive situation awareness. Objective The objective of this project was to investigate the state of situation awareness in the power systems industry by examining three key areas of human factors and SA in electric power transmission and distribution operations: (1) the use of color in the display of information, (2) the use of automation and its impact on situation awareness, and (3) the use of predictive tools to support the highest levels of situation awareness. A goal for the work was to identify design guidelines and provide recommendations for the three areas that will help to ameliorate effects of the breakdowns in SA that can be found in power systems operations. Approach This project features data collected from site visits with three control centers. Semi-structured interviews and observations guided by specific design criteria were used to collect data on the three critical HF/SA areas identified for the project. An online color survey was also conducted to supplement the site visit data collection. Results This project represents a detailed study of the use of color, automated systems, and predictive SA tools in the power industry. Data was provided from site visits with three control centers and an online color survey. A total of 27 survey responses from 25 separate EPRI member companies were collected and analyzed. Use of good HF/SA practices as well as gaps were identified for each topic area. Lists of guidelines and recommendations for improving each critical area were developed, with five (5), ten (10), and six (6) specific guidelines provided for the color usage, automation, and predictive SA topics, respectively. Application, Value and Use It is hoped that the guidelines and recommendations will be used by the power systems industry and software vendors to effect changes in the design of control room displays and advanced applications. EPRI Perspective EPRI has long conducted research in human factors and man-machine interfaces. With the advent of third-party software applications outside of the major energy management systems, a diversity of innovative visualization techniques has emerged, including different uses of color within graphical user interfaces. EPRI and its members believe that a review is needed to help promote more uniformity and application of sound human factors principles for enhancing operator situation awareness. The results of this project will be presented in a workshop on December 9, 2008 which is open to the utility industry and software vendors. It is hoped that the industry will move towards a user-centered software design philosophy and improve operator situation awareness.



P39.002 1015991 Best Practices in State Estimation Technical Update Min, Liang 01-Dec-08

Abstract Power system state estimation has become an essential application in today's energy control centers. The performance of a state estimator depends not only on the solution algorithm and its implementation but also on the existing measurement configuration of the given power system. The future evolution of state estimation, as envisioned in EPRI, will be most affected by new technologies, such as synchronized phasor measurements, as well as by the trend toward decentralization of system operation, monitoring, and control. This technical update covers the results of a survey of electric utilities and a follow-up workshop with survey participants. Survey responses were obtained from ten U.S. and Canadian utilities across a wide spectrum of state estimator users. Responders included transmission operators, balancing authorities, and reliability coordinators. These results will help to shape future planning by identifying the most effective pathways for the future evolution of power system state estimation. Objective Electric utility managers who are responsible for system operation and new technology integration are the intended audience for this report. This technical update is relevant to all types of transmission operators, balancing authorities, and reliability coordinators who use and implement state estimators. As increasing amounts of intermittent renewable generation sources provide power to the grid, as computer capabilities increase, and as the scope of system monitoring expands, state estimators need to improve to continue delivering optimal performance. The next-generation state estimators will be strongly affected by new technologies, such as synchronized phasor measurements, as well as by the trend toward the decentralization of system operation, monitoring, and control. The objective of this project was to identify and highlight the best practices in state estimation and also determine which aspects of state estimation could be further improved and/or revised to suit changing system requirements. Approach This project is based on a survey that contained questions on different aspects of state estimation function. The survey aimed to gather information about the utilization of state estimation function by energy management system (EMS) operators It also investigated the methods used by existing state estimators to carry out various modeling, analysis, and error processing tasks that facilitate successful execution of the state estimation solution. Results This survey provides data and information on the current best practices in state estimation. As summarized in the report, there has been significant progress made both in the solution algorithm and its implementation, making the state estimator one of the crucial applications in today's energy management systems. Several other applications make use of state estimator output in order to control and manage the system efficiently and reliably. The survey also identifies certain features that are either missing or can be further developed in order to optimize the performance of state estimators. Application, Value and Use There are extensive areas for future research on future state estimators. Broadly speaking, research should: • Help utility members to fully utilize existing or soon to be installed phasor measurement units (PMUs) for state

estimation • Enhance the state estimator's accuracy, robustness, and performance • Enhance the ability of system operators to observe and control the system • Forecast the onset of instability by using predictive state estimators

EPRI Perspective EPRI considered it necessary to review existing technologies and the prospects for next-generation state estimators and identify new capabilities that could facilitate power system operation both in terms of reliability and in enabling more efficient operation of power markets.



P39.003 1015993 Controlled System Separation: Key Issues, Industry Practices and State-of-the-Art Technologies

Technical Update Zhang, Pei 21-Nov-08

Abstract Power systems are increasingly stressed by the rapid growth of electricity markets and renewable sources. As a result, the risks of a disturbance causing out-of-step generators or triggering cascading failures in a power system are also increasing. In extreme situations, successive line trips may break the power network into two or more islands in an undesired manner. For those areas without or lacking of generation capacities to support local electricity demands, much load has to be dropped, thus resulting in blackouts. Controlled system separation (islanding) is an effective resort to mitigate cascading failures and out-of-step conditions. It actively isolates the outage area to save other areas or, according to out-of-step generator groups, splits the power system into designed islands with minimized generation/load imbalances. In this way, loss of load can be reduced to a minimum. This report summarizes the key issues that need to be addressed to implement controlled system separation in a large-scale power system, investigates current industry practices in North America, and introduces state-of-the-art technologies in relevant fields. Objective For a particular power system, the development of a controlled separation strategy is a complicated planning problem. Existing policies and non-technical concerns usually play important roles in designing the strategy. The four types of separation issues listed above need to be prioritized and interpreted according to system characteristics. This multiyear project aims at Documenting industry practices and R&D needs in the area of controlled system separation Introducing potential technologies and tools that can help system planners perform studies relevant to controlled system separation Suggesting feasible R&D directions to improve existing controlled separation strategies or develop more effective strategies, such as online, adaptive separation strategies. Increasing members' knowledge on mitigating cascading and out-of-step generators to prevent blackouts Approach The project team sent out a survey to collect information on industry practices and interests in controlled system separation. After receiving the feedback, the team documented industry practices. The team also summarized relevant state-of-the-art technologies and defined future research directions in controlled system separation. Results Controlled system separation can effectively stop the spread of cascading and control out-of-step generators to avoid large-area blackouts. To implement controlled system separation in a power grid, four major separation issues need to be addressed: Where to separate the grid? This issue involves the selection of separation points or island boundaries. When to separate the grid? This issue involves the determination of separation timing. How to separate the grid? This issue is about the design and coordination of separation devices. What to do next? This issue is about the frequency and voltage control in each island after separation. Application, Value and Use This report explains the importance of controlled system separation in mitigating cascading failures and out-of-step generators, and summarizes the key issues that need to be addressed to develop a separation strategy. Industry practices and the state-of-the-art technologies in this area are also documented, thus providing members with an overview of controlled system separation. EPRI Perspective A major R&D goal in transmission system protection is to avoid cascading failures by using improved special protection schemes. The existing "fixed" system separation in which separation points are pre-determined can be replaced by a more "intelligent" separation scheme in which separation points are determined based on real-time power system conditions. Wide area measurement systems (WAMS), now in development, can gather and process the information needed for controlled system separation. EPRI plans to develop a phasor measurement unit-based separation strategy that integrates appropriate and practical technologies to address key separation issues. Based on this separation strategy, utilities will be able to easily customize their own separation strategies to meet their specific requirements.



P39.003 1015994 Prototyping a Decision Support Tool for Evaluation of System Restoration Strategy Options


Abstract Power system restoration is well recognized as one of the most important tasks for electric power grids. Following a power outage, dispatchers in the control center work with the field crews to re-establish the generation and transmission systems and then to pick up load and restore service. It is reported that the impact of a blackout increases with the duration of its restoration. Blackout events and aging transmission infrastructures in North America require that greater attention be paid to R&D in system restoration and its associated decision support tools. The purpose of this research is to address the general strategies and online decision support tools for system restoration. A specific restoration plan can be established by a combination of these general strategies based on the system conditions. Objective Needless to say, system reliability depends heavily on the efficiency of system restoration. Unfortunately, few decision support tools are available to dispatchers and restoration planners today. Restoration plans are developed with basic simulation tools for power flow, dynamics, and electromagnetic transients. These plans developed off line are then used as guidelines for dispatchers in an on-line environment. Dispatchers need to adapt to the actual outage scenario and available resources and be able to develop the strategy based on their experience. On the other hand, restoration strategies are closely related to the specific system characteristics. Since one system's situation does not conform readily to the situations of other systems, the restoration strategies cannot be generalized easily. The purpose of this project is to prototype a decision support tool for evaluation of system restoration strategies. Approach In this project, the best practices of the industry are acquired and documented. Then, the necessary computational concepts and tools for evaluation of system restoration strategy options are developed. Results Industry practice and documentations of system restoration plans were studied in this project. A new concept, generic restoration milestone (GRM) during system restoration, has been proposed. Based on that, a prototype decision support tool for evaluation of system restoration strategy options was developed. A specific restoration strategy can be established by a combination of GRMs based on the system characteristics, energy sources and constraints of power grids, and then be examined by simulations. Different combinations or sequences lead to different strategy options and performances. Simulation studies have shown that the developed decision support tool enables a power system at the blackout status to restart and self-organize various parts until a complete restoration. The following results are documented in this report: • Investigated system restoration options and procedures form industry • Summarized the common issues on power system restoration • Summarized general philosophies of restoration • Developed the concept of generic restoration milestone (GRM) that can be used to establish the specific

system restoration strategy • Developed system restoration strategies based on GRMs • Developed a graph theoretic algorithm to finding the shortest path for cranking non-blackstart units or to pick

up loads • Developed a power flow analysis algorithm with frequency response of generators and loads during restoration

process Application, Value and Use EPRI prototyped a decision support tool based on a new concept, generic restoration milestone (GRM), for large interconnected power grids. A set of flexible generic restoration milestones and the associated algorithms that are able to evaluate different restoration strategy options are used to reconstruct system restoration strategies adopted in industry. The proposed decision support tool will be an operational aid during system restoration. EPRI Perspective: It is important to develop a decision support tool to assist system planners in system restoration planning and, ultimately, assist system operators in an on-line restoration environment. This research developed a new methodology and prototyped a decision support tool for evaluation of system restoration strategies. It is believed that the proposed methodology represents a major step toward modernization of power system restoration that is largely manual at present.



P39.004 1015995

Identification of Critical Voltage Control Areas and Determination of Required Reactive Power Reserves

Technical Update Edris, Abdel-Aty 09-Dec-08

Abstract The objective of this research project is to investigate and devise a methodology for identifying areas in power systems that are prone to voltage instability under particular operating conditions and contingencies. These areas, which are prone to instability due to their lack of reactive power reserves, are referred to as critical voltage control areas (VCAs). Once VCAs are identified, methods of determining their adequate reactive power reserve requirements to ensure secure system operation under all conditions should be established. The possibility of extending VCA identification for use in the on-line near-real-time environment is being sought. Since speed of analysis is critical for on-line applications, development of a scheme where VCAs can be identified using intelligent techniques such as decision tree (DT) techniques from on-line system snapshot needs to be investigated. The possibility of predicting the required reactive power reserve using regression trees (RT) constructed (off-line) for each of the identified VCAs using key system attributes also requires investigation. DTs and RTs have the added benefit of identifying the most important parameters associated with a specified outcome (such as instability). Objective Assessing VCAs is a complex task involving many challenges. The first major challenge is that power system behaviors associated with voltage instability are highly nonlinear. When stressing a system to find voltage stability limits, the nonlinear effects of devices such as loads and discrete actions of devices such as tap-changers and generator limiters can have a profound effect on the limits. Techniques used to determine voltage stability limits must be able to account for these nonlinearities, and, therefore, highly simplified or linearized approaches will be unacceptable. The second challenge is that the problem is very complex; large power system models are involved, and many system conditions and contingencies must be examined. This implies that the solution techniques developed to assess VCAs must be efficient and highly automated. Approach The approach is based on a PV curve method combined with modal analysis. The general approach is as follows:

a) Define a system operating space based on a wide range of system load conditions, dispatch conditions, and defined transactions (source-to-sink transfers).

b) Define a large set of contingencies that spans the range of credible contingencies. c) Using the PV curve method, push the system through every condition and under all contingencies until the

voltage instability point is found for each condition. d) At the point of instability for each case (nose of the PV curve), perform modal analysis to determine the critical

mode of voltage instability as defined by a set of bus participation factors corresponding to the zero eigenvalue. e) Store the results of the modal analysis in a database for analysis using data mining techniques to identify the

VCAs and track them throughout the range of system changes. f) Establish the reactive reserve requirements for each identified VCA. g) Using decision/regression tree techniques to develop a framework for off-line and on-line VCA identification.

Results A highly automated method has been developed for identifying areas prone to voltage instability in practical power system models. For a wide range of system conditions and contingencies, the technique can identify the buses in each VCA and identify VCAs that are common for a set of contingencies and/or conditions. In addition, the method identifies generators that are critical to maintaining voltage stability for a given VCA. The methods developed have been incorporated into a custom software tool that has been tested on large practical systems with good results. Application, Value and Use The methods and software developed in this project can be used by power system planners and operational planners to 1) evaluate the performance of various power system designs or configurations with regards to susceptibility to voltage instability, 2) determine weak areas requiring special remediation, and 3) assist in maximizing the efficient use of assets by determining the minimum amount and optimal location of required reactive reserves. EPRI Perspective Assessing and mitigating problems associated with voltage security remains a critical concern for many power system planners and operators. It is well understood that voltage security, and particularly voltage stability, is driven by adequate levels of reactive power support. Therefore, it is of particular interest to identify those areas in the system that may suffer reactive power deficiencies under various system operation and contingency conditions. Establishing reactive power reserve requirements in these areas to ensure system integrity is important.



P40.001 1015997 PCF v1.0 Probabilistic Transmission Congestion and Constraints Forecast, Version 1.0

Software Min, Liang 12-Dec-08

Abstract The Probabilistic Transmission Congestion and Constraints Forecast (PCF) Version 1.0 program provides the user the capability to compute the probabilistic distribution functions of line flows with consideration of generation, load and network uncertainties. Description PCF Version 1.0 models the generation and load in a probabilistic way, and computes the probabilistic distribution functions of line flows. The program can handle generation and load uncertainties in a probabilistic model. It can handle transmission network in both deterministic and probabilistic ways. The PCF program also can display the overload information on the map of transmission network. It allows users to perform economic dispatch and user-defined dispatch during Monte Carlo simulation. Platform Requirements Windows™ 2000, XP, Vista Application, Value and Use PCF Version 1.0: Provides more confidence in making judgments concerning alternative investments in transmission systems. Enables greater utilization of current generation resources and increases potential for greater efficiencies. Provides predictable and foreseeable bounded results instead of a "zero to perfect" one-time exercise.


Program Product Id Product Description Product Type Manage Date

P40.002 1015998 Grid Shunt Reactive Power Compensation Technical Update Becker,

David 31-Dec-07

Abstract This report provides essential information on transmission grid shunt reactive power compensation, with particular focus on controllable reactive power sources such as the static var controller (SVC). Applying the information presented in this report can help electric utilities planning grid shunt reactive power compensation strategies or operating shunt reactive power compensation equipment to increase grid reliability, improve grid performance and prevent costly cascading outages. The report is intended for use by practicing transmission engineers, as well as a guide for engineers in training and students pursuing a career in transmission engineering. Objective Supplying the large reactive power demands of a heavily loaded transmission grid and the sudden increases that accompany contingencies is a growing challenge. A critical element in meeting that challenge is choosing reactive power sources that will reliably meet the demands of a heavily loaded transmission grid. Approach This report summarizes the problem of reactive power supply in the electric power industry and the current and emerging equipment technology available to ensure that reactive problems do not excessively degrade reliability. The information in the report is based largely on the author's experience and his book, Reactive Power for Planning and Operation, as well as the book, Understanding FACTS; Concepts and Technology of Flexible AC Transmission Systems, by Narian Hingorani and Laslo Gyugyi. Results The report covers reactive power basics, the intricacies of reactive power compensation, transmission system stability challenges, controllable reactive power source components, combinations of fixed and controllable reactive power sources, planning and design requirements, grid applications, industrial applications, and windpower applications. Application, Value and Use Information in this report can help transmission engineers at electric utilities and consulting firms to plan, select, and operate reactive power sources to manage the huge reactive power demand of today's heavily loaded grid. By applying the knowledge captured in this report, engineers can improve the performance and reliability of transmission grids and reduce the risk of extremely costly cascading outages. EPRI Perspective EPRI has helped pioneer the development and application of power electronics-based transmission controllers. This technology owes much of its development to EPRI's Flexible AC Transmission System (FACTS) program which was cosponsored by WAPA, BPA, TVA. AEP, and NYPA. The FACTS initiative was launched in the late 1970s to solve emerging problems due to restrictions on transmission construction and to facilitate the increasing number of power transactions. The report is part of an extensive and growing body of technical information for the selection, specification, and application of power electronics-based controllers for improving the operation and security of transmission systems.



Type Manager Date

P40.002 1015999 Comprehensive Load Modeling for System Planning Studies

Technical Report

Brooks, Daniel 31-Mar-09

Abstract This report, about load modeling for time-domain dynamic simulations for power system planning studies, provides a brief review of previous work and background, as well as two recent efforts by the Electric Power Research Institute (EPRI) and an ongoing major effort by the Western Electricity Coordinating Council (WECC). The report concludes by presenting a step-by-step approach to current best practice for comprehensive load modeling. Objective The key challenge of load modeling is the complexity of the problem. The load composition in a power system is under constant flux, changing with time (hourly, diurnally, and seasonally) and over different geographic regions. To address this challenge, both measurement-based and component-based approaches to load modeling have been pursued, with an initial attempt to systematize sensitivity analysis to address the constant uncertainty in the actual load composition at any given time. Approach The approach taken was to bring together the results of previous work by EPRI on both measurement-based and component-based load modeling. In addition, further component-based testing was performed in the laboratory to increase the pool of knowledge related to modern loads (for example, high-definition televisions) as well as extensive sensitivity studies to identify the impact of various load model parameter variations on bulk system dynamic performance. Results This report presents valuable information related to both measurement-based and component-based load modeling. It also presents a clear step-by-step current best-practice approach to comprehensive load modeling for planning studies. Detailed data on laboratory tests of key load components—such as air conditioners, compact fluorescent lighting, and high-definition televisions —are presented. Results on many measurement-based load model parameter derivation attempts and what was learned from these exercises are also presented. Application, Value and Use The materials presented in this report are for power system planners to guide them in preparing comprehensive models of load for time-domain stability studies. EPRI Perspective EPRI has been performing research on load modeling since the 1980s, with projects such as the LOADSYN project. This report is part of an ongoing effort by EPRI to investigate not only state of the art in load model, but also to keep such efforts focused on meeting the needs of the industry while keeping the approach as simple, practical, and effective as possible.



Type Manager Date

P40.004 1016000 Automated Model Validation for Power Plants Using On-Line Disturbance Monitoring

Technical Report

Pourbeik, Pouyan 31-Mar-09

Abstract: The report documents the results of the Electric Power Research Institute (EPRI) base-funded research work conducted under Program 40.004, Generator Dynamic Model Parameters Identification and Validation, and Program 65, Steam Turbine Frequency Response Modeling and Validation Using Ambient Monitoring. Because of their synergies, these two projects were conducted in parallel, and this single report presents the results of both projects. Background: Generator model validation and testing is certainly not a new subject. Efforts have been ongoing in this area for many decades. In 1997, the Western Electricity Coordinating Council (WECC) started a major effort, in the aftermath of the 1996 system breakups, to improve system planning models. One aspect of this was the mandated testing of generating units. The North American Electric Reliability Council (NERC) is working to bring similar mandates to bear nationwide. In 2007, EPRI's Power Delivery & Utilization (PDU) sector performed a supplemental research project (cosponsored by FE, Duke Energy, and TVA) to develop a prototype software tool for power plant parameter derivation using field-recorded data for staged testing of generating units. This tool caused a significant reduction in the engineering time needed for model parameter derivation and validation. The subject report, Power Plant Modeling and Parameter Derivation for Power System Studies: Present Practice and Recommended Approach for Future Procedures (1015241), provides the background for such staged testing procedures. The report Automated Parameter Derivation for Power Plant Equipment for Use in Power System Studies (1016251) provides a detailed account of the prototype software and demonstrates its use for several staged tests performed on various synchronous generator power plants. The goal of the 2008 Program 40.004 base-funded research work in PDU was to further extend this prototype software to illustrate whether data collected by on-line disturbance monitoring equipment in a power plant (such as a digital fault recorder [DFR]) could be used for model validation rather than staged testing. The benefit of such a methodology is that it enables the routine revalidation of models without the need to bring the unit off-line to perform staged tests. This allows for compliance with the imminent NERC standards with significantly reduced risk to the units and less cost. The goal of the 2008 Program 65 project was to look specifically at developing such disturbance monitoring–based methods for model validation of the primary frequency response of large steam turbine generators. Because of their synergy, these two projects were performed in unison. Objective: The main challenge with this type of model validation is that it typically has been achieved through staged testing of the generating facility. This requires bringing the unit off-line, connecting appropriate recording devices to it, and performing a series of staged maneuvering actions of the unit off-line and at low loads on-line. This incurs expense both in the engineering time and effort required for the task and in the potential loss of opportunity to sell power while the unit is under test. Furthermore, though quite low, there is always a risk of damage to the unit. This project investigated and identified methods of model validation using data captured by event recorders (such as DFRs) in the power plant during systemwide disturbances. These data are then used to validate and fine-tune the power plant model. The benefits are that there is no need to schedule time for testing the unit, the unit need not be maneuvered or taken off-line, and there is no additional risk of damage to the unit. Another key benefit is that the unit's response to actual events is seen. However, for this process to work, good baseline data on the applicable models for the power plant are required—so some form of staged testing or model validation upon plant commissioning is still needed. These topics are all discussed in detail in this report. Approach: A tool was developed using the MATLAB® environment, and a simple graphic user interface (GUI) was built on top for ease of use. This tool was then used to post-process digitally recorded disturbance data from three volunteer plants to demonstrate and verify the approach. Results: The results are encouraging: the tools are able to effectively validate power plant models using on-line disturbance data. As expected, however, some expertise on the part of the engineer using the tool is needed to ensure that the proper model structure is chosen for each case and that reasonable initial estimates of the parameters and upper and lower bounds on the parameters are chosen. Furthermore, a good baseline model is of vital importance for the process. Such baseline models may be in the form of detailed manufacturer-supplied models and model verification upon commissioning the plant or models derived during a staged test. The imminent NERC standards (and existing WECC standards) for revalidating power plant models every five or more years can be easily met through such a disturbance monitoring–based methodology. For one of the volunteer units, five system events were captured during a seven-month period. EPRI Perspective: EPRI's involvement in synchronous machine parameter testing goes back to the 1980s and 1990s with standstill frequency response–based parameter estimation techniques and the PIDAS project. This report is part of an ongoing EPRI effort to investigate not only state-of-the-art power plant model parameter derivation, but also to keep such efforts focused on meeting the industry needs as dictated by reliability standards while keeping the approach to such work as simple, practical, and effective as possible.



P127 1018186 Summary of Recommendations from NERC Reliability Readiness Evaluations

Technical Update Lee, Stephen Ting-Yee 20-Oct-08

Abstract: The North American Electric Reliability Corporation (NERC) has recently conducted a large number of reliability readiness evaluations at the sites of various transmission operators, balancing authorities, and reliability coordinators. This report summarizes the most prevalent recommendations in these evaluations, enabling entities not yet audited to better prepare by initiating improvements in emphasized recommendation areas. Background: NERC established its Reliability Readiness Evaluation and Improvement Program to support the reliable operation of the bulk power system in North America. In this program, NERC independently reviews the operations of transmission operators (TOPs), balancing authorities (BAs), reliability coordinators (RCs), and other entities. The goal of the evaluations is to determine the "readiness" of these entities to maintain safe and reliable operations. These reviews are separate from NERC compliance audits. The results of the evaluations are identified in reliability readiness reports—one per entity reviewed. These reports document positive observations and recommendations for improvement. In addition, NERC documents exemplary practices in the form of case studies it calls "Examples of Excellence." These case studies describe best practices for addressing areas that NERC identifies as needing improvement in its reliability readiness reports. Objective: To help EPRI members prepare for NERC reliability readiness evaluations by gaining increased awareness of the issues and recommendations that NERC has identified in its completed evaluations. Approach: The project team primarily focused on reliability readiness evaluations conducted in 2006 (67 evaluations) and 2007 (40 evaluations). The team used the most recent organization of recommendation subject areas that NERC adopted in March 2007 as the basis for data tallying and analysis. This organization is more useful than the organization NERC used previously. The team compiled data in two ways: 1) total number of line-item recommendations in each subject area (for example, 90 recommendations on training in 2007), and 2) percent of evaluations that included at least one recommendation in each subject area (for example, 88% of 2007 evaluations had at least one recommendation for training). The team tabulated recommendations for all of 2007, all of 2006, Western Electricity Coordinating Council (WECC) entities only, non-WECC entities only, BA/TOPs only, TOPs only, and RC/BA/TOPs only. The team then described the top recommendation areas revealed in these analyses, for comparison alongside relevant NERC Examples of Excellence. For each of the top recommendation areas, the team listed the applicable NERC Reliability Standards, and briefly discussed any overlap between the recommendation area and relevant most reported alleged violations of the NERC standards. Results: The top five subject areas of recommendations in the 2006/2007 NERC reliability readiness evaluations include training, emergency preparedness, operational alignment (documentation), critical infrastructure protection, and operations. The most prevalent subject area for recommendations in the NERC reliability readiness reports is the need for operator training, including training planning and budgeting; training staffing; training scheduling, tracking, and records management; training process evaluation; and training process improvement. Operational alignment recommendations indicate the significant need for improved, updated documentation of operating policies and procedures, documentation management systems, and documentation of authority. Emergency preparedness recommendations include black start and system restoration, emergency plans, backup control center, and load shedding. Operations recommendations primarily cover transmission operations, resource and demand balancing, and voltage and reactive areas. The top five recommended subject areas remained largely unchanged across WECC/non-WECC and entity type. This indicates that the primary areas in which improvement is needed involve industrywide concerns. Subject areas not in the top five include operational planning, operational decision-making, human resources, maintenance, corporate oversight, leadership and management, and corporate communications. While some areas highlighted in the NERC reliability readiness reports are also on NERC's list of most reported alleged violations of the reliability standards, these two lists show some differences. Recommendations regarding critical infrastructure issues were redacted from the reports for security reasons. In NERC's 2007 list of most reported alleged violations of reliability standards, "sabotage reporting" (COP-001) was number one on the list, with 407 alleged violations. EPRI Perspective: Entities that NERC has not yet audited as part of the Reliability Readiness Evaluation and Improvement Program can improve the outcome of their audits, regardless of their Interconnection or entity type, by • Focusing on improving aspects of control center operation that NERC emphasized most often in its audits in the

last two years (for example, operator training, documentation management systems, emergency preparedness, critical infrastructure, and transmission operations)

• Considering improvements to aspects of control center operation related to areas listed in NERC's most reported alleged violations during 2007

• Examining the Examples of Excellence on the NERC Web site to identify NERC recommended best practices in various subject areas



P127 1018402 2008 CIM-XML Interoperability Including CIM-Based Tools Test Technical Report Becker, David 04-Dec-08

Abstract: EPRI Initiatives have produced a number of drafts that have now become International Electrotechnical Commission (IEC) standards, including the Common Information Model (CIM) and the Generic Interface Definition (GID) specifications. These standards provide the basis for model-driven information exchange both within and between control centers and other systems in utility operations across the enterprise. Previous interoperability tests validated the use and acceptance of the CIM standard translated into CIM/XML (eXtensible Markup Language) and transfer of data via the standard interfaces. This report describes the 2008 set of interoperability tests to demonstrate the exchange of complete and incremental power system models and prove the validity of the updated CIM standards as provided by the IEC working groups. This particular test validated CIM draft release 13 version 12. The testing focused on demonstrating that participating vendors were able to successfully exchange power system network models using the standards, as defined in the latest drafts of IEC specifications 61970-452 and 61970-552. In addition, the tests focused on implementing the latest IEC standard contents, the equivalent classes, and the Modeling Authority Sets (MAS) as a method to introduce changes at a regional level. This approach allows the exchange of massive changes than would not be reasonable to expect in an incremental file. That is, the approach fully replaces a region with a regional CIM/XML file that contains many changes for that region. In addition, this test, for the first time, tested a set of CIM tools that may be used to validate the exchange documents to the standards. Tests results are in the report’s Test Tools section. Newer Version of 1017804 Objective: This report will benefit utility professionals who are preparing to implement products from multiple vendors who need to exchange or use information from different applications. The data in this report provide an overview of the functionality that can be purchased from the various vendors. It also explains issues surrounding use and implementation of the standards and the level to which these standards have been implemented by the vendors. The primary future challenge is to extend the standard beyond the control center and prove that the standard is stable and can be fully implemented. Results: To start the test, participants submitted test model files in CIM/XML format. Two validation tools (CIMTool and CIMSpy) were used to validate the correct formation of these models according to the standard. Each participant then attempted to import and re-export these models in conformance with the full and incremental standards. Following the import stage, participants demonstrated to observers, using their own internal modeling and/or power flow applications, that the imported models indeed matched the submitted CIM/XML models. Each participant who supported an import and export capability was able to successfully import at least one power system model correctly and interoperate successfully by exchanging at least one sample model file between them. Areva T&D, GE Energy, Siemens PTI, Siemens EA, and SNC Lavalin T&D were able to successfully run a power flow solution on an imported transmission model file and then export the file, providing further validation of the content and correct translation between proprietary formats and CIM. Areva T&D, GE Energy, Siemens PTI, Siemens EA, SISCO, SNC Lavalin T&D, and UISOL successfully imported multiple incremental model update files and merged them into an existing base model. Areva T&D, GE Energy, Siemens EA, and SNC Lavalin T&D also produced several incremental files for use by other participants. In the newest tests, all vendors were able to import Inter-Control Center Communications (ICCP) transfer data and the equivalent classes, and Areva T&D, GE Energy, SISCO, Siemens EA and SNC Lavalin T&D were able to process a set of Modeling Authority Set files. Areva T&D and SNC Lavaliln T&D were able to produce a set of Modeling Authority Set files to be used by other participants. Application, Value and Use: Once the standard is extended, it will allow full data management and data exchange between the transmission, distribution, planning, and generation areas of the enterprise. Especially urgent at the present time is to move the standard into the newest areas of SmartGrid, Advanced Metering Infrastructure (AMI), and Home Area Network (HAN). Once these areas are standardized and can tap into the new data provided by these systems, utilities will be able to maximize their return on investment and achieve efficiencies that will lower the cost of future system upgrades and integration. EPRI Perspective: The changing business environment has increased the need for greater business and operating flexibility in the energy industry. In recent years, EPRI and other industry entities have encouraged several individuals and companies to address the need for validation tools. As a result, there have been several tools developed that may be used by the industry to validate compliance with the standards and provide testing artifacts to enable interoperability testing. Other than these tests, the industry has no officially witnessed testing activity to determine compliance with the standards and interoperability between vendors. Integration architectures based on the CIM model, GID interfaces, and standard XML messages enable interdepartmental teams to access a range of needed information via open systems. Hence, energy companies are planning to implement CIM/GID/XML outside the control center to reduce costs and improve customer service and staff productivity. EPRI continues to sponsor collaborative efforts to advance these integration strategies for greater information systems integration solutions—in the control center and beyond.



P127 1018440 The 2008 Transmission Planning Interoperability Test Technical Report Becker, David 27-Feb-09

Abstract EPRI Initiatives have produced a number of drafts that have now become International Electrotechnical Commission (IEC) interface standards—including the Common Information Model (CIM) and the Generic Interface Definition (GID) specifications—which provide the basis for model-driven information exchange both within and between control centers and other systems in utility operations across an enterprise. Previous interoperability tests validated the use and acceptance of the CIM Standard translated into CIM/Extensible Markup Language (XML) and transfer of data via the standard interfaces. This report describes the 2008 set of interoperability tests to demonstrate the exchange of complete models and prove the validity of the proposed CIM Standard, as provided by the IEC working groups. This particular test validated CIM draft release 12 version 02. The testing focused on demonstrating that the vendors were able to successfully exchange power system planning models using the CIM/XML Standard, as defined in the latest draft of IEC Specification 61970-552, Energy Management System Application Program Interface. Objective This report is of interest to any utility professional preparing to implement products from multiple vendors that need to exchange or use information from different applications. The data contained in this report provides an overview of the functionality that can be obtained from the various vendors. It also explains the issues surrounding vendor use and implementation of the IEC interface standards. The goal of this report is to encourage adoption of the CIM model by additional product suppliers and energy managers. Approach The goals of the interoperability test were to show that the participants could exchange models using the IEC interface standards. The project team prepared a formal set of test procedures to test the ability of the participant’s products to conform to the IEC 61970 (CIM/XML) Standard. Following a period of preparation and preliminary testing, two participants (GE Energy and Seimens PTI) gathered in New York City to have impartial observers witness product demonstrations of the specified tests. Areva T&D provided a model to be used by the participants in the base import and export tests. Results To start the test, participants submitted test models (that is, files in CIM/XML format). CIMSpy, a CIM-based validation tool, was used to validate the correct formation of the model files according to the standard. Each participant then attempted to import and re-export these models in conformance with the full model standard. Following the import stage, participants would demonstrate to observers, using their own internal modeling and/or power flow applications, that the imported models indeed matched the submitted CIM/XML models. Both GE Energy and Siemens Power Technologies International (Siemens PTI) were able to successfully import and export all power system models correctly. Additionally, power flow solutions were performed successfully on the imported model files, providing further validation of the content and correct translation between proprietary formats and the CIM. Application, Value and Use The primary challenge in the future is to extend the CIM Standard beyond the control center and prove that the standard is stable and fully implementable. Once the CIM Standard is extended, it will allow full data management and exchange between the transmission, distribution, planning, and generation areas of the enterprise. When this new data provided by these systems can be accessed, utilities will be able to maximize the return on investment and achieve efficiencies that will lower the cost of future system upgrades and integration. EPRI Perspective The changing energy environment has increased the need for greater business and operating flexibility in the energy industry. Recently, the CIM Standard has come to include distribution, short circuit and dynamic planning models, and new technologies. IEC compliance and vendor interoperability offers operations center managers the flexibility to combine, on one or more integrated platforms, the software that best meets their energy company’s needs for system economy and reliability. This compatibility allows managers to upgrade or migrate their systems incrementally, thus preserving prior utility investments in custom software and enabling the use of new applications as they become available. Migration can reduce upgrade costs by 40 percent or more. Integration architectures based on the CIM Standard enable interdepartmental teams to access a range of needed information via open systems. Hence, in innovative applications, energy companies are planning to implement the CIM/GID/XML Standard outside the control center to reduce costs and improve customer service and staff productivity. EPRI continues to sponsor collaborative efforts and several initiatives to advance integration strategies for greater information systems integration solutions—in the control center and beyond.



P127 1018587 Vision for a Holistic Power Supply and Delivery Chain Technical Update Lee, Stephen 06-Feb-09

Abstract The dramatic changes that are likely to occur in the electric power industry in the next 10 years are inextricably linked to the activities of power system operators and planners. This report describes the necessary enhancements to the power delivery infrastructure as well as the tools and methods personnel will need to improve economic efficiency, assure adequate reliability and acceptable environmental impacts, increase system robustness and flexibility to mitigate extreme events, protect and leverage the valuable power delivery asset base, and optimize financial benefits for all stakeholders. Background Changes are occurring across the entire power supply and delivery chain. In the power generation portion of the chain, fuel price and availability is less certain. At the same time, stochastic (variable) power generation is growing at a rapid rate (e.g., wind farms and central station solar). Large-scale electric energy storage plants (e.g., compressed air energy storage plants) will soon be installed to complement such stochastic generation. Electric power users are increasing installing distributed generation and storage devices. These are expected to continue to increase, while plug-in hybrid electric vehicles proliferate, and energy efficiency and demand response continues to grow. All of these challenges place greater burdens on power system operators and planners. The power system of 20 years or even 10 years from now is likely to look quite different than today’s power system. And every function that power system operators and planners perform will be impacted by these changes. For this reason, the broad array of anticipated changes across the power delivery and supply chain directly affect grid operations and planning. Objective To describe a vision for a holistic power supply and delivery chain and to identify the most pressing and critical research needs within the advanced grid operation and planning domain that are the foundations of this vision. Approach The project team conducted a review of industry literature to identify challenges that affect power system operation and planning, as well as potential solutions and identified research needs. The team then synthesized this information into a preliminary report. Representatives of utilities, EPRI, and other stakeholders reviewed the concepts in this report and provided input and suggestions for additions and clarifications at a workshop held in Charlotte, NC on October 15, 2008. The project team then revised the preliminary report to reflect these additional ideas and produced this report for publication. Results One way to visualize a solution to the broad array of anticipated challenges in the industry is to envision an end-to-end system of power system monitoring, modeling, analysis, coordination, and control. This solution extends the supply and delivery chain beyond the power system to include the fuel supply portion of the chain due to the impact of fuel price and availability on power grid operation and planning. In this whole system, data gathered through various means across the power delivery chain supports data monitoring and local analysis at substations, for example, as well as development of dynamic models of both generators and loads. Improved alarm management at both transmission owner and regional transmission grid operator (e.g., independent system operator (ISO), regional transmission operator (RTO)) control centers process data received from across the power system. At regional control centers, this data and other information support enhanced wide area coordination, dispatch, control, and when necessary, restoration. Planners use improved power system planning methods and dynamic generator and load models, while complementing the efforts of power system operators. Significant improvements are needed in all of these areas to realize this vision. EPRI Perspective The electric power industry faces a range of critical challenges, including global climate change and an aging power delivery infrastructure that is straining to meet existing demands, let alone the future demands of large amounts of stochastic renewable generation, distributed generation, electric energy storage, plug-in hybrid electric vehicles, and demand response. Two of the four technology pathways that EPRI has established to address these challenges – distribution-enabled and grid-enabled pathways – directly impact, or are driven by, power system operation and planning. Hence, grid operations and planning serves as a capstone to these technology pathways. The effort in this report to summarize potential solutions and research needs in the grid operations and planning area is central to realizing these critical technology pathways.



P127.001 1016038 A Vision of Self-Healing Protection and Control Technical Update Zhang, Pei 23-Dec-08

Abstract A major blackout can cost an affected region in excess of billion dollars due to direct costs and social and economic impacts. Reducing the likelihood of a major cascading outage by even a fraction would mean savings in excess of millions of dollars each year. This report will discuss how to reduce the vulnerability of a transmission grid to cascading outages through application of a self-healing protection and control system. A case study is also included in the report to demonstrate the new framework. Objective The past several decades witnessed many new challenges in power system protection and control. In the past, many protection and control parameters were developed based on offline simulations with some periodical adjustment, such as seasonable modifications, to accommodate system condition variations. However, this offline simulation mode may not work well in real-time in the present power systems. In particular, two power industry trends resulted in the challenges to today's protection and control system. First, deregulation has broken the institutional boundary and caused different flow patterns, leading to more complex operating conditions that have never before been studied and are difficult to predict. Second, the aging infrastructure reduces component reliability and increases the likelihood of outages. The existing protection and control systems—with fixed settings determined based on offline studies—may not be able to provide the desired control performance to handle a variety of contingencies and operating conditions. The objective of this project is to develop a self-healing protection and control system, such that the system is always ready to respond quickly to any possible contingencies or system condition variations. Approach This report first reviews the present technologies of power system protection and control. Potential problems are illustrated using two case analyses. Next, a vision of the future self-healing protection and control scheme is proposed. A case study of Zone 3 protection in the Western Electricity Coordinating Council (WECC) system with three scenarios demonstrates that the present online security assessment based on steady-state analysis is not sufficient to correctly identify problems in the stressed system. In addition, the case study shows that the existing protection and control system with fixed settings is not adequate to handle the increasingly complex operating conditions, which may lead to systemwide cascading failures. Results As shown by historical data and recent experiences, occurrences of major outages are likely due to some unknown factors relating to cascading failures of large complex networks. The proposed self-healing protection and control framework performs dynamic security assessment in real-time. The dynamic security assessment, in turn, produces the coordinated optimal control strategies for each contingency. The control strategies are then sent to the remote protective relays and control systems. Once a contingency occurs, the remote protection and control systems will take actions according to the coordinated optimal control strategies developed through online dynamic security assessment. This framework completes the closed-loop control scheme. Application, Value and Use Implementation of the proposed self-healing protection and control framework can improve overall control on large-scale interconnected transmission systems, reducing the likelihood of cascading failures and thus increasing system reliability. The existing computing and communication infrastructures need to be improved and a variety of technical issues must be resolved through further R&D work before implementing the self-healing protection and control framework. EPRI Perspective EPRI has developed a vision of a self-healing protection and control framework to improve control system coordination and effectiveness. This latest development in communication, control, and computing systems has attracted increasing interest from the power engineering community to explore possible solutions for building more robust power systems.


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