Five Year Synchrophasor Plan NOVEMBER 2011

Five Year Synchrophasor Plan NOVEMBER 2011 SynchrophasorReport2011.indd 1 12/22/2011 11:07:36 AM

Table of Contents 1.0 Overview...2 2.0 Background...3 3.0 Key Activities...5 3.1 Infrastructure...5 3.1.1 ISO Production Hardware...5 3.1.2 Utility PMU placement...6 3.2 Data quality and management...6 3.2.1 PMU data quality...6 3.2.2 Data retention / storage policy... 6 3.3 Application functionality...7 3.3.1 Small Signal Analysis (SSA)... 7 3.3.2 Dynamic model validation...7 3.3.3 Voltage Sensitivity Analysis (VSA)...9 3.3.4 Phase Angle Difference Dynamic Limits (PADDL)...9 3.3.5 Event playback...10 3.3.6 Automatic event analyzer...10 3.3.7 State Estimator...10 3.3.8 Nomogram validation...11 3.4 Visualization...12 3.5 Operating procedures and training...13 4.0 Timeline...14 5.0 Summary...15 6.0 Glossary...16 Copyright California ISO Five Year Synchrophasor Plan November 2011 1

1.0 Overview The ability to monitor grid conditions and receive automated alerts in real-time is essential for ensuring reliability. Synchrophasor technology improves this capability for the ISO. System-wide and synchronized phasor measurement units take sub-second readings that through visualization and advanced applications provide an accurate picture of grid conditions. This document describes a high-level synchrophasor technology plan for using and advancing visualization tools and applications over the next five years. The overriding near-term goal for synchrophasor technology is achieving wide-area situational awareness that is trusted by the operators, coordinated with neighboring control areas, and can be acted on using well understood procedures to avoid system instability and undesired system outages. The ISO is actively pursuing a number of applications and functionality that leverage the synchrophasor data that support consolidated visualization by providing wide area situational awareness and alarming capabilities. Network model improvements and analytic applications that further create a more accurate system picture are also included in the roadmap vision. This roadmap is expected to evolve. Direct feedback from ISO operations, collaboration with the California IOUs and neighboring balancing authorities and participation in the Western Interconnection synchrophasor project will influence and enable the realization of this roadmap. The roadmap starts with fortifying and expanding the system infrastructure by installing phasor measurement units and establishing the architecture and communications framework for data exchange and storage and will require participation from other stakeholders including the utilities. The ISO does not directly own, operate or maintain the measurement units and is dependent on the utilities and neighboring balancing authorities for synchrophasor data availability and quality. 2 Five Year Synchrophasor Plan November 2011 Copyright California ISO

2.0 Background Deployment of synchrophasor technology is accelerating under recent U.S. Department of Energy initiatives. Most relevant to the ISO is the Western Electricity Coordinating Council s Western Interconnection Synchrophasor Project (WISP), which will increase the now deployed phasor measurement units (PMU) fivefold to over 300. The project will also develop common software suites that improve situation awareness, system-wide modeling, performance analysis and wide-area monitoring and controls. One challenge related to using synchrophasor technology is the communications infrastructure, which lacks the bandwidth to handle the data traffic produced by the smart devices, needs enhanced security and it must maintain a high degree of reliability if the data is used for control decisions. Another major challenge is the lack of available applications that assimilate and provide meaningful, understandable visual displays of the extensive data produced by the smart devices. Phasor measurement units provide voltage and electric current measurements. This data can be used to provide early detection to prevent grid events, assess and maintain system stability following a destabilizing event, as well as alerting system operators to view precise real-time data within seconds of a system event. This capability reduces the likelihood of an event causing widespread grid instability. Also, the use of phasor measurements is very valuable for post-mortem event analysis to understand the cause and impact of system disturbances. Phasor data is also useful in validating the dynamic models of generation resources, energy storage resources and system loads for use in transmission planning programs and operations analysis, such as dynamic stability and voltage stability assessment. The technology may have a role in determining dynamic system ratings and allow for more reliable deliveries of energy, especially from remote renewable generation locations to load centers. The ISO currently uses phasor data on a real-time basis for basic monitoring. Data from 56 phasor devices stream at a rate of 30 scans per second collecting more than three gigabytes of data per day. By the end of 2011, the ISO will receive data from other phasor measurement units located across the Western Electricity Coordinating Council area that will further enhance visibility to grid conditions. ISO s involvement with phasor technologies and its applications dates back to 2003. At this time, the ISO installed the Real-Time Dynamics Monitoring Systems (RTDMS) platform for conducting research into synchrophasors and applications and a phasor data concentrator (PDC). The PDC receives multiple data streams from the utilities PDCs, packages them together and broadcasts the packets as a user datagram protocol (UDP) in a PDC stream format. The IEEE C37.118 protocol has been designed to connect directly with the PDC output over a local area network connection, read the phasor data stream in real-time, and calculate scaled and derived values such as megawatts and megavolt-ampere reactive (MVAR). Once received, the raw data is processed to remove erroneous data and filtered for noise to improve data quality. Setting filtering options, entering PMU signal longitudes and latitudes, defining alarm and event archiving attributes are configurable settings through the RTDMS data management server graphical user interface. The parsed phasor data received from ISO PDC and derived quantities are stored in a real-time memory buffer. This data cache provides high performance data read and write capability for further processing or visualization. Additionally, the data will also be stored in a structured query language (SQL) database for long-term trending and reporting purposes. An alarm and event application retrieves data from the real-time cache, processes this information and saves the results back into the memory cache for real-time alarm use within the RTDMS client applications, the SQL server for offline alarm report generation, as well as logged into a text file for easy access within the server. Copyright California ISO Five Year Synchrophasor Plan November 2011 3

Table 2.1 provides a timeline of RTDMS development history. It is worth mentioning that RTDMS real-time monitoring was initially implemented in the ISO control center in 2008 for informational purposes. It has since evolved and will be piloted with operators on a limited basis in 2011. The application includes features such as: configurability, alarm capability, automatic event file generation, and event play back function. The application needs further development to reduce false positives in its event alarms, increase visualization functions and support integration with other applications. Table 2.1 RTDMS development history Timeline RTDMS Version Function enhancement 2003 Version 1.0 Standalone synchrophasor BPA phasor data included data visualization application January 2005 Version 2.0 Multi-user capability Frequency response monitoring SCE phasor data included Replay capability Wide-area visuals through configurability August 2005 Version 3.0 Transient detector Event archiving for transient events Enhanced alarming capability PG&E phasor data included 2006 Version 4.0 Dashboard display Real-time alarms Multi-level visualization Event archiving Client/Server User configurations Event detection Replay Functions 2007 Version 5.0 Small Signal Monitoring Open interfaces, external alarms (FNET) IEEE Standards Automated reports Reports, data extraction Integration with historians 2010 Version 6.0 Real-time monitoring of Subscription to notifications power-angle, power-voltage Small Signal Monitoring sensitivities IEEE Standards Color gradients for visualization 2011 plan Version 8.0 Database as backbone Improved RTDMS Configuration GUI RTDMS server, mode meter Event file in COMTRADE format calculation and oscillation PI Interface connector detection Improved Alarm/Event Detection 4 Five Year Synchrophasor Plan November 2011 Copyright California ISO

3.0 Key Activities To achieve our near-term goal of enabling wide area situational awareness using the synchrophasor data infrastructure, the ISO must enhance data quality and management, improve application functionality, and develop visualization capabilities. The following sections describe key activities as well as the current status and challenges. 3.1 Infrastructure 3.1.1 ISO Production Hardware Initially, the ISO synchrophasor hardware infrastructure was designed as a research and development pilot project. As utilities and the power industry have become more aware of PMUs benefits along with government incentives to deploy more units, it has become clear over the years that developing a production-quality synchrophasor architecture system is needed to support grid reliability and renewable integration. By the end of 2012, the ISO goal is to have a fully redundant synchrophasor system with a productiongrade application and database server in Folsom and Alhambra. When these servers are in place, utilities will send two separate phasor data streams, one for each location. This will enable fall-back to Alhambra servers should main servers in Folsom go offline for maintenance or upgrades. In addition to the production servers, there will be staging and test servers to evaluate new client versions and test integration with other tools. Figure 1 shows the synchrophasor infrastructure 2012 goal. Figure 1: Synchrophasor infrastructure goal by the end of 2012 WECC PDC BPA PDC PG&E PDC SCE PDC SRP PDC SDG&E PDC California ISO Energy Communications Network UDP/TCP FOLSOM Production epdc & RTDMS C37.118 ALHAMBRA Production epdc & RTDMS C37.118 TEST/STAGING epdc & RTDMS C37.118 PI Historian SQL Database PI Historian SQL Database PI Historian PRODUCTION PRODUCTION DEVELOPMENT Control Room Users Folsom and Alhambra Engineering Staff Users Folsom and Alhambra WEB Services to External Clients SQL Database Administrators APS PDC Copyright California ISO Five Year Synchrophasor Plan November 2011 5

3.1.2 Utility PMU placement PMU placement is often difficult to determine. Ideally, the ISO would like to have the devices installed at every bus on the grid but, in reality, that is not economically feasible. Therefore, future PMU installations need to be prioritized by taking into account the data requirements of all the different synchrophasor applications. With this in mind, the ISO provided a set of recommended placement criteria for investor-owned utilities. The ISO desires to have PMUs installed in high voltage substations, large generation power plants and load centers, major transmission lines, substations with remedial action schemes, and renewable generation plants. Currently, most of 500 kv substations within California have a PMU and it is expected to have them installed at all substations and generations plants meeting the criteria set out by the ISO. 3.2 Data quality and management 3.2.1 PMU data quality Data quality is foundational to achieving an accurate picture of the current grid state. The ISO currently receives synchrophasor data from 56 PMUs across the Western Interconnection via the WECC/ISO wide-area network connecting the Bonneville Power Administration, Pacific Gas and Electric and Southern California Edison PDCs to the ISO PDC. To help determine the health of the synchrophasor data stream, additional information showing data quality attributes is embedded in the data stream. On average, the data received from five to ten PMUs have quality or availability problems, which represent 10% to 17% of the total PMUs. Specifically, the most common data quality problems are invalid data (~80%), unsynchronized data (~10%) and data sorting problems where the data streams are sorted by time of arrival (~10%). When it comes to addressing the general problem of synchrophasor data quality and availability, ISO believes all synchrophasor systems should be migrated to production-grade hardware and software. Also, PMU and communication infrastructure maintenance should be elevated to a higher priority within the utilities that maintain the infrastructure. Synchrophasor data availability and quality should have the same priority level as supervisory control and data acquisition (SCADA) measurements as synchrophasor applications become an integral part of operating procedures. 3.2.2 Data retention / storage policy With the synchrophasor applications transitioning from a pilot project to production and the increase in data availability from sources both inside and outside the ISO footprint, the ISO needs to develop a strategy for data retention and storage. The ISO now receives three gigabytes of raw synchrophasor data daily. The current data storage policies and procedures were set up as part of a pilot project conducted more than seven years ago. Data is stored on stand-alone hard drives that make accessing and sharing between systems problematic. In addition, there are no defined practices in terms of the data retention time period and proper identification of data storage needs. An even larger need is to make this data more accessible. At this time, displaying the data in raw or processed forms require custom applications, however, to maximize the benefit from this technology, it is necessary to make this data readily available to all ISO systems that can use it. The incorporation of synchrophasor data into the Plant Information (PI) tool is proposed as a solution to this problem. The PI tool is not intended to visualize synchrophasor data but rather as a trending tool where different raw or derived phasor data can be plotted for any desired timeframe and compared with each other. This data will be then easily accessible for other in-house application and engineers. 6 Five Year Synchrophasor Plan November 2011 Copyright California ISO

3.3 Application functionality 3.3.1 Small Signal Analysis (SSA) It is every operator s objective to keep system oscillations under control while maximizing power transfers and maintaining system reliability. Monitoring devices such as PMUs can play a critical role in dynamic conditions System oscillations are expected in a large interconnected network of loads and generators. During normal operations, generators have the ability to retain synchronization speed with other interconnected generators and can maintain system stability. For example, when one generator drifts from the synchronous speed, the other generators in the network have enough inertia to provide the torque required to restore the unit back to the synchronous speed and maintain system stability. If the system is properly designed and operated and a disturbance occurs, the oscillations are damped and the system naturally returns to equilibrium quickly. However, if the disturbance is large or the interconnected system is somewhat weak, the oscillation caused by the disturbance could grow causing the system to become unstable and break apart leaving large areas without power. In some cases when system damping is inadequate, a disturbance on the grid, such as scheduled or unplanned transmission line outages can cause adverse and serious system stability problems. Sometimes only a slight variation in system operating conditions might exist in which an oscillatory mode becomes lightly damped. Under such circumstances, it is possible the system operators fail to notice this insecure state and miss the opportunity to remedy the situation before it is exacerbated by a system disturbance. PMU data can be used to compute damping ratios and determine the magnitude and energy associated with oscillations with certain frequency (so called oscillation modes) in real-time operations. Variable generation resources can strain grid stability and as such, system oscillations are becoming a much more serious threat. Monitoring, detecting and identifying low damping oscillations in a system with renewable resources is essential for system operators since this allows them to start control measures to damp out the oscillations by re-dispatching or forcing reduction in power generation. When oscillations are detected, a control signal can be generated and sent to the offending generator s excitation system to regulate its voltage and bring it into synchronization or reduce its output to a level that is no longer a threat to the system. Data obtained from PMUs can help identify the causes of some of the stability issues in the system. For example, some of the unstable modes are local where a small group of generators is out of synchronization with the rest of the generators in the system or inter-area where many generators in one part of the system are out of synchronization with the rest of the system. There are also some higher frequency oscillation modes that are caused by poorly-tuned exciters, governors or static VAR compensators. Bonneville Power Administration and Southern California Edison have already begun using PMU data to monitor and control oscillations 1. Off-line and post disturbance analyses are very useful in understanding grid dynamics. Using the data recorded by PMUs is vital in the calculation of the distinctive frequency responses contributed by each generator. Off-line analysis, such as modal analysis (using event or ambient data 2 ) and the use of algorithms such as Prony and Walker, can identify oscillation and damping modes. 3.3.2 Dynamic model validation Dynamic modeling and validation of complex power systems components are essential for optimal operation, safety and security of the grid. Also, important decisions on new capital investment are dependent on the accurate modeling of the different components in the system. Obtaining accurate model parameters in that 1 K.E. Martin, Phasor measurements in the Western Electric Power System, IEEE PES Transmission and Distribution Conference and Exhibition, 2006. 2 Ambient data refers to PMU data that is taken under normal operating conditions and is not related to a specific disturbance event. Copyright California ISO Five Year Synchrophasor Plan November 2011 7

the model truly represents system behavior is a challenging task. The unpredictable nature of system disturbances and modeling short comings to reflect real-time dynamic response of the system during events add complexity into finding a true system representation. In addition, the rapid increase in renewable resource penetration in the system further highlights the need for more accurate models and improved validation methods. The new models need to give an accurate representation of the aggregated nature of renewable resources, such as solar and wind. System planning for such systems can be difficult without an accurate comprehensive model. Failure of a model to predict or replicate the system s response to a disturbance is an indication of model weakness and inaccuracy. A good example of model inaccuracy was observed for the WECC system separation event of August 1996 3. Figure 2 shows the discrepancies between the simulated California-Oregon Intertie (COI) power transfer and the active power flow recorded at the Malin substation at the time of the event. The simulated power flow on the COI was not able to capture the growing oscillation phenomena. During off-line studies, the simulated COI power response resulted in a stable response without significant oscillations while in reality the system presented an unstable response with undamped and growing oscillations. Validation by field tests of any single power system component can be time consuming, expensive, and even sometimes an unachievable goal. An easier way to validate system models is to use data from real event recordings, compare them against the simulated dynamic response and then make the necessary Figure 2: Power flow oscillations recorded at Malin substation leading to WECC system separation 4,600 Observed COI Power (Dittmer Control Center) 4,400 4,200 4,000 4,600 Simulated COI Power (initial WSCC base case) 4,400 4,200 4,000 0 10 20 30 40 50 60 70 80 90 Time in Seconds 3 A major blackout event occurred in August 10, 1996 where the WECC system was separated into four electrical islands. 8 Five Year Synchrophasor Plan November 2011 Copyright California ISO

corrections to the models. PMU data is suitable for off-line model validation studies because they require high resolution data to accurately update the dynamic model parameters. PMU data from different events will also help on the continuous task of fine tuning the dynamic models. Furthermore, improving dynamic models will provide more accurate results when performing system operation limits studies which might relax or tighten operational limits resulting in more reliable and safe system operations. 3.3.3 Voltage Sensitivity Analysis (VSA) The WECC power system has dynamic stability problems. All 500 kv transmission lines in the ISO balancing authority are stability limited versus thermally limited 4. Both local and inter-area oscillatory modes have been identified across the grid, which can result in catastrophic events such as the 1996 blackout. This prompts the need to monitor oscillations and voltage changes in the system. Current tools used to monitor voltage are SCADA information, which is available every four seconds, and the state estimator solution (refer to section 3.3.7), which is available every minute. These tools, though, do not provide a granular enough resolution to monitor dynamic bus voltages changes in the system. The high resolution of synchrophasor measurements provides the ability to map changes in voltages at a bus to power flow changes on connected lines, which measures voltage sensitivity at that point. High voltage sensitivities could be an indicator of possible voltage stability problems. The phasor measurement-based voltage sensitivity analysis (VSA) application assesses the power (or current)-to-voltage system operating point and sensitivities at a sub-second resolution. Using VSA along with a model-based voltage stability application would provide the additional benefit of being able to monitor the current operating point against the power-to-voltage curves that are obtained from the network information. Presently, ISO has such a model-based voltage stability application called Real-Time Voltage Stability Analysis (RTVSA). This application uses the state estimator solution every 10 minutes to compute the load margin until system s collapse (or point of instability) by stressing pre-defined critical transmission paths. It also considers a set of pre-defined critical contingencies. From these results, power-to-voltage curves are obtained dynamically as the system operating conditions change with time. The proposed synchrophasor-based VSA combined with the model-based RTVSA tool, will provide the operators visibility of how stable or unstable system is in real-time. 3.3.4 Phase Angle Difference Dynamic Limits (PADDL) The phase angle difference between buses voltage phasors measured by PMUs on the transmission grid is an indication of system stability. An angle difference within a predetermined limit is acceptable but needs to be monitored closely for early warnings. An increasing margin of phase angle difference can be a serious problem when the deviation gets large enough to cause voltage instability. The ISO currently uses the RTDMS tool to display incoming synchrophasor data from across the Western Interconnection. This tool is in a development environment and needs further improvements before it is ready to use operationally. One area of improvement is producing meaningful alarms for operators when a critical event occurs. RTDMS generates alarms when the phase angle difference across a pre-defined transmission path goes over a threshold limit which alerts the operator of high active power flow (in megawatts) across the path which represents an unsecure operating condition. However, these phase angle difference limits were obtained by performing off-line studies on the WECC system back 4 When a transmission line flow reaches its maximum rated power capacity it is referred to as reaching its thermal limit. Copyright California ISO Five Year Synchrophasor Plan November 2011 9

in 2001. The power system s topology, generation and load patterns have changed since these studies were conducted, rendering these calculated phase angle differences limits obsolete. Phase angle differences can currently reach values over their calculated limits during normal operating conditions, creating false positive alarms. Operators have reported alarms generated when no critical event have occurred. One objective is to determine how phase angle difference limits can be computed from real-time system information and continuously updated online in RTDMS so that it will issue accurate alarms and eliminate the false positive ones. 3.3.5 Event playback Sudden changes in voltage or frequency measurements may suggest that the grid is undergoing a transient event such as loss of a generator, load or transmission line, or a fault in the system. When voltage or frequency measurements that go over a pre-defined limit caused by a transient event triggers an alarm, the application automatically saves into an event file all raw and derived phasor data captured before and after the transient detection along with an alarm summary log. The default duration time of this file can be configured. RTDMS has the capability to retrieve an event file and replay it for post-disturbance analysis. After retrieving an event file, the application offers traditional video player features such as auto-rewind and forward and a bar slider to move back and forth in time. 3.3.6 Automatic event analyzer The main objective of the automatic event analyzer is to use synchrophasor data recordings from multiple points across the system to identify the type and area of a disturbance. The power system is always subject to unplanned disturbances such as loss of load and generation or sudden unplanned outages of transmission facilities. The systems used to collect synchrophasor measurement data will be able to record most system disturbances. However, system operators need more accurate and timely information to better understand system status and take proper control actions. Thus, it is essential to analyze synchrophasor recordings quickly to identify the nature of events so the system operator can take appropriate actions to maintain system reliability. For example, a sudden loss of generation will cause the system frequency to drop, while a sudden load shedding will make it rise. Understanding this, a large disturbance can be identified by synchrophasor measurements, such as angle differences and frequencies. The ability of the automatic event analyzer to identify the source of a disturbance is dependent on the number and location of PMUs. 3.3.7 State Estimator At this time, the state of the transmission system (bus voltage angle and magnitude) is calculated using the state estimator. This application starts with the basic mathematical representation of the transmission system (network model) and then uses tens of thousands of analog measurements (MW, MVAR, voltage, and transformers tap position) to perform this calculation. Yet, PMUs directly measure the state of the transmission system. Therefore, PMU measurements can be used to cross-validate the state estimator solution. Conversely, PMU data accuracy will be verified at the same time because a bad PMU measurement will not match the state estimated solution and will be identified before it goes into the advanced applications and used for operational decisions. 10 Five Year Synchrophasor Plan November 2011 Copyright California ISO

3.3.8 Nomogram validation The existing operational nomograms have been developed from offline studies that considered different load and generation profiles, high power flow transfer through critical transmission paths, and contingency analysis using the base case system (all power system components are in service). However, it is known that real-time operating conditions can deviate from the simulated conditions (e.g., network topology, generation and load in the system is always changing). Taking into account that engineers cannot consider every single possible One goal is to study the possibility of using synchrophasor measurements, results from other synchrophasor-based applications that assess the health of the system, and possibly SCADA/state estimator data, to better assess system operating conditions and validate and improve existing nomograms. Specifically, synchrophasor measurements can contribute to detecting potential holes (unsecure operation conditions that lie inside the boundaries of the nomogram) and excessive conservatism (secure operation conditions that are outside of the boundaries of the nomogram) in existing nomograms. These concepts are shown in Figure 3. Figure 3: Potential hole and potential conservatism in a nomogram 5 Actual Real Time Limit Actual Real Time Limit Critical Parameter 1 Nomogram Real-Time Security Indicators Critical Parameter 1 Nomogram Potential Nomogram Conservatism Operating Point Operating Point Critical Parameter 2 Critical Parameter 2 operating scenario, there is some uncertainty in the study results and, therefore, the nomograms lean conservative, which results in less efficient use of the system. To operate the system more reliably and benefit from improved congestion management, less conservative and more dynamically adjustable nomograms are needed. Even though the concept of using synchrophasor data to improve nomograms seems promising, there are some shortcomings that need to be addressed. Challenges include the lack of network model information and the number and locations that have PMUs. The first challenge relates to the fact that nomograms are based on contingency scenarios; while 5 Extracted from http://certs.lbl.gov/pdf/cec-500-2008-049-apd.pdf Copyright California ISO Five Year Synchrophasor Plan November 2011 11

Nomogram Operating Point Actual Real Time Limit Real-Time Security Indicators Critical Parameter 2 synchrophasor data can help assess a real-time operating point of the system, it cannot predict the stability limits for the next contingency. This can be overcome by incorporating SCADA and state estimator results into the analysis. The number and location of installed PMUs present a problem of the lack of system observability into local voltage instability-prone areas. Within the timeframe of this plan, the ISO expects to see a significant increase in the number of installed PMUs through the WISP initiative. This will increase observability of the system. Also, it is important for the ISO to work with utilities to install PMUs in locations identified as critical to the ISO. 3.4 Visualization The main goal of this activity is to make use of an advanced visualization tool that is designed not only to observe PMU measurements but also to serve as a situational awareness tool that interfaces with multiple applications and performs further analysis using their results. Displays will include real-time measurements, such as phase angles, system frequency, and voltage magnitude, as part of the visualization to provide instant system observability. Operators can take quick actions following an event based on the real-time measurements, the analytical results produced by advanced applications, and operating procedures. Advanced applications will provide analytical results quickly from tools such as small signal analysis, automatic event analysis, voltage stability assessment and nomogram validation. The results will then be integrated into the visualization tool that will act as a common visualization layer for all other applications aforementioned to display different results as needed. Operators could then consult with more sophisticated system variables that will allow them to quickly evaluate the system operation status. For example, the current RTDMS software generates damping values on critical points where low frequency oscillations are likely to take place. The decrease of the damping ratio to values below five percent indicates the system can become unstable if being subject to a small disturbance. Operators can easily make adjustment to reduce the risk by constantly monitoring the damping variables. The visualization tool will also integrate monitoring tools such as PI and geospatial information system (GIS) displays. When an event occurs, the synchrophasor data will be useful for evaluating system stability; however, the PI and GIS displays can help operators quickly monitor system topology updates and geographical influence. Figure 4 shows a diagram Figure 4: The objective is a common visualization layer that integrates multiple applications results providing wide-area situational awareness Wide-Area Situational Awareness Visualization Critical Parameter 1 Common Visualization Layer Google Earth Tools PADDL Small Signal Analysis Nomogram Validation State Estimator RTVSA Non-operational data Sychrophasor data SCADA, CIM/XML 12 Five Year Synchrophasor Plan November 2011 Copyright California ISO

that includes the different advanced applications to be integrated within the common visualization layer which will provide wide-area situational awareness of the Western Interconnect system. 3.5 Operating procedures and training Synchrophasor measurements and the technology s associated applications are useful in tracking system dynamic behavior and transient instability. However, from a visualization and implementation perspective, they are very different from the traditional monitoring and management tools familiar to system operators. PMUs transmit data at rates of up to 60 measurements per second compared with SCADA data rate of one measurement every 4 seconds. They also provide values such as synchronized phase measurements across the interconnected system, which can be used to measure the phase angle difference between two points that might have not been monitored by SCADA systems. This means that the first step in creating synchrophasor data-based procedures will be getting operators familiar with the capabilities of synchrophasor measurements and its applications. At the same time, it is necessary to educate operators on the fundamentals of power system dynamics and train them on system control procedures. To develop standard procedures based on synchrophasor applications, abnormal phenomena identified by the synchrophasor monitoring applications need to be clearly defined and should complement the SCADA-based procedures. The time for synchrophasorbased data processing and related actions is critical because transient stability issues need to be resolved quickly to prevent a cascading failure. The ISO is currently developing operating procedures for low frequency oscillation detection and dynamic angle limit monitoring. For low frequency oscillation detection, several parameters need to be included in the procedure, such as the oscillation mode and damping ratio percentage. Specific mitigation actions need to be identified to be taken based on the combinations of these parameters. For dynamic phase angle limits, the parameter being monitored is the voltage phase angle difference between a set of PMUs which will directly measure the stress of the system. Each alarm trigger needs to be defined and tested separately taking into account the underlying topology. Currently, the ISO is working with BPA and WECC to develop a procedure to monitor low damping conditions at the California-Oregon Intertie. Copyright California ISO Five Year Synchrophasor Plan November 2011 13

4.0 Timeline A high-level timeline for the key activities described above is presented in Figure 5. It is important to emphasize that this timeline is used for guidance and will be modified as PMUs are deployed and applications advance. Figure 5. High-level timeline for key activities 2011 2012 2013 2014 2015 Production Hardware Procure Install Test PMU Placement Specify Install PMUs IOU Coordination Data retention/storage policy Policy PI Integration Small Signal Analysis Study Develop Procedures Phase Angle Dynamic Difference Limits Study Develop Procedures Voltage Stability Analysis Research Implementation Synchrophasor/EMS Integration Specify Research Vendors Integration/ Testing Nomogram Validation Study Update Procedures Dynamic Model Validation Research Implementation Visualization Specify Research Vendors Procure Integration Testing Operating procedures and training Develop Procedures and Training 14 Five Year Synchrophasor Plan November 2011 Copyright California ISO

5.0 Summary The ISO anticipates deriving many benefits from the deployment and application of synchrophasor technology. Table 5 below lists the key activities in our synchrophasor roadmap, the expected benefits and status. We expect to revisit this roadmap periodically as we participate in collaborative efforts with California IOUs, neighboring balancing authorities, members of the WISP project, and as synchophasor applications mature. Table 5: ISO Synchrophasor plan summary Application Data input What it does? Status Potential Benefits Small Signal Synchrophasor Analysis (SSA) Dynamic model validation Voltage Sensitivity Analysis (VSA) Phase Angle Difference Dynamic Limits (PADDL) Synchrophasor Synchrophasor Synchrophasor Performs oscillation detection, damping computation and mode identification PMU sub-second resolution data allows to obtain the dynamic response of components (generators, loads, renewable resources) Assess the current operating point and power-to-voltage sensitivities at a sub-second resolution. Dynamically computes the angle difference limits across pre-defined transmission paths Event playback Synchrophasor Provides the ability to playback events at a sub-second resolution State Estimator (SE) Nomogram validation Synchrophasor & SCADA, CIM/XML Synchrophasor & SCADA, CIM/XML Estimates the state (voltage magnitudes and angles) and provides results on network topology and flows. These results are used in Operations and Markets. Better assess the system operating conditions with respect to stability limits, and consequently validate or improve existing nomograms Developed (available on RTMDS); Results need to be monitored and validated Proposed Proposed Proposed Developed (available in RTDMS) SE with SCADA input is in Production; Adding PMU data input into SE is Proposed Proposed By detecting and identifying low damping operating conditions, operators can take preventive control actions to increase the system s damping. By validating current dynamic models with PMU data, planning and operations will obtain more accurate results when performing dynamic stability and voltage stability studies. Incorporated with model-based VSA application it provides operators visibility of current operating point vs. collapse point (unstable conditions) Monitor stress across the transmission system Automatically saves event files and allows the user to perform post-disturbance analysis Provides redundancy of measurements for improved bad data detection and allows for cross-validation between PMU measurements and SE results Synchrophasor data can provide for less conservative nomograms (operation boundaries) Copyright California ISO Five Year Synchrophasor Plan November 2011 15

6.0 Glossary Acronym BA BPA CIM / XML COI GIS IOU LADWP PADDL PDC PG&E PI POI PMU RAS RTDMS RTVSA SCADA SCE SOL SQL SSA VSA WAN WAPA WECC WISP Definition Balancing Authority Bonneville Power Authority Common Information Model / extensible Markup Language California-Oregon Intertie Geospatial Information System Investor-Owned Utility Los Angeles Department of Water and Power Phase Angle Difference Dynamic Limits Phasor Data Concentrator Pacific Gas & Electric Plant Information Point Of Interconnection Phasor Measurement Unit Remedial Action Schemes Real-Time Dynamics and Monitoring System Real-Time Voltage Stability Analysis Supervisory Control And Data Acquisition Southern California Edison System Operation Limits Structured Query Language Small Signal Analysis Voltage Sensitivity Analysis Wide-Area Network Western Area Power Administration Western Electricity Coordinating Counsel Western Interconnection Synchrophasor Project 16 Five Year Synchrophasor Plan November 2011 Copyright California ISO

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