Update on NERC Reliability Guideline: PMU Placement

Transcription

1 Update on NERC Reliability Guideline: PMU Placement Sarma (NDR) Nuthalapati, Ph.D., Principal Engineer, Grid Operations Support, ERCOT And Ryan D. Quint, Ph.D., P.E. Staff Coordinator, NERC SMS, SAMS SMS Meeting, November 03-05, 2015, San Diego

2 Background & Status Team Working on PMU Placement Guideline Sarma (NDR) Nuthalapati, ERCOT Ryan Quint, NERC Ken Martin, EPG Tony Faris, BPA Dimitry Kosterev, BPA Marianna, V&R Energy Hongming, PEAK RC Bruce, NYPA Dan Trudnowski, Montana Tech Mani Venkatasubramanian, WSU Manu Parashar, Alstom Kyle Thomas Gregor Jared. 2 RELIABILITY ACCOUNTABILITY

3 Preamble NERC develops guidelines that are useful for maintaining or enhancing the reliability of the BES Technical committees of NERC Operating Committee (OC) Planning Committee (PC) Critical Infrastructure Protection Committee (CIPC) Background & Status Technical Committees are authorized by NERC Board of trustees to develop Reliability (OC and PC) and Security (CIPC) guidelines Guidelines establish a voluntary code of practice Guidelines are coordinated by Technical Committees Includes the collective experience, expertise and judgment of the industry 3 RELIABILITY ACCOUNTABILITY

4 Background & Status Objective Distribute the key practices and information on specific issues critical to maintaining the highest levels of BES reliability Reliability guidelines are not to be used to provide binding norms or create parameters by which compliance to standards is monitored or enforced Incorporation of guideline practices is strictly voluntary Reviewing, revising or developing a program using these practices is highly encouraged to promote and achieve the highest levels of reliability for BES 4 RELIABILITY ACCOUNTABILITY

5 Purpose of the Guideline on PMU Placement To address the recommended practices for placement of Phasor Measurement Units (PMUs) and Background & Status Collection of Synchronized Phasor Measurement ( synchrophasor ) data To provide sufficient technical basis to make efficient and economical placement decisions Provide technical background to deploy additional PMUs for applications of high value for their system Provides insights into those standards for which PMU equipment and synchrophasor data are impacted the greatest Strategies center around the needs of the applications that use PMU data 5 RELIABILITY ACCOUNTABILITY

6 This guideline applies to: Transmission and Generator owners who own physical equipment Data owners or users for which PMU data is of value o Real-time applications: Transmission Operators Balancing authorities Reliability coordinators o Offline Analysis Transmission Planners Planning coordinators This guideline aligns with Background & Status Purpose of the Guideline on PMU Placement (Contd) NERC function of interconnection-wide event analysis and disturbance monitoring 6 RELIABILITY ACCOUNTABILITY

7 PMU installation generally follows standard practice for planning, design, installation and commissioning of instrumentation in a substation Planning stage o Measurements to be made o Signals required o Signal sources Design stage o Equipment required and equipment available for installation o Detailed design including equipment location, circuit wiring, communication interface and design of auxiliary equipment such as routers and timing receivers o Installation requires scheduling of staff and usually some line outages Commissioning Stage PMU Installation Tests with instrumentation in the substation Tests where data is decoded and used/recorded Check for intensive monitoring period of 1-7 days to check for dropouts, corruption, or other data problems 7 RELIABILITY ACCOUNTABILITY

8 Equipment Considerations PMU can be provided as a stand alone equipment or as a function within another device such as a relay or DFR Number of inputs: o Required inputs : voltage, current, analog values and digital indications Transmission level bus voltages and feeder currents Inputs Characteristics o Voltage and currents at required levels o To have appropriate input protection for dealing transients and intereferance o Current levels: expected to operate accurately at normal load levels o Should survive extreme conditions Signal Availability Output Capability Local Access Communication interface PMU Installation 8 RELIABILITY ACCOUNTABILITY

9 Communication and IT Considerations Communications are generally implemented using networks rather than individual wire and channel systems. Communication concerns are described here under the assumption of digital and networked systems. Bandwith : Amount of data that can be passed a given point in a unit time (bits/sec or kbps) o Synchrophasor data communicated at a continuous rate PMU Installation Typical rate : kbpts for 30/s measurement reporting rate Network communications handle this well (10 MBPS and up) Issue: when needed to share circuits with other applications some of which send data in bursts without sufficient prioritization and buffering, synchophasor data can be lost. Latency : amount of time delay from when data is sent to when it is received o Straight communication circuits are fast, approaching the speed of light. o However there is delay in coding the data into the circuit and decoding data out of the circuit. o More delay introduced by schemes for error detection, retransmission, extra decode-encode points when systems are merged, and data rates are changed. This can add up to 100 s of ms. o Latency affects real time applications such as control functions and real-time system displays. o Latency is not a concern for event archiving except as it may effect the data collection system. o A typical PMU to control center link will have ms of latency. Variable waiting and processing delays in data collection systems can increase overall latency to several seconds, so this must be considered in the overall application plan. 9 RELIABILITY ACCOUNTABILITY

10 Communication and IT Considerations (Contd.) Reliability : A measure of how likely a communication link is to fail, either momentarily or for long terms. o o o o o o o o Short term failure can include considerations such as fading on a long microwave link or a burst of data on a a link that exceeds buffering capability. Concerns like this are known and expected but reduced to a rare occurrence by statistical planning to reduce possibility. The more unknown failures include the quality of equipment and installation. Beyond planning for reduction of failure modes and high quality installations, redundancy techniques are required. At the lowest level, the most likely sources of failure such as interface equipment can be made redundant. The next step if making the communication path redundant with automatic path switching. A fully redundant installation will duplicate the entire measurement system from sensing through the measurement and communication. At this level the only single point of failure is the application itself. Security: A measure of how resistant the communication link is to intentional or unintentional interruption, corruption, or loss of data o o o o PMU Installation Complex and ever growing concern Terminal equipment (PMU and PDC) need to be secured to prevent unplanned changes to their configuration, interruptions in their operation, and unauthorized data access. Data on the links needs to be secured to be able to detect errors alteration, and spoofing. All communications for equipment used in system operations must be examined and certified to CIP requirements. 10 RELIABILITY ACCOUNTABILITY

11 Measurement Reporting Rates PMU Installation Phasor measurements are reported at a rate that is a multiple or submultiple of the system frequency. For a 60 Hz system, the standard reporting rates are 10, 12, 15, 20, 30, 60, or 120 measurements/second. The measurements are sent as a package, called a frame, where all the measurements are at the specific time represented in the timetag that is included in the message. Most systems in North America report data at 30 frames/second (fps). While this is the most common rate being used, the data requirements for applications vary. o An application that determines phase angle for reporting to SCADA only needs data at around 1 fps to match SCADA operating speeds. o Conversely, an application trying to detect subsynchronous resonance may require 120 fps reporting to enable detecting oscillations as high as 60 Hz. 11 RELIABILITY ACCOUNTABILITY

12 Measurement Reporting Rates: Considerations Application Requirements: o o Measurement bandwidth: The Nyquist rate restricts the bandwidth of the measurement to < ½ reporting rate. Practical filtering further restricts reasonable measurement to probably ¼ reporting rate Reporting Latency: The delay between reports will be 1/reporting rate. The measurement represents the value at the timetag but will have some filtering and thereby represents some average value around the timetag. P class uses a short window, so the delay between measurements may be much greater than the averaging window. Each measurement thus presents a new value, and the latency is close to the update rate. M class uses a long window that will span the reporting delays, so the reported value has a delay that is greater than 1/reporting rate. Communication Restrictions: o o o The reporting rate and number of reported values determining the minimum bandwidth. Attempting to send data at a higher rate will cause overload and data loss. Maintenance information, bursts of data by applications sharing the channel, and occasional impairments restrict channels below rated capacity. o The reporting rate needs to be restricted so that the requirement is below the usable channel capacity, which may be 20% to 80% lower than the nameplate capacity. Data Handling equipment: o o o PMU Installation Usually equipment like PMUs, PDCs, and application servers are sized to handle data at the specified reporting rate. The reporting rate may have to be restricted to prevent overloading them. PMUs may not be equipped to provide all reporting rates, so this could further restrict reporting rate specification. 12 RELIABILITY ACCOUNTABILITY

13 Measurement Reporting Rates: Considerations (Contd.) Data Storage capacity: o Synchrophasor systems are capable of producing a very large set of data. o The rate at which it is reported and stored directly affects the storage requirement. o Storage is usually specified based on reporting. PMU Installation o If that is not practical and there are restrictions, the data can usually be decimated by a PDC to an acceptable rate. o However if data reports directly to the storage device, it could be necessary to restrict the reporting rate to meet storage capacity limitations. 13 RELIABILITY ACCOUNTABILITY

14 Data Quality Synchrophasor data can include any electrical and physical quantity including voltage, current, frequency, power, breaker position, control values, alarm positions, etc.. However, the basic synchrophasor data only includes magnitude and phase of voltage and current, frequency, and rate of change of frequency (ROCOF). The focus here on data quality is on these data types Data Loss: PMU Installation o Data loss is where data is expected but no data is received. The most common place this is experienced in in communication systems. Buffer overruns due to insufficient bandwidth, either continuous or intermittent Interface mismatch: ports, connection types Incorrect routing Communication blockage due to incorrect security provisioning o The second most common area of loss occurs during data processing. Insufficient computer processing capability. Data loss occurs during task switching, background task activity, and other shared activity. Virtual servers not provisioned for real-time priority. Synchrophasor processing requires hard real-time activity while typical processing deals with blocks of data based on a scheduler. Redundant system switchover often causes a short data loss. Security between data handling systems can create problems Overload in data storage systems insufficient disc space. Also excessive storage access can interrupt data storage functions. 14 RELIABILITY ACCOUNTABILITY

15 Data Quality (Contd.) Data Corruption: PMU Installation o Corruption as used here refers to errors in the data representation rather than the values themselves. This kind of error includes bits that are lost or flipped, numbers that are represented in the wrong format, incomplete messages, and similar problems. o Bit and message format errors occur in communication and handoffs between equipment. They are usually detectable with a CRC and message format checking including message completeness, format, and length. o Other checks like measurement value ranges and time stamp values add more certainty. o The representation format errors are the result of configuration miscommunication. o In some cases the error will cause obviously bad values, like using floating point for integer data. o In other cases, like reversing real-imaginary, the problem will not be as clear and requires more data value checking. While this kind of error can largely be eliminated with thorough commissioning, continuing monitoring should be employed to detect unscheduled changes. 15 RELIABILITY ACCOUNTABILITY

16 Inaccuracy Accuracy addresses whether the measurement data correctly represents the engineering quantity. This includes both the value itself and the time given for that value. Synchrophasor, Frequency, and ROCOF are measurements of AC quantities, so have to be estimated over an interval of time or window. They can change over that window, so the reported value will be some kind of average over that interval. Factors that affect the accuracy of the estimate include: Time errors from either the time source or within the PMU. o o If the reference time is bad, the phase angle will be incorrect. Errors above 50 µs will be significant. If it is very far off, the measurement will be incorrect for the time given. the time error will have to be > 1 ms to make a significant difference. Any translation device from the point of sensing the measured quantity to the PMU affect the accuracy. o o PMU Installation PT/CT devices, auxiliary transformers, and electronic transducers if used. These problems include poor initial calibration, aging, uncompensated equipment repairs, and temperature effects. Extreme changes in value over the estimation window can degrade accuracy. Noise and interference can degrade accuracy, particularly for Frequency and ROCOF which are derivatives of the phasor values. Once estimated, the value is in digital form and the accuracy is fixed. However scaling and other processing can change the value and make the measurement inaccurate. Common errors include undocumented PT/CT ratio changes, phase angle adjustments incorrectly applied (eg, Y-Δ), and scaling misapplied (eg, l-l vs l-n). 16 RELIABILITY ACCOUNTABILITY

17 Lack of Precision Precision is how finely the number is resolved. For example, voltages of 1.5 V or V would both be reported as 2 V by a meter with 1 volt resolution. It the meter had 0.01 V resolution, these voltages would be reported as 1.50 V and 2.50 V respectively, clearly different voltages. PMU precision affects the measurement is the input A/D sampling. o o If the scaling is such that the signal level is very low compared with the A/D resolution, the waveform will be steppy and not very accurate. The lack of precision in this case shows up as a noisy measurement. Conversely, if the scaling is too high, the waveform will be clipped at times and the measurement will lose accuracy. Precision affects the measurements is in the calculations. o o o The numbers can be in integer or floating point and with different precisions. The issues in this case are the same as with the input. If the numbers are not scaled to use the right number of bits, the calculations can be steppy for too few or overflow at peaks with too many. Floating point processing can alleviate this by representing all numbers with the same resolution. Precision affects the reported values. o o o o Measurements can be transmitted in integer or floating point form. Floating point can provide all the precision of the calculation results within the PMU, so does not degrade precision. Integer number form usually requires scaling from the particular engineering value. If the scaling is not set to provide most of the bits of resolution, there will be a reduction in precision from the calculated value. This is particularly true when the data is to be used for small signal and modal analysis. Precision affects data storage o PMU Installation The least significant bits may be dropped or the data may also be compressed to reduce the storage requirement. In both cases there is a loss of precision to minimize data storage space. The tradeoff should be carefully analyzed to be sure the applications will not be adversely affected by data reduction. 17 RELIABILITY ACCOUNTABILITY

18 Incorrect Identification PMU Installation When received at a control center or other place the measurement will be used, it has to be identified as to the type of measurement, where it is taken, and the particular engineering quantity it represents. Measurement values are sent in some kind of block of numbers. The numbers are parsed from the data block and then identified by the order in the block, tags in the block, or some other means. If the measurement identifier, usually the measurement name (line, bus, substation, etc.) and type (voltage, current, etc.) are not correctly matched to the number, the value being used will be incorrect and misleading. This problem can easily occur because the naming and scaling are done at the substation but only observed at the control center. A thorough process to check this identification after installation will minimize the problem, though periodic checks are still required as occasional small repairs can cause changes that are overlooked. 18 RELIABILITY ACCOUNTABILITY

19 Latency Latency is the time delay from when the measurement is made until the measured value is ready to be used by an application. Normally the latency for synchrophasor data is quite low, on the order of 50 ms. However when there are problems with data communication and data processing equipment, it can become much larger, on the order of a few seconds. Setting the Phasor Data Concentrator (PDC): The PDC collects data from several PMUs and aligns it by time stamp before sending on to an application or another PDC. To do this, a PDC has to wait until the data for each time stamp from all the PMUs is present so these measurements can be aligned together. If one is late, then the aligned group is late. o o The PDC is designed to limit the wait so that if one measurement is lost, it does not wait forever. The challenge is setting the PDC so it will wait the maximum reasonable time for late data but not so much as to degrade performance if data is lost. If there is more than one PDC it the data processing chain, settings of the lowest PDCs in the chain will dictate coordination of the settings and the next level, and so on. They must be carefully coordinated to prevent excessive delay for the users or excessive data loss. Latency due to communication circuits: o o PMU Installation If communication circuits are highly loaded, buffering to handle data bursts can cause excessive latency. If they are overloaded, there will be data loss which will cause PDC latency as described above. Careful design and operation can assure the circuits are not overloaded to the point that they degrade the performance. 19 RELIABILITY ACCOUNTABILITY

20 Synchrophasor-based Application Matrix Synchrophasor data is used for an array of applications PMU placement should support the needs of all the applications Once placement strategies are discussed, a compiled prioritization and optimization table will be provided. 20 RELIABILITY ACCOUNTABILITY

21 PMU Placement Strategies Real-Time Tools Offline Studies 21 RELIABILITY ACCOUNTABILITY

22 PMU Placement Strategies for real-time tools State Estimation Oscillation Monitoring & Analysis Forced Oscillation Detection Inter-Area Mode Monitoring & Oscillation Subsynchronous Resonance & Subsynchronous control interaction Angle Difference Monitoring Line-based Phase Angle Difference Monitoring Wide-Area Phase Angle Difference Monitoring Blackstart & System Restoration Voltage Stability Model-based Measurement-based Hybrid Approach 22 RELIABILITY ACCOUNTABILITY

23 Major Interfaces Interconnection Reliability Operating Limits(IROL) and System Operating Limits( SOL) Remedial Action Schemes Wide-Area Visualization & Alarming Renewable Energy Resource Integration Power System Protection Automated or Supervised Voltage Control Oscillation Damping Control Island Detection PMU Placement Strategies for real-time tools (Contd.) 23 RELIABILITY ACCOUNTABILITY

24 PMU Placement Strategies for Offline Analysis Model validation Generator Model Validation System Model Validation Load Model Validation Disturbance Monitoring & Event Analysis Frequency Response Analysis Disturbance System Monitoring 24 RELIABILITY ACCOUNTABILITY

25 State Estimation (SE) PMU Placement Strategies for real-time tools State estimation is the process of deriving a best estimate of system state (system voltage magnitudes and phase angles) based on a set of measurements from the system. The state estimator (SE) produces a state estimate using measured quantities and statuses, such that bad data or errors are flagged through redundant measurements deriving the estimate. Conventional state estimation is based on minimizing the sum of squares of the differences between the estimated and the measured values of a function. There are three primary types of commonly used sate estimators: Conventional State Estimator o Non-linear State Estimation based on unsynchronized SCADA measurements Hybrid State Estimator o Non-linear SE using unsynchronised SCADA measurements and time synchronized data Linear o Direct, linear solution of system state using time synchronized data Observability Sufficient measurements (number and location) to make the system observable o Observability analysis determines if it is possible to estimate the system state from the available set of measurements. The system is considered to be observable if the Jacobian matrix has full rank. The number of measurements should exceed the number of system states. 25 RELIABILITY ACCOUNTABILITY

26 State Estimation (SE) (Contd.) PMU Placement Strategies for real-time tools To determine placement, one must differentiate between conventional and linear state estimation. PMU Placement for Conventional State Estimation PMU Placement for Linear State Estimation Observability analysis defines if a set of available measurements is sufficient to be able to estimate the system state. The concept of state observability and measurement placement remains the same regardless of the solution technique used for State Estimation. System observability depends on the number of measurements, locations of measurements, and topology of the system. Topological, numerical, and hybrid techniques are utilized to determine the network s observability. Numerical methods involve matrix analysis. Topological approaches are based on the graph theory. As a result of observability analysis, additional measurements that are needed for the system to become observable are identified. To achieve full observability, PMUs should be optimally placed. The objective function for identifying PMU locations is minimizing the number of PMU installations while achieving sufficient redundancy level. Excluding a redundant measurement should not affect observability of the system. 26 RELIABILITY ACCOUNTABILITY

27 PMU Placement Strategies for real-time tools State Estimation (SE) (Contd.) Bad Data Detection and Conditioning LSE is an important tool for bad data detection, including: o Bad PMU data; o Bad SCADA data; o Bad system parameters; o Errors in the process of conventional state estimation; o Separating bad data with an onset of an event. LSE maybe also used for topology estimation, if breaker status is not available Measurement redundancy is also essential for placement of PMUs in terms of bad detection and conditioning 27 RELIABILITY ACCOUNTABILITY

28 PMU Placement Strategies for real-time tools Oscillation Monitoring & Analysis PMUs enable real-time monitoring of system oscillations, and monitoring can vary from simple detection of the existence of oscillations to tracking a particular system mode s properties. PMU placement is critical to the monitoring of oscillations. Oscillatory Mode: A natural property of an electromechanical system ( electromechanical mode ) characterized by its frequency, damping, and shape. Inter-area modes are oscillatory modes consisting of many generators whose speeds move together cohesively. Oscillatory Mode shape: Relative perception of an Oscillatory Mode at different parts of a power grid. The Shape is defined by the amplitude and phase of the Mode at specific measurement locations. Forced Oscillation Response: Response of the system associated with an external input or a malfunctioning apparatus (e.g. malfunctioning steam valve cycling on and off, arc furnace induced dynamics). o o Forced oscillations may include harmonics resulting from the periodicity of the external inputs. Forced oscillations are typically undamped and persist until the malfunctioning device is removed from the system. Ambient Response: The response of the system to the small random changes within the system. These changes are typically characterized by small random load changes. 28 RELIABILITY ACCOUNTABILITY

29 PMU Placement Strategies for real-time tools Oscillation Monitoring & Analysis PMUs enable real-time monitoring of system oscillations, and monitoring can vary from simple detection of the existence of oscillations to tracking a particular system mode s properties. PMU placement is critical to the monitoring of oscillations. Oscillatory Mode: A natural property of an electromechanical system ( electromechanical mode ) characterized by its frequency, damping, and shape. Inter-area modes are oscillatory modes consisting of many generators whose speeds move together cohesively. Oscillatory Mode shape: Relative perception of an Oscillatory Mode at different parts of a power grid. The Shape is defined by the amplitude and phase of the Mode at specific measurement locations. Forced Oscillation Response: Response of the system associated with an external input or a malfunctioning apparatus (e.g. malfunctioning steam valve cycling on and off, arc furnace induced dynamics). o o Forced oscillations may include harmonics resulting from the periodicity of the external inputs. Forced oscillations are typically undamped and persist until the malfunctioning device is removed from the system. Ambient Response: The response of the system to the small random changes within the system. These changes are typically characterized by small random load changes. 29 RELIABILITY ACCOUNTABILITY

30 Forced Oscillation Detection: PMU Placement Strategies for real-time tools The goal in detecting Forced Oscillations (FO) is to quantify the oscillation amplitude, frequency(ies), and location of the root cause of the FO. PMU must be located near the source of the FO. Unfortunately, one cannot predict where FOs will come from a priori; therefore, one must consider typical sources of FOs. Type of sources: Traditional Generators: Power plants have many controls, with the primary functions maintaining mechanical power to the generator and generator field current at the desired level. FOs often result from malfunctioning power plant controls and/or devices. Examples of malfunctioning controls include misoperation or abnormal valve controls swinging in a limit cycle and hydroelectric generation plants operating in a rough zone resulting in resonance effects linked to the turbine penstock. Wind Generators: Unintended FOs induced by the turbine or plant-level control systems for wind turbines have been observed at high levels of wind power output. Cyclic Loading: Industrial loads are highly cyclic in nature, which can induce FOs into the bulk power system. Such as electrolytic process in aluminum smelting. Malfunctioning Grid Controls: Devices such as switched capacitors, SVCs, and series compensation devices can misoperate. Periodic malfunctioning can induce FOs into the system. 30 RELIABILITY ACCOUNTABILITY

31 PMU Placement Strategies for real-time tools Forced Oscillation Detection (Contd.): PMU should be placed near all generators (including wind), large load busses, and grid control devices in order to capture the location of FOs. An FO with an oscillation frequency near a system-wide oscillatory mode will be amplified by the system (i.e. a resonance effect). Therefore, even small generation plants have induced large system-wide FOs. To truly locate FO sources requires considerably wide PMU coverage across a particular interconnection. In most cases, FO are monitored in real-power flows, frequency signals, and voltage magnitude signals from the PMU as these quantities provide physical perspective to grid operators. For example, if a monitoring device states that a particular generator is oscillating with an RMS magnitude of 50 MW, this provides physical perspective and alarm limits to the operator. One natural perspective is to alert/alarm operators on FOs that are X MW above the normal ambient level and that persist for more than Y seconds. 31 RELIABILITY ACCOUNTABILITY

32 PMU Placement Strategies for real-time tools Inter-Area Mode Monitoring & Oscillation The characteristics of the oscillation are primarily dictated by the system grid topology and generation pattern over the entire interconnection. Transient stability simulations and eigenanalysis help engineers baseline expected oscillation properties. Certain locations will have very high observability of the mode while other locations will have no observability. System simulation and linear analysis studies are used to find these general locations. The goal of monitoring an inter-area mode is to track the mode s frequency, damping, and shape. Sophisticated signal processing algorithms are needed to accurately estimate these quantities along with properly-placed PMU measurements. Monitoring a particular mode requires PMU placement at the high observability points of the mode. Two levels are recommended. For the first, the few highest points of observability are required to monitor the frequency and damping of the mode. To monitor the shape of the mode requires a higher level of placement with PMUs located at all possible observability points within the interconnect. In general, is has been found that mode shapes rarely change unless major grid topology or generation shifts occur. 32 RELIABILITY ACCOUNTABILITY

33 PMU Placement Strategies for real-time tools Subsynchronous Resonance & Subsynchronous control interaction (Work in Progress) 33 RELIABILITY ACCOUNTABILITY

34 Angle Difference Monitoring PMU Placement Strategies for real-time tools Two main uses of PMUs Line-based Phase Angle Difference Monitoring Wide-Area Phase Angle Difference Monitoring 34 RELIABILITY ACCOUNTABILITY

35 Angle Difference Monitoring : Line-based Phase Angle Difference Monitoring The phase angle difference across a line provides useful information to a system operator, particularly for the application of line reclosing. PMUs located at both terminals of a transmission circuit allow for monitoring of phase angle difference across that circuit; in particular, enabling PMU-based line reclosing and line restoration supervision. Synchronism check relays are used in the protection system for actual reclosing; however, the PMUs can provide system operators with real-time visualization of the phase angle difference across the circuit and across circuit breaker(s) at each line terminal for pre- and post-contingency conditions. Two versions of reclosing or restoration monitoring: o PMU Placement Strategies for real-time tools Basic Monitoring: PMUs measuring voltage magnitude and angle on the bus-side of the circuit breaker(s) will provide the operators with the phase angle difference across the entire circuit. In the event of an out-of-service line, this provides the operators with insight into whether the synchronism check relays will be impacted upon attempted reclosing. The potential transformers (PT) for this capability are shown as the red measurement points in the Figure 35 RELIABILITY ACCOUNTABILITY

36 Angle Difference Monitoring : Line-based Phase Angle Difference Monitoring The phase angle difference across a line provides useful information to a system operator, particularly for the application of line reclosing. PMUs located at both terminals of a transmission circuit allow for monitoring of phase angle difference across that circuit; in particular, enabling PMU-based line reclosing and line restoration supervision. Synchronism check relays are used in the protection system for actual reclosing; however, the PMUs can provide system operators with real-time visualization of the phase angle difference across the circuit and across circuit breaker(s) at each line terminal for pre- and post-contingency conditions. Two versions of reclosing or restoration monitoring: o o PMU Placement Strategies for real-time tools Basic Monitoring: PMUs measuring voltage magnitude and angle on the bus-side of the circuit breaker(s) will provide the operators with the phase angle difference across the entire circuit. In the event of an out-of-service line, this provides the operators with insight into whether the synchronism check relays will be impacted upon attempted reclosing. Comprehensive Monitoring: PMUs measuring voltage magnitude and angle on the bus-side and line-side of the circuit breaker(s) of the circuit provide the operators with exactly the same measurement that the synchronism check relay would be experiencing (with some measurement error differences). The operator would know exactly the angle difference across each breaker as the line is reclosed or returned to service. The potential transformers (PT) for this capability are shown as the blue measurement points in Figure XXX, which would be in addition to the red points as well. 36 RELIABILITY ACCOUNTABILITY

37 PMU Placement Strategies for real-time tools Angle Difference Monitoring : Wide-Area Phase Angle Difference Monitoring Phase angle difference is directly correlated with system stress, and can be used as a strategic measurement of grid security both pre- and post-contingency. For improved wide-area phase angle difference monitoring and situational awareness, the following recommendations are provided: o Major interfaces: It is useful to monitoring the angle difference across major transmission interfaces across the grid, including both on a local- and wide-area basis. These interfaces are defined by key stress patterns driving the need to monitor these interfaces. Often times, a nomogram or operating limit is defined in terms of a real power (MW) transfer level. However, these limits can be defined in terms of angle difference, which is more illustrative of actual system stress. o Baselining: Which PMUs will be the most valuable for angle difference monitoring requires significant baselining analysis, both using actual system data as well as offline system studies. o Visualization: Wide-area angle displays such as angle contours or angle difference maps and trends provide system operators with increased awareness into the current state of the system. Visualization of angles is particularly useful after major system events since real power flows often redirect to unplanned conditions, and many times actually reduce due the increased electrical impedance between source and sink. Angle differences from PMUs can visualize this stress, complementing flow-based measurements. 37 RELIABILITY ACCOUNTABILITY

38 Blackstart & System Restoration (Work in Progress) PMU Placement Strategies for real-time tools 38 RELIABILITY ACCOUNTABILITY

39 Voltage Stability Voltage stability refers to the ability of a power system to maintain steady voltages at all buses in the system after being subjected to a disturbance from a given initial operating condition, and is a fundamental concept of power system stability analysis. System dynamics influencing voltage stability are usually slow, therefore steady-state (power flow) analysis offers an effective way to perform Voltage Stability Assessment (VSA). Power Voltage (PV) and Voltage Reactive Power (VQ) curves are the most frequently used steady-state techniques for voltage stability assessment. Voltage Stability Assessment is generally a scenario-based analysis. A VSA scenario includes specification of source and sink locations (e.g. injection groups), monitored interface, a set of contingencies, monitored elements, and buses to plot PV- and VQ-curves. Placement of PMUs to perform VSA or monitor VSA system conditions should consider the following: VSA Operating Condition Awareness: o o PMU Placement Strategies for real-time tools Synchrophasor data enables high-resolution monitoring of actual system voltages, which can be used for advanced real-time visualization of current operating conditions and voltage stability limits to better assess the power system s proximity to system collapse. For improved VSA awareness using synchrophasor data, PMUs should be placed to enable scenario-based analysis including locating PMUs at the following locations: PV Interfaces: PMUs located on the interface can be used to compare current operating conditions (pre- or post-contingency) to the stability limits determined using scenario-based tools. Monitored Elements: Voltage stability limited interfaces are driven by low voltage conditions on critical monitored elements post-contingency. A PMU placed at or near these critical monitored elements can help provide awareness of stability limts compared with simulation results to derive the limits. Injection Groups: PMUs located in the source and sink areas of the injection groups used to derive the VSA limits can provide additional VSA awareness. 39 RELIABILITY ACCOUNTABILITY

40 Voltage Stability Placement of PMUs to perform VSA or monitor VSA system conditions should consider the following: VSA Operating Condition Awareness: PMU-Based VSA: o o o PMU Placement Strategies for real-time tools An effective approach to performing VSA using synchrophasor data is based on Linear State Estimation (LSE) to derive a PMU-based power flow base case at PMU data rates (i.e. 60 times per second). Then, the LSE-based power flow case is used to perform VSA and identify active and reactive power margins and limiting contingencies. Computation of operating margins can occur at much higher rates that conventional VSA using SCADA measurements and SE solutions. This is beneficial immediately following a major contingency such that VSA margins and limits can be updated immediately rather than waiting for the next SCADA-based SE solution. 40 RELIABILITY ACCOUNTABILITY

41 Major Interfaces Interconnection Reliability Operating Limits(IROL) and System Operating Limits( SOL) (Work in Progress) PMU Placement Strategies for real-time tools (Contd.) 41 RELIABILITY ACCOUNTABILITY

42 Remedial Action Schemes (Work in Progress) PMU Placement Strategies for real-time tools (Contd.) 42 RELIABILITY ACCOUNTABILITY

43 Wide-Area Visualization & Alarming 43 PMU Placement Strategies for real-time tools (Contd.) PMU data provides high resolution visibility into system conditions, including dynamic behavior of the system following system events. A high-value use of PMU data is simply enabling improved visualization and advanced alarming techniques. The primary forms of synchrophasor-based visualization and alarming include the following: o Phase angle difference monitoring & alarming: System-wide: PMUs located across the system at strategic EHV bus locations Interface-based: PMUs located on either end of major transmission interfaces Line-based: PMUs located on either end of major transmission lines o High-resolution frequency Monitoring: System-wide frequency measurements across electrically diverse locations provides a much clearer and accurate representation of system frequency than conventional single-location measurements of local frequency. o Voltage trends and contouring: System-wide or local voltage measurements at major EHV buses for bulk system voltage monitoring; key EHV or lower voltage buses for local voltage monitoring. o Interface real and reactive power flow monitoring: PMU measurements covering all Elements of a major transmission interface provide the greatest visibility and accuracy of capturing the interface flows; measurements at either end of the interface are generally acceptable. o Alarming is a function of the monitoring Capability: There are no common industry practices for placement of PMUs specifically for advanced or improved system operator alarming. RELIABILITY ACCOUNTABILITY

44 Renewable Energy Resource Integration (Work in Progress) PMU Placement Strategies for real-time tools (Contd.) 44 RELIABILITY ACCOUNTABILITY

45 Power System Protection PMU Placement Strategies for real-time tools (Contd.) Out-of-step Protection Small Signal Stability Protection (Work in Progress) 45 RELIABILITY ACCOUNTABILITY

46 Power System Control Automated or Supervised Voltage Control Oscillation Damping Control PMU Placement Strategies for real-time tools (Contd.) (Work in Progress) 46 RELIABILITY ACCOUNTABILITY

47 Island Detection PMU Placement Strategies for real-time tools (Contd.) Islanding is when a portion of the bulk power grid becomes completely disconnected from other portions (an island ). o In an AC system, all areas are held together to the same average frequency by power transfer between regions. Power will flow from areas with excess generation to areas with deficit generation to keep the areas synchronized. o Overall the grid frequency is continuously changing around nominal value due to small perturbations such as load changes. Controls keep the generation and load balanced so frequency does not vary much. When a portion of the grid becomes islanded, there is no power flow to keep them synchronized. o The islanded system will speed up, slow down, or remain nearly the same depending on its internal generationload balance. Detection of islanding involves two essential processes: detecting that an islanding event has occurred and what elements the island covers. 47 RELIABILITY ACCOUNTABILITY

48 Island Detection (Contd.) PMU Placement Strategies for real-time tools (Contd.) Detection of islanding involves two essential processes: detecting that an islanding event has occurred and what elements the island covers. It is highly unlikely that the island will continue to operate at the same frequency as the rest of the system. If it does, then the event is not detectable nor is it important since it operates with the rest of the system in a normal manner. Discarding this trivial case, the frequency of the island will deviate from the rest of the system. o In the event that there is a big difference in frequency, the islanded portion can be identified by looking a substation frequency measurements. o If the frequency difference is small, the monitoring phase angle to see which angles track together with each other continuously will identify the islanded portion. o Frequency reporting errors, changes in islanded system frequency, and the possibility for an event to create multiple islands complicate creating reliable islanding detection algorithms. For effective islanding detection, PMUs need to be located in each area which could likely become part of an island. o Having several PMUs in each area guards against false alarms generated by PMU errors and missed alarms from PMU failures. In the case of a islanded region, PMUs in each area of the region can help define the interconnected areas and determine where the separations have occurred. 48 RELIABILITY ACCOUNTABILITY

49 Model validation Placement of PMUs for model validation is flexible yet highly important to enable the use of playback models and case comparison with actual system and unit-level response. Generator Model Validation o o o o o o o 49 PMU Placement Strategies for Offline Analysis PMU-based generator model validation is the process of comparing actual power plant or unit-level response to grid disturbances against modeled response. Online generator model verification provides a cost-effective and efficient way of meeting compliance with MOD-026 and MOD- 027, which focus on the exciter and turbine-governor functions, including plant-level volt/var and load controls, respectively. PMU placement and measurement capability are essential for power plant model validation. PMUs must be located such that the generator is radially connected to the location at which the PMU is monitoring. Multiple PMUs establishing a radial-like local network of the generator connected to the external grid can also be used to perform playback since they are time-synchronized to one another. Generally, the PMU is placed at the terminals of the generator(s) at either the high- or low-side of the generator step-up (GSU) transformer. PMUs are often installed at the Point of Interconnection (POI), which is the jurisdictional boundary between the Generator Owner and Transmission Owner, such as the Transmission Owners interconnecting substation. This is an acceptable practice assuming the radial nature of connection to the rest of the system is maintained. At the point of PMU Placement, the following electrical quantities need to be measured: Bus Voltage magnitude Line 3-ph real power (MW) and Reactive Power (MVARs) Bus Frequency RELIABILITY ACCOUNTABILITY

50 Model validation (Contd.) : System Model Validation System model validation is the process of comparing modeled system conditions with actual conditions during steady-state and disturbance events on the system. o o o o o o PMU Placement Strategies for Offline Analysis Unlike generator model validation, system model validation focuses on the performance of the aggregate model of the interconnected system. NERC Reliability Standard MOD-033 serves the purpose of establishing consistent validation requirements for the construction and utilization of planning models for analyzing the reliability of the bulk power system. MOD-033 incorporates both steady-state and dynamic model validation; PMUs play an essential role in validation of dynamic models specifically due to the continuous recording and high resolution data available. Quantities to be compared include bus voltage magnitude, phase angle, and frequency; Generator real and reactive power outputs, line and transformer flows, dynamic reactive power resources, and HVDC response. Aspects to compare include inter-area oscillations, pre- and post-contingency conditions, and frequency response. PMU Placement for the purpose of improving system model validation include capturing the response of: Large power plants or generating units; Dynamic reactive power resources such as STATCOMs, SVCs, or synchronous condensers Major transmission interfaces SOLs, IROLs, major transfer paths Cohesive load zones capture aggregate load response Major system loads large industrial or block loads Terminals of HVDC resources (on the AC side of the transformer) Automatically controls resources such as Under-Load Tap Changers (ULTC), phase-shifting transformers, and switched shunt devices Remedial action schemes Capturing the dynamic response of these resources enables validation of the dynamic models behind these resources such as governors, excitation systems, power system stabilizers (PSS), FACTS and HVDC controls, RAS, and transformer controls. 50 RELIABILITY ACCOUNTABILITY

51 PMU Placement Strategies for Offline Analysis Model validation (Contd.) : Load Model Validation High resolution data can also be used to validate the performance of dynamic load models, and has been successfully performed by many utilities. End use loads are located, generally, at the distribution system; however, these loads are often modeled at the transmission system. It is important to understand the effects that the system disturbances have on the end use loads, and vice versa. To accomplish this, it is necessary to have data sources at as many of these locations, from the transmission system down to the individual feeders and end use loads, as possible. Data is not limited to synchrophasor data and many data sources are used in this process, including: o Phasor measurement units o Digital fault recorders o Power quality meters o PQube devices o Sequence of event recorders o Relay oscillography records o SCADA data PMUs at the transmission and sub-transmission voltage levels provide a time synchronized reference and are often used to time align the unsynchronized data sources from various measurement locations. 51 RELIABILITY ACCOUNTABILITY

52 PMU Placement Strategies for Offline Analysis Disturbance Monitoring & Event Analysis PRC (approved by the FERC on September 17, 2015) requires that adequate data [is] available to facilitate analysis of Bulk Electric System (BES) Disturbances, focusing on three distinct forms of disturbance monitoring data sequence of events recording (SER) data, fault recording (FR) data, and dynamic disturbance recording (DDR) data. PMUs are a form of DDR monitoring equipment, and generally meet the technical specifications outlined in the standard. PMUs are expected to play a critical role in capturing the required data for event analysis for major grid disturbances moving forward. Requirement R5 outlines the placement requirements for which data is required, and includes the following: o Generating resources with gross individual nameplate rating greater than or equal to 500 MVA; or gross individual nameplate rating greater than or equal to 300 MVA where the gross plant/facility aggregate nameplate rating is greater than or equal to 1,000 MVA o Any one BES Element that is part of a stability (angular or voltage) related System Operating Limit (SOL) o Each terminal of a high voltage direct current (HVDC) circuit with a nameplate rating greater than or equal to 300 MVA, on the alternating current (AC) portion of the converter o One or more BES Elements that are part of an Interconnection Reliability Operating Limit (IROL) o Any one BES Element within a major voltage sensitive area as defined by an area with an in-service undervoltage load shedding (UVLS) program Requirements R6 and R7 specify the electrical quantities that must be either directly measured or calculated. These apply for each of the BES Elements specified in Requirement R5. At a high level, these requirements mandate the following quantities to be measured: o One phase-to-neutral (or phase-to-phase for Generator Owners) or positive sequence voltage. o The phase current of the same phase(s) at the same voltage corresponding to the voltage(s), or positive sequence current. o Real Power and Reactive Power flows expressed on a three phase basis corresponding to all circuits where current measurements are required. o Frequency of any one of the voltage(s) specified. 52 RELIABILITY ACCOUNTABILITY

53 PMU Placement Strategies for Offline Analysis Disturbance Monitoring & Event Analysis (Contd.) PRC (approved by the FERC on September 17, 2015) requires that adequate data [is] available to facilitate analysis of Bulk Electric System (BES) Disturbances, focusing on three distinct forms of disturbance monitoring data sequence of events recording (SER) data, fault recording (FR) data, and dynamic disturbance recording (DDR) data. Requirement R8 requires continuous recording of DDR data while Requirement R9 requires that the input data rate be greater than or equal to 960 samples per second and the output reporting rate be at least 30 samples per second. Requirement R10 defines time synchronization with accuracy of +/- 2 milliseconds, which is well within the requirements set forth in IEEE C Requirement R11 focuses on data formatting for submitting data when requested and the timeframes for when that data is due to the requester. PRC addresses only the PMU locations which are essential to event recreation for major grid disturbances, enforcing mandatory and enforceable requirements for the monitoring of these locations. However, PMU data plays a crucial role in this process, and any available PMU data helps time align the sequence of events and corroborate unsynchronized measurement sources. o For example, PMU data was valuable in the expeditious event recreation for the 2011 Pacific Southwest Outage event, as well as benchmarking the simulated performance against actual response. 53 RELIABILITY ACCOUNTABILITY

54 PMU Placement Strategies for Offline Analysis Frequency Response Analysis While SCADA data can be used for frequency response analysis, synchrophasor data provides time synchronism and higher resolution that simplifies and improves analysis. Frequency response analysis can be distinguished by three resolutions: 1) Interconnection-wide, 2) Balancing Authority (BA), and 3) plant-level. Interconnection-wide frequency response analysis is associated with characterizing the grid s response using a set of criteria. NERC performs extensive interconnection-wide frequency response analysis on an annual basis to define obligations for the overall system and each balancing authority to meet. At this level, it is necessary to define a system frequency signal for each time stamp in the event. It is useful to have PMUs spread throughout the system, particularly on the edges of the system, such that a quality system frequency value can be defined. 54 RELIABILITY ACCOUNTABILITY

55 Frequency Response Analysis (Contd.) On the Balancing Authority level, BAs are required to monitor their BA-level frequency response. This is performed by monitoring the net interchange on all tie lines with neighboring BAs for a given event. Therefore, utilities use SCADA data due to the large number of monitoring points required. Frequency response analysis can be improved by measuring the points required to calculate net actual interchange using PMUs 55 PMU Placement Strategies for Offline Analysis Frequency response analysis can be distinguished by three resolutions: 1) Interconnection-wide, 2) Balancing Authority (BA), and 3) plant-level. Plant-level frequency response is a relatively new concept that focuses on comparing the plant (or unit) response to under-frequency events to monitor whether the plant responded as expected. o For example, this type of analysis can be used to determine if a plant was o o base loaded, frequency responsive, or under plant-level load control. For this type of analysis, the PMUs should be monitoring the terminals of the generator (or high-side of the GSU) Measurement points: bus voltage phasor frequency, and real and reactive power output of the generator or plant. RELIABILITY ACCOUNTABILITY

56 PMU Placement Strategies for Offline Analysis Disturbance System Monitoring (Work in Progress) 56 RELIABILITY ACCOUNTABILITY

57 Optimization and Prioritization of PMU Placement Optimization and Prioritization of PMU Placement (Work in Progress) 57 RELIABILITY ACCOUNTABILITY

58 Optimization and Prioritization of PMU Placement Cross-cutting PMU Placement (multiple applications) (Work in Progress) 58 RELIABILITY ACCOUNTABILITY

59 59 RELIABILITY ACCOUNTABILITY

60 Angle Separation Monitoring: Industry Experience Following the 2011 Pacific Southwest Outage Recommendation 27 NERC Synchronized Measurement Subcommittee (SMS) Hongming Zhang, Ph.D., EMS Manager, Peak Reliability Aftab Alam, [Title], California ISO November 3, 2015

61 Angle Separation Monitoring: NERC Recommendation 27- Direction Southwest Outage Report Recommendation 27 o TOPs should have: (1) the tools necessary to determine phase angle differences following the loss of lines; and (2) mitigation and operating plans for reclosing lines with large phase angle differences. TOPs should also train operators to effectively respond to phase angle differences. 2

62 Angle Separation Monitor: Integration with EMS Network Applications 3 Major utilities monitor bus angle separation for reclosing line in state estimator (SE) and real time contingency analysis (RTCA) o Bus/node pair and angle difference limit are determined by synchro-check relay settings o Angle separation violation can be detected under basecase and/or post-contingency o Operators shall restore the system to a secure [N-1] state as soon as possible, but no longer than 30 minutes

63 BaseCase Exceedance Post-CTG Exceedance 4

64 PMU based Angle Separation Monitor Typically SE and RTCA run for one and five minutes, respectively Fast monitor application upon PMU signals is available now, yet mainly used for wide area bus angle difference calculation per <10s 5

65 Baselining & Benchmarking PMU and SCADA Data Highlights: Compare Phasor values (30 samples/1s) to known trusted values o ICCP/SE (10s/60s scan rate) Set allowable deviation o o Angle = 2 Deg. Mag = 1% of Nominal KV Determine % Good (within allowable deviation) = AAAAAA(VVVVVVVVVV IIIIIIII/SSSS VVVVVVVVVV PPPPPP ) > DDDDDDDDDDDDDDDDDD LLLLLLLLLL Notes: SCADA ICCP measurements are being refreshed in 10s. PMU voltage measurements are sent in SCADA at 1s interval. SE solves for every 60s. The SE values need be written in SCADA for storing in PI At least one of PMU reference angle measurements need be enabled in SE 6

66 Phase Angle -Real Power Correlation Phase angle and real power correlation holds true for transmission network with small ratio of line r/x (resistance/reactance) typically PP LLLL = 1 XX LLLL θθ ss θθ rr Path MW Actual vs Correlated Angle Separation 7

67 Case Study #1: Path Operation Monitor under Planned Line Outage A Path consists of multiple line segments. Path flow changes little with loss of one line Path SOL was derated prior to one planned outage 8 LINE MW FLOW PATH OPERATION LIMIT v PATH MW FLOW

68 Stress Indication: Path MW vs Angle Separation under a Forced Line Outage 9 Traditionally, operators gain awareness of operating stress for a given Path by monitoring Path loading as a percentage of the Path Limit in MW. PPPPPPP SSSSSSSSSSSS = FFFFFFFF MMMM 100 LLLLLLLLLL MMMM It s less effective in case of forced outages because (1) Path limit in MW is not updated timely; (2) Path flow may not increase

69 Case Study #2: Path Operation Monitor under a Forced Outage LINE MW FLOW PATH RATING in MW PATH MW FLOW BUS ANGLE SEPARATION 10

70 Observations from Case Studies It s noted from PI Trend: 11 o Visible correlation between Path MW and the angle separation before the outage o Path limit holds the same before and after o Path MW loading decreases by 200 MW while the angle difference is separated considerably Angular separation offers a strong indicator of system stress, complementing traditional MW Limit or MW loading% exceedance

71 Case Study #3: Path MW Loading % vs Angle Separation Stressing Correlation between Path MW high loading % and stressed angle separation condition surely exists 12

72 Findings and Recommendation #1- Linking Angle with Key Transfer Paths The correlation between key transfer paths and angle separation is strong in general Path MW limit assessment has been established When the path loading % is high (e.g., > 90%), the sensitive angle pair separation is likely approaching the stress limit, assuming the Path Limit is dynamic and reasonably accurate (e.g. key baselining clues) The angle separation value and limit may change based on underlying or nearby line outages driving system angle stress but reduced MW flows. 13

73 Findings and Recommendation #2 - Linking Angles with System Studies Angle separation based Safe & Alert Operating limits shall be defined upon adverse operation conditions: 14 o Syncro-check relay reclose angle difference exceedance o Excessive thermal limit violation that potentially leads to cascading outages o SOL or IROL exceedance due to voltage stability and transient stability concerns o Subsynchronous resonance (SSR) driven by bulk wind generation and weak system connection issues o Triggering RAS/SPS and affecting oscillation damping

74 Actions for Excessive Phase Angle Differences Practical control actions by industry include o Coordinated phase shifting XF tap movements o Reconfiguration of in-series capacitors /reactors o Optimal line switching to re-direct power flow o Generation re-dispatch o Curtailment of interruptible load, if necessary o Firm load shedding, if necessary o Point-to-point transmission service curtailment 15

75 Monitoring WECC Inter-Area Modes Known Inter-Area Modes in WECC System: Mode Frequency Hz (normally) NS Mode A 0.25 NS Mode B 0.32~0.39 Montana 0.8 BC 0.6 E-W A (new) 0.45 E-W B (new) BPA, SCE and Peak et al enabled real-time monitoring and engineering analysis for Modes A & B

76 Inter-Area Oscillation Mode Study Case #1-Chief Jo Brake Testing On June 17, 2015, it inserted the 1,400 MW braking resistor for 0.5 seconds and then disconnect it to benchmark system oscillatory performance to a grid disturbance 17

77 NS Mode B Results on the Break Test 18

78 Remarks-1 After the first brake test was performed, the N-S Mode B damping ratio dropped from ~12% to ~8%, lasting for about 30 minutes. It is noted that both the COI MW flow and Custer- Malin angle separation did not change drastically during this timeframe. Additional operational changes during this time are being investigated to better understand the primary drivers of N-S Mode B damping ratio variations. 19

79 Inter-Area Oscillation Mode Study Case #2-PDCI Step Down Event On 08/17/2015, PDCI Stepped Down 800 MW 20

80 NS Mode B Damping Results on the PDCI Step Down Event 21

81 Remarks-2 Comparing with the Brake Test, one can notice that COI MW loading is much higher and the correlation between COI MW flow and angle separation of Big Eddy-Malin and John Day-Malin are considerably stronger Noticeable correlation between two patterns of phase angle differences and N-S Mode B damping ratio A thorough analysis and study report on the PDCI event will be reported in future 22

82 Utility Practices & Strategies Peak Reliability Coordinator (Peak Reliability): 23 o Phase-I: Identifying a list of correlated phase angle separation pairs against WECC Paths and IROLs/SOLs Baselining the Safety & Alert thresholds from PI historian o Phase-II: Performing in-depth offline studies using EMS, Stability Limit Assessment tools and Oscillation software Understanding of angular separation limits, implications of angle exceedances, and actionable measures to mitigate large angle separations. o Phase-III: Using Big Data techniques to leverage historical PMU and EMS data, operation study results, R- T transfer analysis to compute dynamic angle limits

83 Utility Practices & Strategies (Cont d) California ISO (to be added by Aftab) 24

84 Utility Practices & Strategies (Cont d) SRP (to be added by Naim and Matthew) 25

85 Utility Practices & Strategies (Cont d) APS (to be added by Jeff) 26

86 Efforts Going Forward List main tasks and schedules of angle separation monitoring implementation in the industry under NERC guidance. 27

87 Hongming Zhang, EMS Network Applications Manager, Peak

88 Data Injection Function in TSAT & ModV Program Synchronized Measurement Subcommittee Meeting Nov 3-5, 2015, San Diego, CA Gang(George) Zheng

89 Highlights DSATools TM - TSAT Data Injection function in TSAT Data format Illustration Model Validation Tool (ModV) 2

90 3 DSATools TM - TSAT

91 DSATools TM A suite power system analysis tools Core Component: PSAT VSAT TSAT SSAT DSA Manager Add-on modules Comprehensive security assessment Stability study 4

92 DSATools TM - TSAT Transient Security Assessment Tool (TSAT) leading-edge time-domain simulation tool designed for comprehensive assessment of dynamic behavior of power systems A rich model library State-of-the-art solvers Useful analysis features Highly intuitive user interface Calculate transient security limits under specified criteria, contingencies, and transfer conditions 5

93 6 DSATools TM - TSAT

94 7 DSATools TM - TSAT

95 8 Data Injection Function

96 A function available in TSAT Playback measured data during the simulation Useful for dynamic model calibration Input 1. Field measurement high resolution data 2. System models 3. Station or bus number or name where the injection to be Output Data Injection Function Time domain simulation results 9

97 Data Injection Function Data Format Time varying voltage and frequency/angle measurements (actual values or p.u. values) Voltage Frequency Angle Voltage and Frequency Voltage and Angle Multiple data files at different buses are supported 10

98 Data Injection Function Data Format 11

99 Data Injection Function Case Example 12

100 Data Injection Function Case Example Incorporate injection data with simulation system: 13

101 Data Injection Function Case Example 14

102 Data Injection Function Case Example TSAT Nov 01, :19:42 Buf. Binary Result File Scenario Contingency 3 E:\DSATools\TestCases\TSATcases\Data_Injection\IEEE39\IEEE59 modified\tb2014_12_11_10_ Eq N-1 scan 2014_12_11_10_24_ T EST Line active power flow (MW) -120 Bus # Bus Name ID Buf. 19 ALGER.BS ALDER.BS Time (sec) 15 DSATools Output Analysis 11.0 Powertech Labs Inc. Copyright 2015 All rights reserved

103 Data Injection Function Case Example TSAT Nov 01, :19:42 Buf. Binary Result File Scenario Contingency 5 E:\DSATools\TestCases\TSATcases\Data_Injection\IEEE39\IEEE59 modified\tb2014_12_11_10_ Eq N-1 scan 2014_12_11_10_24_ T EST Line reactive power flow (MVAR) 20 Bus # Bus Name ID Buf. 19 ALGER.BS ALDER.BS Time (sec) 16 DSATools Output Analysis 11.0 Powertech Labs Inc. Copyright 2015 All rights reserved

104 17 ModV

105 ModV - Introduction Helps utilities become compliant with the NERC MOD 33 standard Uses PMU data from field to validate dynamic models Initiated in collaboration with PEAK RC in 2014 Profound interest from NA utilities Graphic-enriched, user-friendly interface 18

106 19 ModV User Interface

107 ModV - How it works (Steps) 1. Takes system simulation models and PMU data; 2. Based on the PMU data, ModV makes voltage and frequency injection data into the system; 3. ModV then runs simulation and monitors the MW and Mvar flow; 4. ModV compares the actual PMU measurements with the simulated results to validate the models. 20

108 21 ModV Process

109 22 ModV Example - Video

110 Contact Us 23

111 ATC Experiences: Initial Tests using PSS E Playback Jim Kleitsch for NERC SMS Meeting November 4, 2015 atcllc.com

112 ATC Overview American Transmission Company [ATC] is a transmission-only utility 9,400 circuit miles of transmission line 535 substations (wholly or jointly owned) Peak demand in footprint: 13,270 MW Service area includes portions of Wisconsin, Michigan, Minnesota, and Illinois 2 atcllc.com

113 Background Information ATC was formed by transfer of the transmission assets of ~20 transmission owning entities (Large Utilities, Coops, Municipals, etc..) Many of the employees who performed dynamics studies at the predecessor companies transferred to ATC to support our Operations. Issues trying to maintain and update generator models as the data was not owned by ATC Recently completed a project to request and archive generator model and facility information for all the entities in our footprint After the project we had the model data but no real way to verify how complete or up to date it is. Until now.. atcllc.com 3

114 Initial Tests using PSS E Playback Ryan ran an analysis on one sample unit to highlight what the results for a specific event (fault and large unit trip). He shared these results with our Planning group to show the value of the analysis Our Planning group is engaged and they worked with Ryan to get the tools enabled on our system We are committed to performing additional analysis on different events and units and have already collected the needed data. Unfortunately workload is an issue at this time so things are on hold until we have personnel available. We have identified 12 units with GSU high side PMU metering and 4 wind plants with point of interconnection PMU metering we can use in our testing. atcllc.com 4

115 Initial test case Looked at data for one large coal fired unit for an event where a bus fault tripped off a large generator within 100 miles of the test plant. Ryan performed an initial comparison AS IS which had the governor disabled by default. Without a base load flag to hold valve position in the dynamic run, governor-on results are way off. The different runs and associated parameter changes are as shown. Plots of the results follow: atcllc.com 5

116 Initial Results For One Unit One Event atcllc.com 6

117 Initial Results For One Unit One Event (cont d) atcllc.com 7

118 Initial Results For One Unit One Event (cont d) atcllc.com 8

119 Issues to be addressed/discussed We scan all PMUs at 30 samples/second but have the capability to go to 60 samples per second. Need to decide if there s value in making that change for unit validation. We use compression and exception processing when storing data to PI. We store raw value in our PhasorPoint historian and have elected to use that for the input to the analysis. If we switched to PI as an input source we need to understand impacts of data compression. Do we need to update to the latest C protocol before we start using the data for any type of official analysis? atcllc.com 9

120 Issues to be addressed/discussed (cont d) How do we manage differences in data for different PMU vendors? Specifically integer based processing with discrete changes from DFR vendors versus real data based processing from stand alone PMUs. atcllc.com 10

121 Where Do We Go From Here? Working to develop a high level project plan to allow us to monitor all units per MOD requirements (units greater than 100 MWs, etc ). This would include an additional 30 PMU installations. We need to determine if/when we have enough confidence in the tools to move forward with that project. We are looking at ways to work with our interconnected Generation Owners to help them understand what we re doing and how we plan to use the new tools to help us validate / sanity check the model data they provide. On a somewhat related note we re considering doing something similar on distribution interconnections to help validate our dynamic load models atcllc.com 11

122 Questions? atcllc.com 12

123

124 Table of Content Mechanics of Dynamic Simulation Model Validation Using PMU data during Large Network Disturbances Chief Joseph Brake Test Model Validation Examples (Combined Cycle, Wind Turbine, and Solar PV) Conclusions

125 Dynamic Models (A typical power system network one-line diagram) M Fig. 1 Typical power system network

126 Dynamic Models (Distinguishing dynamic and non-dynamic elements) M Fig. 2 Distinguishing dynamic and non-dynamic elements

127 Dynamic Models (Modeling dynamic and non dynamic elements) PSS Turbine G + Exciter PSS Turbine G Transmission Network (no dynamic elements) Loads + Exciter PSS Turbine G M + Exciter Fig. 3 Modeling dynamic and non-dynamic elements

128 Dynamic Model Models (IEEE Task Force on Turbine-Governor Modeling: Technical Report PES-TR1 Jan 2013 ) Fig. 4 Turbine Governor of a Gas Turbine unit

129 Dynamic Model Models (IEEE Task Force on Turbine-Governor Modeling: Technical Report PES-TR1 Jan 2013 ) Fig. 5 Functional Components of a Gas Turbine Unit

130 Dynamic Model Models (IEEE Task Force on Turbine-Governor Modeling: Technical Report PES-TR1 Jan 2013 ) Fig. 6 Block Diagrams of the Components of a Gas Turbine Unit

131 Dynamic Model Simulation (Steps in Numerical Simulation) Fig. 8 Steps in Numerical Simulation

132 Model Validation Using PMU Data (Courtesy of BPA, based on the methodology proposed by Dmitry Koserev and Steve Yang) Fig. 9 PMU needs to be placed at Power Plant POI

133 Model Validation Using PMU Data Fig. 10 Disturbance play-in capabilities are added to GE PSLF in 2001

134 Model Validation Using PMU Data (This is based on the methodology proposed by Dmitry Koserev and Steve Yang from BPA) Summary of steps in model validation: 1. Select a disturbance of significant magnitude 2. Extract the measured data from PI database for Voltage, Frequency, Active Power, and Reactive Power at the point of interconnection 3. Create a reduced Power flow and dynamic model for the machine as seen at Point of Interconnection 4. Using the playback feature of PSLF, simulate the dynamic behavior of the machine for the measured voltages and frequencies 5. Compare the measured values of active and reactive power at the Point of Interconnection with the simulation results

135 Chief Joseph Brake Resistor The Bonneville Power Administration has designed, constructed, and tested a 1400 MW resistor brake at the BPA Chief Joseph Substation in north central Washington. The resistor is designed to dissipate 1400 MW of power when energized at 240 kv and is capable of withstanding a three second application between cooling periods. If applied for three seconds, the power output will decrease to 1000 MW as a result of temperature rise in the conductor.

136 Picture of Chief Joseph Break Brake Resistor (Courtesy of BPA)

137 Simplified One-Line for Chief Joseph Braking Resistor

138 Operating Conditions Required for CHJ Brake Tests Operating Conditions for Chief Joseph brake insertion test: Power system operation is normal and system is within SOL BPA oscillation Detection Application shows no Oscillations If BC-Alberta in service, North-South Mode A is above 9% If BC-Alberta is out of service, North-South Mode B is above 5% Chief Joseph 500/230 kv transformer is in service Keeler 230 kv Static Var Compensator is in service 16

139 Chief Joseph Brake Tests These tests are continuation of system tests conducted in the period of The tests are planned for: During early spring with high wind generation online During hydro-generation run-off in early summer During early fall with low hydro and predominant thermal generation. The last test was performed on 9/17/2015 at 3:24:00 pm

140 Model Validation Using PMU Measurements from CHJ Brake Test Plot MS23023.Freq /17/2015 3:00:00 PM minutes 9/17/2015 4:00:00 PM Fig. 11 Chief Joseph Brake Tests as seen at Mission 230 kv Two afternoon tests at 3:14:00 and 3:24:00 pm (PT)

141 Chief Joseph Brake Tests Example 1 The combustion turbine of a combined cycle plant (162 MW) POI 230 kv Network CT1 Fig. 12 Setup for Example 1

142 Model Validation Example 1: The combustion turbine of a combined cycle plant (162 MW) Fig. 11 Actual PMU measurements of voltage and frequency (at the terminal of CT1)

143 Model Validation Example 1: The combustion turbine of a combined cycle plant (162 MW) Fig 12 Comparison of P-actual and P-simulated for CT1 (very good match)

144 Model Validation Example 1: The combustion turbine of a combined cycle plant (162 MW) Fig 13 Comparison of Q-actual and Q-simulated for CT1 (reasonably a good match)

145 Chief Joseph Brake Tests Example 2 Wind Turbine plant (265 MW) POI 500 kv Network G1 G2 Fig. 14 Setup for Example 2

146 Model Validation Example 2: Wind Turbine plant (265 MW) Fig. 15 Actual PMU measurements of voltage and frequency at the POI of wind turbine plant)

147 Model Validation Example 2: The Wind Turbine plant (265 MW) Fig. 16 Comparison of P-actual and P-simulated for WT (The difference may be due to wind pick-up)

148 Model Validation Example 2: The Wind Turbine plant (265 MW) Fig. 17 Comparison of Q-actual and Q-simulated for WT (reasonably a good match for reactive power response but not magnitudes)

149 Chief Joseph Brake Tests Example 3 Two Solar PV plant (Total of 146 MW) POI 230 kv Network G1 G2 Fig. 18 Setup for Example 3

150 Model Validation Example 3: Two Solar PV plants (Total of 146 MW) Fig. 18 Actual PMU measurements of voltage and frequency at the POI of the two solar PV plants

151 Model Validation Example 3: Two Solar PV plants (Total of 146 MW) Fig. 19 Comparison of P-actual and P-simulated for PV (good match)

152 Model Validation Example 3: Two Solar PV plants (Total of 146 MW) Fig. 20 Comparison of Q-actual and Q-simulated for PV (Model needs tuning!)

153 Conclusions Important to have PMU measurements at the terminal of the dynamic units (conventional generators, wind turbine, solar PV, synchronous condensers, SVC, HVDC Converters, etc.) Important to know the right settings for the controllers (e.g., voltage, reactive, or power factor control.) Important to have tools to identify model parameters based on the PMU measurements during actual or planned disturbances.

154 Thank You!

155 Online Transient Security Assessment (TSA) Bilgehan Donmez NERC SMS MEETING SAN DIEGO, NOVEMBER 4, 2015

156 Outline Background Online TSAT implementation at ISO-NE Application examples Challenges Conclusions 2

157 Background ISO New England 28,130 MW all-time summer peak demand set on August 2, ,818 MW all-time winter peak demand set on January 15, ,500 miles of high-voltage transmission lines (115 kv and above) 13 transmission interconnections to power systems in New York and Eastern Canada 14% of region s energy needs met by imports in 2013 $6.6 billion invested to strengthen transmission system reliability since 2002; $4.3 billion planned Over 150 transmission stability operating guides / limits New York Hydro Québec New Brunswick 3

158 Background online TSAT project Online Transient Security Assessment (TSA) The powerflow case comes from EMS snapshot Enables real-time transient stability evaluation Real-time model for online TSA at ISO-NE New England real-time network model is based on State Estimation solution The equivalent models (both static and dynamic) represent remaining Eastern Interconnection Dynamic models are taken from the a more detailed PSS/E planning case A number of 345 kv faults are monitored Monitors using same stability criteria that operation engineers use in running PSS/E off-line studies 4

159 PowerTech Lab s Transient Security Assessment Tool (TSAT) solution Why TSAT? Efficient simulation engine Approx. 50% of the execution time using PSS/E for the same planning case Parallel computation Support multi-core and multi machine (with DSA Manager as job scheduler), suitable for on-line implementation Automated interface limits calculation using user-defined stressing patterns and criteria (e.g., transient voltage sag, damping, loss of synchronism, etc.) 5

160 Overview of online TSA at ISO-NE Updated in real time EMS Snapshot Fixed data (updated periodically) Auxiliary files (e.g., interface file, contigency file, transfer file, etc.) Fixed data (updated periodically) Generator mapping table Network model in planning case Data Preparation Tool (DPT) DSA Manager Dynamic data in planning case Dynamic equivalent for external area Updated in real time (optional) TSAT Server 1 TSAT Server 2 TSAT Server n System components Data Preparation Tool (DPT) interfaces with EMS merges external equivalent model prepares dynamic models consistent with detailed case DSA Manager scenario setup job scheduler results display TSAT Servers execute TSAT processes (multi-core support available) 6

161 Overview of online TSA at ISO-NE (Cont d) Power flow modification Append the same detailed substation network model as in the planning case into EMS case EMS case Planning case HVDC links: In the EMS model, HVDC links are represented as dummy generators connected to the AC terminal of HVDC converters. The HVDC dynamic models are taken from the detailed case 7

162 Overview of online TSA at ISO-NE (cont d) Merge dynamic equivalent with EMS case Objective: Adjust the generators in the equivalent network to match the boundary conditions with the EMS case. EMS model P, i Q i G Bus i i V θ i i Boundary equivalent units G i Bus i V θ G k G Bus k k Bus k Bus k and k will be merged P i ', Qi' i' i' Equivalent model for external area Matched boundary condition: i', Qi = Qi ', Vi = Vi', θ i = θi' Optimization: 1. P i and V i for generator G i are set the same as their counterpart G i in the EMS case; 2. Generation in external area are dispatched to match boundary angles; Virtual phase shifter are added to compensate the extra phase angle difference at the boundary buses; Virtual shunts are added at the boundary buses to compensate unmatched MVar flows over tie lines. P i = P 8

163 Overview of online TSA at ISO-NE (cont d) In-house developed Data Preparation Tool (DPT) Read in EMS case for user-specified time interval Functions: adjust dynamic equivalents and merge them with EMS model create power flow modification script based on static generator mapping table build dynamic data file per equipment naming convention Outputs: merged power flow network model node-bus mapping file interface file dynamic data file derived from planning case (off-line mode only) power flow modification script file (off-line mode only) 9

164 Application Example 1 Model Validation Verification of a power plant model based on an event Event summary: a fault occurred at one of the 345kV circuits connecting the plant. High speed line tripping in 4 cycles followed by the automatic reclosing in 10.5s Good match of oscillations between the TSAT simulations and PMU data, validating the accuracy of online TSAT models MW flow in the remaining in service 345kV line MW output from the nuclear unit 10

165 Application Example 1 Model Validation (Cont d) HVDC response to a fault in the transmission system Event summary: blocking of one pole of HVDC due to the fault followed by the blocking of the second pole after 1.7s. Good match of the system dynamic behaviors (line MW flow and system frequency responses) between the TSAT simulations and PMU data, validating the accuracy of online TSAT models MW flow in the 345kV line connected to the HVDC terminal Frequency at a major 345kV bus 11

166 Application Example 2 Event Analysis Sensitivity to the SVC device Generator Rotor Angle (deg) Generator Rotor Angle (deg) Simulated criteria contingencies to verify the system response with the SVC device in and out-of-service Confirmed the impact of the SVC device on transfer limits. Transfers need to be curtailed to avoid instability when SVC becomes unavailable Time (sec) SVC in service (stable) Time (sec) SVC out-of-service (instable) 12

167 Application Example 2 Event Analysis (Cont d) IROL violation studies Investigate exceedances of the stability limits Simulations can be performed with TSAT for the exceedance instances to determine the IROL impact No need to manually adjust a load flow case to match the system conditions during the exceedance The archived online TSAT case is readily available for transient stability testing 13

168 Application Example 2 Event Analysis (Cont d) Correlation with PMU measurement Event summary: over tripping of two lines left the plant generating 2100 MW connected only to a single 345 kv line. The power swing triggered the protection of the third line and eventually isolated the plant. TSAT case 2 minutes prior to this event used for analysis TSAT simulations showed good match with PMU data 14

169 Application Example 3 Offline Study Short term outage planning Objective: calculate the generator output limit based on the planned transmission outages Tools: automated limit calculation in TSAT were benchmarked against the PSS/E simulations Screenshot of automated transfer limit calculation Bus voltage responses at the insecure cases (transient voltage sag) 15

170 Application Example 4 Online analysis Continuous online transient security assessment Online stability analysis is running in test mode 24x7 at 30-minute intervals on a server consisting of 4 cores Monitoring critical New England stability constrained interfaces Benchmark the operational limit developed in the off line studies All cases and results are archived Summary page of transient stability assessment Screenshot of transfer limit output from online TSA 16

171 Challenges Benchmark entire dynamic stability model against existing standards The stability model used in TSAT comes from PSS/E case originating from MMWG. The correctness of each model has to be benchmarked (injection method). In addition, many user written models (black box models) are not currently available in TSAT. Maintaining the updates to the dynamic stability model Anytime PSS/E dynamic models are updated, these changes will need to be reflected to the TSAT models, which requires additional effort/staff within the organization. If this is to be a tool supporting operations and real time, it requires the same level of support as our other real time tools. Building confidence among operational staff Acceptance of a new tool in operation requires very thorough and lengthy review, as well as tool / data / output validation. Users will have to build total confidence in the models and output before it is relied upon. 17

172 Conclusions TSAT simulations based on the EMS snapshots offer the closest match to the realtime conditions with minimal staff effort. The use of online TSAT model for off-line studies is valuable, where correlation with the real time conditions is critical (event re-creation, model validation). User friendliness and many unique features (automated limit calculation, model building, setting criteria) make TSAT an attractive off-line study tool. The online TSAT results are monitored, benchmarked and analyzed to build confidence with the tool. The successful implementation of online TSAT depends on: Resources and procedures to maintain TSAT dynamics database / model Development of proprietary non-standard models in TSAT (i.e., wind) and model validation based on actual events 18

173 19

174 Power Plant Model Validation: BPA Experience NERC SMS November, 2015 Steve Yang Bonneville Power Administration

175 Power Plant Model Validation BPA has been installing PMUs at power plant POIs since 1996 BPA developed Power Plant Model Validation (PPMV) application using PMU data and GE PSLF play-in function (Added in 2001) BPA requires PMU installation for all new generation including the wind Substation Power Plant Point of Interconnection V I G Record: - POI bus voltage - POI bus frequency - Power plant MWs and MVARs G PMU needs to be placed at Power Plant POI

176 BPA s PPMV PMU Coverage BPA s PMU disturbance monitoring: Conventional 12 plants, 130 generators, 21,145 MW of generation Wind 11 plants 1,200 MW of generation More to be added

177 PPMV Tools BPA PPMV Sequence of GE PSF EPCLs and MATLAB programs BPA-PNNL PPMV Stand-alone data management program and automated PSLF interfaces Idaho Power Excel macro with PI data link and PSLF interfaces EPRI PPPD Stand-alone MATLAB based software

178 BPA PPMV Process Get disturbance PMU data Convert PDAT (binary files) to CSV files (BPA PDATViewer and ConvertPDAT) MODEL Voltage and Frequency Power Plant Controllable Voltage and Frequency MWs and MVARs G G Measured and responded MWs and MVARs are compared for measures of success 5

179 PPMV Results Good Models What a good models looks like: Blue line = actual recording Red line = model Voltage and frequency are inputs Active and reactive power are measures of success

180 PPMV Results Bad Results What a bad model looks like: Blue line = actual recording Red line = model Voltage and frequency are inputs Active and reactive power are measures of un-success

181 When the model is BAD!

182 Data Check Review data Make sure the model represent actual equipment Run Error-Check EPCL Obtain and review test report Most common model issues: Power System Stabilizer models Turbine control mode of operation / governor models Generator inertia Simple sensitivity studies

183 Repeat Baseline Test Easy Hard

184 After Re-test Using BPA-PNNL PPMV 2.0 MOD-027 MOD-026

185 Before calibration Calibration After calibration PPMV can complement model development and calibration, there are successful case studies. However, engineering expertise and knowledge of generator controls are essential Beware of curve fitting exercises

186 Calibration EPRI Power Plant Parameter Derivation (PPPD) is most mature, a user group is established including 23 participants Bernie University of Wisconsin uses a unique approach of pattern matching which is useful to provide insight in model inaccuracies Others: MATLAB University of Texas Particle Swarm Optimization PNNL Kalman filter Georgia Tech super-calibrator Idaho Power developed in-house optimizers

187 Going Beyond the Standards

188 Verification of Consultant s Report Power (MW) Active Power The same power plant tested by two different consultants Power (MW) Reactive Power Time (sec) Consultant A Consultant B Which data is correct? You do not know unless you have an independent way of verifying

189 Power (MW) Verification of Consultant s Report Active Power Consultant A Power (MW) Reactive Power Consultant B Reality(PMU) Time (sec) Turned out neither consultant was right BPA experience suggests that 60 to 70% of models did not match disturbance recordings even after the baseline test was performed

190 Active Power [MW] Performance Monitoring and Detection of Control Failures PMU monitoring provides detection of generator abnormalities Power PSS failure Observed Expected Time (sec) Active Power [MW] Unexpected action from plant controller Power Observed Expected Reactive Power (MVAR) 0-50 Abnormal runback in reactive power Time (sec) Time (sec) 17

191 Summary BPA PPMV Maturity: 8/10 Users: transmission planners, generator owners in use at BPA in various forms since 2000, programmatic since 2009 Currently works only with GE PSLF PSS E and PowerWorld have the same capabilities PPMV Application has been used for: acceptable method for GOs to comply with NERC MOD-026 & 027 and WECC policy used by TPs to independently verify that the models provided by GOs are valid determination of power plant operating practices detection of generator control failures Wind model validation Allows more frequent model validation- better than once every 10 years (NERC) or 5 years (WECC)

192 Industry Outreach Promoting PPMV to other utilities since 2008 (very slow process but it s starting to pickup) PG&E recently completed validation using BPA- PNNL PPMV Tool inspired by BPA-PNNL PPMV Ron Markham PG&E San Diego Gas & Electric just started using the tool Others are very interested but

193 Next Steps WECC MVWG PPMVDTF User s Group First meeting in November 18 th in SLC BPA TI projects: TIP: Power Plant Dynamic Performance Center TIP: Development and Demonstration of a Phasor- Driven Tool for Adaptive Stability Model Calibration Using GE PSLF Review model performance periodically (system events) PNNL PPMV 2.0 tool enhancements

194 Publications DOE Report on Model Validation CIGRE Tutorial CIGRE Paper IEEE Magazine paper ERCOT Technical Conference NASPI Meetings 21

195 Thank You! Contact information: Steve Yang

196 NASPI Update Alison Silverstein NASPI Project Manager NERC SMS meeting, November

197 Current priorities for NASPI Document what we ve learned from the SGIG-SGDP projects, including the value of synchrophasor technology Mainstream synchrophasor technology, making it easier for entities to adopt or improve synchrophasor projects with lessons learned from SGIG-SGDP projects Facilitate control room use of synchrophasor-based tools Prepare for the next generation of synchrophasor technology adoption, including Data quality Expand data sharing among entities and with researchers Cyber-security Network design Next generation of applications Update and expand technical and reliability standards 2

198 NASPI October meeting Recognize NASPI MVP Volunteers of the Year for 2015 Roll-out of the Synchrophasor Value Proposition Identifies the benefits and metrics of value for synchrophasor technology and how to do the math to quantify those; see the study and the ppt Roll-out of the draft Synchrophasor Starter Kit First pass at documenting all the practical things we ve learned about synchrophasor technology in a concise package; see here and several presentations up on NASPI website for the GOTF tutorial and the 10/14/15 technical session EATT Power System Protection Survey paper DC area low voltage disturbance event analysis Many synchrophasor user success stories 3

199 Upcoming NASPI work PMU application requirements for PMU data quality, errors & availability initial report here, draft white paper out soon Cyber-security best practices for synchrophasor systems (spring 2016) NASPInet 2.0 Assess existing networks (spring 2016) Design and management for new networks (fall 2016) CRSTT technical papers Islanding & Blackstart paper and Voltage Stability and Phase Angle Monitoring papers are complete and on NASPI website Continue work on Synchrophasor Starter Kit feedback welcome Next meeting -- March 2016 International synchrophasor symposium, co-sponsored by IEA ISGAN T&D Annex 6, US-DOE, EPRI & CIGRE Tighter coordination with WECC JSIS and NERC SMS 4

200 The Value Proposition for Synchrophasor Technology: Itemizing and Calculating the Benefits From Synchrophasor Technology Alison Silverstein, Dr. Mark Weimar, Joseph Petersen PNNL

201 Synchrophasor Benefits Framework Approach to the framework Classes of benefits Quantify metrics and benefits Show examples and calculations Reliability & resiliency benefits Cost savings and efficiency benefit Grid throughput and efficiency benefits Environmental and policy benefits Scaling from annual to longer cycle benefits New NASPI Technical Report on the Synchrophasor Value Proposition at 6

202 Approach to framework Benefits occur from multiple applications in combination, not one-by-one Risk of double-counting benefits Active use of synchrophasor data required for benefits to be realized Some benefits may be hard to quantify Following diagram illuminates the approach 7

203 8

204 Reliability and resiliency metrics and benefits Fundamental benefits about reducing the odds and consequences of outages, so look at how synchrophasor technology affects: Number of major and minor outages that occur Number of customers affected Duration of those outages Customers financial value of the outages Two approaches Estimating impact of each component Using relationship of transmission to distribution outages to calculate impact

205 Reliability and resiliency benefits (cont d) Benefits will be area-specific Probability, causes and lengths of outages in each area without synchrophasor technology use Numbers and types of customers How could your uses of synchrophasor technology affect the occurrence and duration of outages?

206 How synchrophasor technology could enhance reliability and resiliency Better wide-area situational awareness and applications to prevent outages and cascading failures Fewer equipment failures Faster service restoration Faster line reclosing Faster generator synchronization Faster black-start restoration Faster island resynchronization Faster forensic analysis and lessons learned implementation Back-up network and data source for SCADA failure

207 NERC Reliability standards using synchrophasors Synchrophasor technology can be used to improve performance and establish compliance with at least seven NERC reliability standards Standard Title Status Number BAL Frequency Response and Frequency Bias Setting Subject to Enforcement FAC Facility Interconnection Requirements Subject to Enforcement IRO Reliability Coordination Wide-Area View Subject to Enforcement MOD Verification of Models and Data for Generator Excitation Subject to Enforcement Control System or Plant Volt/Var Control Functions MOD Verification of Models and Data for Turbine/Governor and Subject to Enforcement Load Control or Active Power/Frequency Control Functions MOD Steady-State and Dynamic System Model Validation Subject to Enforcement PRC Disturbance Monitoring and Reporting Requirements Approved, pending enforcement Source: Information provided by Ryan Quint, NERC, September

208 Cost savings and efficiency metrics Less transmission congestion (MWh and $ value) Labor cost reductions (time and $) Forensic analysis Model validation Fault location Detecting equipment failure before catastrophic failure Equipment commissioning Capital deferral and avoidance savings Standards compliance 13

209 Grid efficiency and throughput benefits Congestion management These are hard to quantify: Better voltage and reactive power management Line loss reduction 14

210 Environmental and policy benefits Increased delivery and use of renewable generation From better power plant models, voltage stability, oscillation monitoring, state estimation, congestion management, dynamic line ratings, automatic operation of transmission assets, etc. Valuing incremental renewable generation Identify an incremental percentage of renewable generation enabled by synchrophasor technology Fossil fuel offset by renewables Emissions reduction offset by renewables 15

211 Aggregating benefits over time Factors affecting the calculation of project benefits Operational impacts significant in early years, level out as technology matures Benefits from transmission-level synchrophasors may decrease with more customer-level energy efficiency, DG and storage Create a baseline without synchrophasor technology and compare to the alternative with synchrophasors Net present value for time stream of financial benefits; sum up or discount non-monetary benefits 16

212 Conclusions Benefits from synchrophasor technology arise from actively using combinations of applications Identified benefits and where possible estimated values for: Resiliency and reliability (outage #, duration, customers affected, value of customer service) Cost savings (time and $) Grid efficiency and throughput (MWh, energy cost) Environmental (mostly renewable) impacts (MWh, emissions Provided methodology to quantify and estimate project benefits 17

213 Find The Value Proposition for Synchrophasor Technology: Itemizing and Calculating the Benefits from Synchrophasor Technology Use is on the NASPI website at: 18

214 For more information Project manager Alison Silverstein NASPI website Join the naspi listserv: 19

215 SYNCHROPHASOR MEASUREMENT CERTIFICATION PROCESS Ken Martin Principal engineer Electric Power Group NERC SMS Meeting November 3-5, 2015 San Diego, CA Electric Power Group

216 Introduction Relevant standards Process for assessing compliance Certification Roadblocks Next steps Electric Power Group 1

217 Phasor Measurement System Display standards GPS Communication standards Phasor Data Concentrator Real Time Monitoring & Alarming Future real-time controls: Substation PDC Measurement standards Data storage standards Data Storage Off-line Dynamics Analysis Other utility PDC Electric Power Group 2

218 Synchrophasor standards/guides C : Measurements Performance for phasor, frequency, & ROCOF IEC/IEEE : Measurements (next version under development) C : Communication Messaging & adaptation to communication medium IEC : Communication Complete communication system (IEC 61850) C37.111/IEC : COMTRADE Data file format with profile for synchrophasor data C : Testing & supporting systems Guide to PMU testing & system calibration & timing C & PC37.247: PDC Published Guide & developing standard for PDC Electric Power Group

219 Terminology Assessment Determine capability, features, and performance Compliance Assure that device or application has features and performs according to statements & requirements Conformance Assure that device or application has features and performs according to given requirements (similar to above) Certification Assure that investigation and testing have determined that the device or application conforms with given requirements (standards) Interoperability Assure that one or more devices will operate together as expected Electric Power Group 4

220 Observations on Standardization Most products are assessed for compliance with standards or user specified requirements Conformance usually describes compliance with certain standardized requirements Certification usually is done by an independent party that assesses whether the test or investigation followed appropriate rules so the process is valid and that the results indicate compliance with the given set of requirements or standards Interoperability means that devices operate together as expected. Compliance with standards does not mean devices will interoperate. Devices will interoperate only as well as the standards developers have anticipated the features and interactions that are required for interoperation Electric Power Group 5

221 Compliance concerns Most vendors claim standards compliance Some products/systems are tested, some are not Vendor & test labs may have different interpretations of standards requirements Certification moves authority to 3 rd party Independent & unbiased Certifying authority Can be any organization Needs credibility for recognition Needs to develop transparent processes, standardized test plans, clear evaluation criteria Electric Power Group 6

222 Electric Power Group Certification Process Standards Development Organization (SDO) develops standard Test laboratory (may be pre-qualified by the certifying body) Vendor International Standard Test procedure development (if needed) Perform test according to published methods (either from standard or accepted interpretation of Standard) Examine test results assess if DUT meets requirements Vendor product Certifying Body Grant Certification

223 Certification to C PMU Certification Includes synchrophasor, frequency, & ROCOF measurement Does not include data communication IEEE Conformance Assessment Program (ICAP) IEEE is Certifying body Developed Test Suite Specification (TSS) Open development process Unambiguous testing based on standard Qualifies test laboratories Consumers Energy Laboratory certified at this time Electric Power Group November 9, 2010

224 Users Certification benefits Assured measurement performance & accuracy Compatibility with other vendor products Utilities can choose different vendors & data is comparable Vendors Clear requirements to achieve for development Qualifies sales to most companies Same requirements throughout the world Products can be listed by certifying authority Electric Power Group November 9, 2010

225 Certification roadblocks Process is very expensive Tests are extensive and exacting Require expensive test instruments Vendors may not expect enough sales to justify Each model & firmware change requires certification Most utilities do not require certified products New standard, , addresses some issues Reduces requirements Certify only at specified reporting rates (up to 6:1 reduction) No environmental tests (drop temperature tests) Improved definitions & better clarity Electric Power Group November 9, 2010

226 Summary Current problems with consistent measurement include: PMUs do not meet Standards PMUs validated to different requirements interpretation Some kind of performance validation essential Certification an important step forward How to encourage validation & certification? Develop simpler/less expensive validation? NERC requirements for deployment? Posting on NERC site? How? Electric Power Group 11

227 Electric Power Group THANK YOU. 201 South Lake Avenue, Ste 400 Pasadena, CA

228 Transient Stability Play-In Signals with PowerWorld Simulator Adapted from Training Slides Nov. 4, 2015 Presentation for NERC SMS Meeting 2001 South First Street Champaign, Illinois (217)

229 Play-In Signals Simulator supports user-configurable timeseries blocks as inputs to the transient stability simulation These models are called Play-In Signals Play-In Signals encapsulate custom time series fields which can be analyzed and plotted like any other signal in Simulator Any number of play-in signals can be defined T13: Play-In Signals and Scripts 2014 PowerWorld Corporation 2

230 Two Purposes of Play-In Signals Define a signal for plotting purposes Just another signal to put on a plot for comparison purposes only A way to load and view data independently Play-in of model data Add Machine model: play-in a bus voltage and frequency Add Exciter model: play-in field voltage Add Governor model: play-in mechanical power Add an auxiliary other machine model for governor reference (P ref ) or exciter reference (V ref ) T13: Play-In Signals and Scripts 2014 PowerWorld Corporation 3

231 Play-In Model Structure Three new data objects PlayIn a named structure that contains the other two objects Name, Time offset PlayinInfo a list of information about the signals contained in one PlayIn structure Name, Scale, Offset, Filter Time, Signal Index PlayinSignal a time-series list of numerical data for one PlayIn structure Time, List of values for this time T13: Play-In Signals and Scripts 2014 PowerWorld Corporation 4

232 Graphical Representation of Play-In Structures PlayIn Structure #1 Name : String Time Offset : float PlayIn Structure #2 Name : String Time Offset : float PlayInInfo List PlayInSignal List PlayInInfo List PlayInSignal List (0) Voltage Time(0), x0(0), x1(0), x2(0) (0) Efield Time(0), x0(0), x1(0), x2(0) (1) Frequency Time(1), x0(1), x1(1), x2(1) (1) PMech Time(1), x0(1), x1(1), x2(1) (2) Other Time(2), x0(2), x1(2), x2(2) (2) Other Time(2), x0(2), x1(2), x2(2) Time(3), x0(3), x1(3), x2(3) Time(3), x0(3), x1(3), x2(3) Time(N), x0(n), x1(n), x2(n) Time(N), x0(n), x1(n), x2(n) 3 PlayIn Info objects 3 values for each PlayInSignal T13: Play-In Signals and Scripts 2014 PowerWorld Corporation 5

233 Fitting a Play-In Signal to Simulation PlayIn structure Time Offset : shifts signal in time axis to match simulation PlayInInfo Offset : shifts the signal in y-axis Scale : multiplies the signal Filter Time : runs the signal through an additional [1/(1+Ts)] delay block during the simulation General note about time All signals in a PlayIn structure use the same time axis For all signals, a value must be specified at every time Use multiple PlayIn structures if your signals do not have the same time points T13: Play-In Signals and Scripts 2014 PowerWorld Corporation 6

234 Play-In Example Open TS9Bus Bus Fault PlayIn Setup.pwb This case contains a PlayIn object which is not yet linked to anything in the Simulation Open the PlayIn Configuration tab on the Model Explorer T13: Play-In Signals and Scripts 2014 PowerWorld Corporation 7

235 Play-In Configuration Use this tab to specify new PlayIn objects Name Time Offset Signal Count, Names T13: Play-In Signals and Scripts 2014 PowerWorld Corporation 8

236 Pieces of a Play-In: Signal Info, Signals Each PlayIn object contains Signal Info specifications The signals themselves T13: Play-In Signals and Scripts 2014 PowerWorld Corporation This PlayIn contains two signals listed by signal index 9

237 Play-In Specification as an AUX File T13: Play-In Signals and Scripts 2014 PowerWorld Corporation 10

238 Dynamic Models PLAYINGEN: Machine model play-in a bus voltage and frequency PLAYINEX : Exciter model play-in field voltage PLAYINGOV: Governor model play-in mechanical power PLAYINREF: Other generator model play-in governor reference (Pref) play-in exciter reference (Vref) T13: Play-In Signals and Scripts 2014 PowerWorld Corporation 11

239 Example: GOVPLAYIN Add a new governor model PLAYINGOV Specify which PlayIn object to use Specify the signal index to refer to T13: Play-In Signals and Scripts 2014 PowerWorld Corporation 12

240 Example Simulation Load playinmechpowerplot.aux Top curves show the played in mechanical power T13: Play-In Signals and Scripts 2014 PowerWorld Corporation 13

241 Play-In for Plotting Directly plot a play-in signal on a plot T13: Play-In Signals and Scripts 2014 PowerWorld Corporation 14

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244 PLAY BACK MODELS IN GE PSLF AND ITS APPLICATIONS NERC SMS Meeting, San Diego, 2015 Brian Thomas Commercial Software Manager GE Energy Consulting GE Energy Consulting 2015 General Electric Company. Proprietary. All Rights Reserved.

245 History of play back models in PSLF First generation of play back model introduced in 2001 by Dr. John Undrill in PSLF for power plant testing and validation Second generation of play back models introduced in early 2010 by Dr. John Undrill in PSLF 2015 General Electric Company. Proprietary. All Rights Reserved. 2

246 Type of play back signals in PSLF Voltage and Frequency at a bus or as internal voltage Generator field voltage Turbine mechanical power Voltage regulator reference setting for excitation systems Governor reference setting for turbine controls. Turbine Pm ref Generator Excitation System E fd V int F req Power System Governor V V ref 2015 General Electric Company. Proprietary. All Rights Reserved. 3

247 First generation of play back model in PSLF (2001) GENCLS Play in signals Voltage Frequency Compare other recorded signals MW MVAR 2015 General Electric Company. Proprietary. All Rights Reserved. 4

248 First generation of play back model in PSLF (2001) GENCLS Bias for input play back signals Low pass filter Input can be CSV or TEXT file Extensively used by various users for power plant model validation (maxsamples) (time_sample0), (voltage_ sample0), (frequency_ sample0), a2_ sample0, a3_ sample0, a4_ sample0 (time_sample1), (voltage_ sample1), (frequency_ sample1), a2_ sample1, a3_ sample1, a4_ sample1.... end 2015 General Electric Company. Proprietary. All Rights Reserved. 5

249 Second generation of play back models in PSLF (2010) Play in signals Voltage (V int ) Frequency (F req ) Field voltage (E fd ) Turbine mechanical power (P m ) Voltage regulator reference setting for excitation systems (V ref ) Governor reference setting for turbine controls (ω ref ) Turbine Pm ref Generator Excitation System E fd V int F req Power System Governor V V ref 2015 General Electric Company. Proprietary. All Rights Reserved. 6

250 Second generation of play back models in PSLF (2010) Source of data PMU DFR Others Input format for PSLF CSV file TEXT file Each channel Scaling Offset Time delay 2015 General Electric Company. Proprietary. All Rights Reserved. 7

251 Second generation of play back models in PSLF (2010) 2015 General Electric Company. Proprietary. All Rights Reserved. 8

252 Second generation of play back models in PSLF (2010) GTHEV dynamic model which can be used to play in voltage amplitude and frequency. PLEFD dynamic model which can be used to play in generator field voltage. PLTP dynamic model which can be used to play in turbine power. PLREF dynamic model which can be used to play in voltage regulator and/or governor reference settings. NOTE : To play in the measured data in any of the play back models, the user only needs to reference the play in channel. This is done by assigning the channel index General Electric Company. Proprietary. All Rights Reserved. 9

253 Automation of play back simulation in PSLF Native scripting language of PSLF (EPCL) makes it possible to automate the entire play back simulation in PSLF The figure on the right shows an entire play back simulation automated via EPCL script 2015 General Electric Company. Proprietary. All Rights Reserved. 10

254 Some applications of PSLF play back models in the Industry Used for power plant model validation by the grid code testing team in GE Energy Consulting [5]. Used by EPRI to benchmark the 2 nd generation wind turbine models [6]. Used by GE Energy Consulting to validate the GE wind turbine model parameters. Used in the Power Plant Model Validation (PPMV) tool developed by PNNL and BPA [7]. Used in the Generator Model Validation developed by Idaho Power [8] General Electric Company. Proprietary. All Rights Reserved. 11

255 Example 1 Generator model validation by Grid Code Testing Group in GE Energy Consulting Actual system frequency event was played back to validate the turbine governor model 2015 General Electric Company. Proprietary. All Rights Reserved. 12

256 Example 2 Generator model validation by Grid Code Testing group in GE Energy Consulting Actual system frequency was played back on top of the ( staged test ) load reference step changes. The effect of actual speed changes can be seen, along with the effect of the unit s responses to the staged input changes General Electric Company. Proprietary. All Rights Reserved. 13

257 References [1] GE PSLF 19 program manual. [2] B. Yang, Z.Huang, D. Kosterev, Multi-terminal Subsystem Model Validation for Pacific DC Intertie, IEEE Power and Energy Society General Meeting, July [3] Z. Hyang, D. Kosterev, R. Guttromson, T. Nguyen, Model Validation with Hybrid Dynamic Simulation, IEEE Power Engineering Society General Meeting, June [4] Real-Time Application of Synchrophasors for Improving Reliability, NERC Report [5] Grid Code testing work performed by GE Energy Consulting, [6] Pouyan Pourbeik, Model Validation on Wind Turbine Generators using the 2 nd Generation Wind Turbine Generator Models, WECC Renewable Energy System Models Webcast, July [7] Dmitry Kosterev, Steve Yang, Pavel Etingov, PMU-based application for power plant model validation, North American SynchroPhasor Initiative Working Group Meeting, March, [8] Eric Bakie, Generator Model Validation Using PD Data using PSLF Play-In Function, WECC MVWG Workshop, Nov General Electric Company. Proprietary. All Rights Reserved. 14

258 Thank you! 2015 General Electric Company. Proprietary. All Rights Reserved.