Phase Angle Monitoring:
Industry Experience Following the
2011 Pacific Southwest Outage
Recommendation 27
Technical Reference Document
June 2016
NERC | Report Title | Report Date
I
Table of Contents
Acknowledgments ..................................................................................................................................................... iv
Preface ........................................................................................................................................................................ v
Executive Summary ................................................................................................................................................... vi
Recommendations.................................................................................................................................................... vii
Introduction ................................................................................................................................................................1
The Meaning of a Synchrophasor Phase Angle ......................................................................................................1
Fundamental Drivers for Phase Angle Differences .................................................................................................2
Fundamental Need for Synchrocheck Relay Thresholds ........................................................................................2
Southwest Outage Recommendation 27 ...................................................................................................................4
Overview of Outage and Angle Implications ..........................................................................................................4
2011 Southwest Outage Report Finding 27 ........................................................................................................5
2011 Southwest Outage Report Recommendation 27 .......................................................................................5
Phase Angle Difference Monitoring – Synchro-Check Awareness .............................................................................6
Integration with EMS Network Applications ..........................................................................................................6
Synchrophasor-Based Tools & Real-Time Awareness ......................................................................................... 11
Benchmarking PMU and SCADA Data .................................................................................................................. 12
Time Alignment ................................................................................................................................................ 13
Synchrophasor Data Validation Options .......................................................................................................... 13
Signal Mapping Guidelines ............................................................................................................................... 13
PMU Data Quality............................................................................................................................................. 14
EMS and PMU Data Quality Flags .................................................................................................................... 15
Benchmarking Calculations .............................................................................................................................. 15
Mitigation and Operating Procedures for Line Restoration ................................................................................ 19
Actions for Excessive Phase Angle Differences ................................................................................................ 19
Correlating Phase Angle with System Conditions ................................................................................................... 20
Phase Angle and Real Power Correlation ............................................................................................................ 20
Identification of Key (Optimal) Angle Differences................................................................................................... 25
Major Transmission Interfaces or Transfer Paths ................................................................................................ 25
WECC Intertie Paths ......................................................................................................................................... 25
Oscillatory Stability Analysis ................................................................................................................................ 26
Phase Angle Visualization of Operating Boundaries............................................................................................ 30
Voltage Stability and Phase Angle ....................................................................................................................... 30
Linking Phase Angles with System Studies .............................................................................................................. 32
NERC | Phase Angle Monitoring | June 2016
ii
Table of Contents
Definition of Safe & Alert Operating States ......................................................................................................... 32
Defining Inter-Area Stability Limits Based on Phase Angle ................................................................................. 32
References ............................................................................................................................................................... 35
Appendix A – Utility Practices ................................................................................................................................. 36
Peak Reliability Coordinator (Peak Reliability) .................................................................................................... 36
California ISO (CAISO) .......................................................................................................................................... 36
Arizona Public Service (APS) ................................................................................................................................ 36
Salt River Project (SRP) ........................................................................................................................................ 37
San Diego Gas & Electric (SDG&E) ....................................................................................................................... 37
NERC | Phase Angle Monitoring | June 2016
iii
Acknowledgments
The NERC Synchronized Measurement Subcommittee (SMS) gratefully acknowledges the invaluable assistance of
the following industry experts in the preparation of this technical reference paper:
•
Aftab Alam (California ISO)
•
Tony Faris (Bonneville Power Administration)
•
Hassan Ghoudjehbaklou (San Diego Gas & Electric)
•
Dmitry Kosterev (Bonneville Power Administration)
•
Naim Logic (Salt River Project)
•
Ken Martin (Electric Power Group)
•
Tariq Rahman (San Diego Gas & Electric)
•
Alison Silverstein (North American Synchrophasor Initiative)
•
Jeff Sundin (Arizona Public Service)
•
Dan Trudnowski (Montana Tech)
•
Marianna Vaiman (V&R Energy)
•
Hongming Zhang (Peak Reliability)
NERC | Phase Angle Monitoring | June 2016
iv
Preface
The North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory authority
whose mission is to assure the reliability of the bulk power system (BPS) in North America. NERC develops and
enforces Reliability Standards; annually assesses seasonal and long‐term reliability; monitors the BPS through
system awareness; and educates, trains, and certifies industry personnel. NERC’s area of responsibility spans the
continental United States, Canada, and the northern portion of Baja California, Mexico. NERC is the electric
reliability organization (ERO) for North America, subject to oversight by the Federal Energy Regulatory Commission
(FERC) and governmental authorities in Canada. NERC’s jurisdiction includes users, owners, and operators of the
BPS, which serves more than 334 million people.
The North American BPS is divided into eight Regional Entity (RE) boundaries, as shown in the map and
corresponding table below.
The Regional boundaries in this map are approximate. The highlighted area between SPP and SERC denotes overlap as some
load-serving entities participate in one Region while associated transmission owners/operators participate in another.
FRCC
Florida Reliability Coordinating Council
MRO
Midwest Reliability Organization
NPCC
Northeast Power Coordinating Council
RF
ReliabilityFirst
SERC
SERC Reliability Corporation
SPP-RE
Southwest Power Pool Regional Entity
TRE
Texas Reliability Entity
WECC
Western Electricity Coordinating Council
NERC | Phase Angle Monitoring | June 2016
v
Executive Summary
The purpose of this report is to provide an update on industry practices for phase angle difference monitoring and
limit determination, phase angle-related applications, and operating experience using innovative software tools.
Under direction of the FERC/NERC 2011 Pacific Southwest Outage Reporting Finding and Recommendation 27,
the paper reports on the current state of how system operators and operations engineers have expanded angle
monitoring capability. Findings, recommendations, and examples provided in this report are preliminary yet
specific to guide phase angle monitoring implementation strategies, work scopes, and technical solutions.
The report reaches the following conclusions and findings:
1. Transmission Operators and Reliability Coordinators are monitoring phase angle differences and
comparing those real-time angle differences to synchrocheck relay settings. This comparison is taking
place in the State Estimator (SE) and Real-Time Contingency Analysis (RTCA), as well as in advanced
supervisory applications.
2. PMU phase angle signals are being baselined and benchmarked against SCADA measurements and SE
solutions.
3. Phase angle is strongly correlated to active power transfer and system topology, and is analyzed across
WECC Paths in OSIsoft PI system. Continued efforts will focus on using phase angle difference as an
additional system stress indicator in conjunction with Path MW flow.
4. PMU phase angle differences are a useful quantity to monitoring immediately following an unplanned
and/or unstudied forced outage event. The real-time angle difference provides the system operator with
an immediate awareness of system strength and stress.
5. Static or dynamic Path Limits are conventionally based on MW flow. Using phase angle difference may be
an additional indicator that provides system operators with better awareness of system stress, particularly
for stressed outage conditions where MW flow changes minimally but phase angle increases due to Path
separation or other outages.
6. Wide area oscillation modes and angle separation correlation are presented. The oscillatory modes of the
Western Interconnection are well understood and correlating modal characteristics to phase angle
differences can provide additional situational awareness and engineering insights to stressed operating
conditions.
7. Baselining phase angle differences to determine ‘Normal’ or ‘Abnormal’ operating states is being explored
using data mining techniques. “Big data” analytics should be applied with engineering judgment and
integrated with historical data, operational experience, study results, and event validation analysis.
8. The phase angle monitoring practices of utilities in the Pacific Southwest are presented to provide a status
update approximately 5 years after the 2011 Pacific Southwest Outage.
NERC | Phase Angle Monitoring | June 2016
vi
Recommendations
The recommendations listed below are based on the assessment of phase angle monitoring, limit calculation, and
alarming techniques. While the report focuses on practices in the Western Interconnection following the Pacific
Southwest Outage, it was determined that these recommendations apply to all interconnections and entities
performing the respective functions. The concepts of phase angle monitoring and alarming using both SCADAbased and time synchronized measurements for improved situational awareness apply to any Bulk-Power System.
1. The contingency risk of interest is the outage of a transmission circuit and the phase angle difference
across the out-of-service terminals of that line exceeding synchrocheck relay limits. Post-contingency
angle differences should be monitored in real-time. The Planning Coordinator and/or Reliability
Coordinator should identify key transmission circuits for which this monitoring is required. It is
recommended that awareness of synchrocheck relay limit exceedances be provided to system operators
for EHV transmission circuits, where applicable, with nominal voltage greater than or equal to 345 kV.
2. Phase angle differences for potential contingency conditions should be monitored in real-time and
compared against synchrocheck relay settings, if applicable, for all EHV transmission circuits using RealTime Contingency Analysis (RTCA) tools. Any N-1 or credible N-2 or N-1-1 exceedances of these limits
should be provided to the system operator for advanced notice of potential line restoration issues.
3. Wide-area phase angle difference monitoring provides an additional layer of situational awareness for
system operators, and wide-area limits based on known risks such as transient stability, voltage stability,
small signal stability, or overloads can effectively be developed based on operations studies or advanced
online applications. Utilities should consider extracting phase angle difference values during system
studies for stability risks, in conjunction with conventional MW flow limits.
4. Line-based phase angle difference monitoring and comparison against known synchrocheck limits is not
presently a universally adopted operating practice. It is recommended that the NERC Synchronized
Measurement Subcommittee (SMS), in coordination with the NERC Operating Committee (OC), explore
how this practice could be used or more widely adopted by the industry.
5. In the Western Interconnection, phase angle difference is correlated to oscillatory stability issues
particularly during high transfer conditions. Tools such as Mode Meter, Oscillation Detection, and Phase
Angle Difference (PAD) tools provide advanced analytical capabilities to detect any oscillatory issues linked
with phase angle stress. It is recommended that utilities continue pursuing advancements in these tools
for further situational awareness.
NERC | Phase Angle Monitoring | June 2016
vii
Introduction
The importance of monitoring phase angle differences has been highlighted in the report for the causes and
recommendations of the August 2003 Northeast Blackout and the September 2011 Pacific Southwest Outage.
Specifically, the August 2003 Northeast Blackout report states that operators in several of the events leading to
the blackout were unaware of the vulnerability of the system to the next contingency, in part because they had
insufficient situational awareness and no operator monitoring of stability measures like power transfer angle. The
report on the 2003 blackout recommended that the industry “review phase-angle restrictions that can prevent
reclosing of major interconnections during system emergencies” [1]. The 2011 Pacific Southwest Outage report
highlighted the lack of tools at the time to determine the phase angle difference between the two terminals of a
line after the line tripped, and recommended that grid operators 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.” It also recommended that operators should be trained to effectively respond to phase
angle differences [2].
Synchrophasor technology improves the capability of grid operators and operations engineers to visualize and
monitor a wide-area view of the bulk power system. Phasor Measurements Units (PMUs) provide direct
measurement of system voltage and current phasors (magnitude and phase angle) and frequency. This timesynchronized data can be used for early detection of system disturbances, assessing and maintaining stability
following a major event, and alarming system operators to view precise real-time data within seconds of a system
event.
The phase angle difference between buses’ voltage phasors, as measured by PMUs on the bulk power system, is
an indication of system stress and stability. An angle difference within a predetermined limit is acceptable but
needs to be monitored closely for early warnings. An increasing phase angle difference can be a serious problem
when the deviation gets large enough to cause instability either pre- or post-contingency. This report identifies
industry practices for utilizing synchronized phase angles and phase angle differences for monitoring system stress
and providing situational awareness to grid operators.
The Meaning of a Synchrophasor Phase Angle
A Phasor Measurement Unit (PMU) measures voltage and current signals and estimates a time-synchronized
phasor representation (magnitude and phase angle) of these electrical quantities. These voltage and current
phasors are referred to as synchrophasors. The synchrophasor phase angle is defined as:
A PMU estimates synchrophasor phase angle based on the nominal system frequency
synchronized to UTC (Global Positioning System (GPS)). The PMU estimates the sinusoidal
component of the AC waveform from a voltage or current input. Using a time input, usually from
a GPS source, it constructs a synchronized reference cosine waveform at the nominal system
frequency (60 Hz) such that positive peak is at a UTC second rollover. The synchrophasor phase
angle is the phase difference between these signals at the given reporting time.
PMUs also report analog quantities such as derived active and reactive power and digital quantities such as
breaker status. Frequency and rate-of-change-of-frequency (ROCOF) are derived from a phasor signal (generally
voltage phasor) estimated by the PMU. Figure 1 depicts a phasor representation of a sinusoidal waveform.
Synchronization to a common time reference for time = 0 is performed using a reference waveform as described
above.
NERC | Phase Angle Monitoring | June 2016
1
Introduction
Figure 1: Sinusoidal Waveform and Phasor Representation
[Source: Electric Power Group]
Fundamental Drivers for Phase Angle Differences
Phase angle is fundamentally linked to power transfer and system topology. Consider the equation for active
power flow, 𝑃𝑃𝑠𝑠𝑠𝑠 , across a short high voltage transmission line 1
𝑃𝑃𝑠𝑠𝑠𝑠 =
𝑉𝑉𝑠𝑠 𝑉𝑉𝑟𝑟
sin(𝜃𝜃𝑠𝑠𝑠𝑠 ).
𝑋𝑋𝑙𝑙
𝑉𝑉𝑠𝑠 and 𝑉𝑉𝑟𝑟 are the sending and receiving end voltage magnitudes, respectively, 𝑋𝑋𝑙𝑙 is the line impedance, and 𝜃𝜃𝑠𝑠𝑠𝑠 is
the phase angle difference between bus voltage phasors at each terminal of the line. This equation can be
rewritten to show the relationship with respect to phase angle difference.
𝑃𝑃𝑠𝑠𝑠𝑠 𝑋𝑋𝑙𝑙
�
𝜃𝜃𝑠𝑠𝑠𝑠 = sin−1 �
𝑉𝑉𝑠𝑠 𝑉𝑉𝑟𝑟
This clearly shows that phase angle difference is directly related to power flow, impedance, and voltage
magnitudes. However, voltage magnitude is held relatively constant within reasonable operating schedules near
1.0 pu (or higher for EHV transmission). Therefore, phase angle difference is primary driven by power flow and
electrical impedance. Phase angle can change drastically for major topology changes; hence, phase angle
differences being a strong indicator of system topology conditions and switching events. Power flows can vary
over a wide range and also have a relatively significant impact on phase angle differences. Power flows from a
higher voltage phase angle to a lower voltage phase angle. A large phase angle difference between the source and
the sink or a pair of buses indicates greater power flow between those points. This implies higher static stress
across that interface and closer proximity to instability. The relationships described here and uses of phase angle
differences in power system applications are the focuses of this paper.
Fundamental Need for Synchrocheck Relay Thresholds
When a transmission line is removed from service (forced or planned), the phase angle difference between its
terminals generally increases because the electrical impedance between these two points increases. Substantially
large phase angle differences can lead to system instability and loss of synchronism for generating resources.
Power swings from reclosing or restoring lines with a large phase angle, and subsequent oscillations, could lead
to system instability or collapse.
1
This equation is only valid when XL >> RL, where XL is the line series reactance and RL is the line series resistance.
NERC | Phase Angle Monitoring | June 2016
2
Introduction
Reclosing a transmission circuit with large phase angle difference across its terminals near generators can result
in a large transient torque on the shaft of the generator. Large phase angle difference is directly related to the
generator rotor being out of phase with the bulk power system; therefore, the transient torque is generated to
move the rotor shaft position back into phase with the system. Significantly large transient torques can cause
instantaneous damage or cumulative fatigue to the generator shaft, and deteriorate the life of the machine [3].
To prevent the harmful effects of closing transmission lines on the transmission system with a high phase angle
difference, many utilities use synchrocheck relay schemes on their bulk power transmission lines. Such schemes
measure the voltage magnitude difference, frequency slip and phase angle difference between the voltages and
supervise against a pre-determined setting prior to restoring a transmission line.
NERC | Phase Angle Monitoring | June 2016
3
Southwest Outage Recommendation 27
Overview of Outage and Angle Implications
On the afternoon of September 8, 2011, an 11-minute system disturbance occurred in the Pacific Southwest,
leading to cascading outages and approximately 2.7 million customers without power. The outages affected parts
of Arizona, Southern California, and Baja California, Mexico. All of the San Diego area lost power, with nearly 1.5
million customers losing power, some for up to 12 hours.
During the event, system stress steadily increased in seven distinct steps during the sequence of events. This is
illustrated in Figure 2, showing the line MVA/current loading for South of SONGS (San Onofre Nuclear Generating
Station) interface [2]. The initiating event was the forced outage of the Hassayampa-North Gila 500kV line. This
led to tripping of sub-transmission transformers and generation, operation of a response-based Remedial Action
Scheme (RAS), and subsequently the separation of the South of SONGS interface when it exceeded its phase
current limit.
Figure 2: Seven Phases of the 2011 Pacific Southwest Outage
The public report did not provide a detailed analysis of phase angle values during this event; however, monitoring
phase angle was a key finding and recommendation from this outage analysis. Finding and Recommendation 27
from the outage report are described below.
NERC | Phase Angle Monitoring | June 2016
4
Southwest Outage Recommendation 27
2011 Southwest Outage Report Finding 27
Report Finding 27 focused on the phase angle separation following loss of major transmission lines, specifically
the Hassayampa-North Gila 500kV line. In particular, when the line was tripped out of service, system stress drove
the phase angle difference between the two terminals of the line to larger than the synchrocheck relay setting.
Therefore, the line was incapable of returning to service if switched in due to this large phase angle. The report
highlighted the need for monitoring phase angle differences for the purposes of returning to service transmission
elements in a coordinated, efficient manner. Finding 27 states:
“Phase Angle Difference Following Loss of Transmission Line: “A TOP did not have tools in place to
determine the phase angle difference between the two terminals of its 500 kV line after the line
tripped. Yet, it informed the RC and another TOP that the line would be restored quickly, when, in
fact, this could not have been accomplished.”
2011 Southwest Outage Report Recommendation 27
Based on this finding, the FERC-NERC report highlighted two major areas of focus for Transmission Operators
(TOPs) related to restoration of transmission lines: situational awareness tools, and mitigation and operating
plans. Recommendation 27 states:
“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.
These plans should be developed based on the seasonal and next-day contingency analyses that
address the angular differences across opened system elements.”
NERC | Phase Angle Monitoring | June 2016
5
Phase Angle Difference Monitoring – Synchro-Check Awareness
Integration with EMS Network Applications
Commercial EMS software applications provide Transmission Operators (TOP), Balancing Authorities (BA), and
Reliability Coordinators (RC) with the capability of defining node or bus angle pairs and comparing calculated
phase angle differences against defined settings such as synchrocheck relay settings. Monitoring these
calculations in the network model and alarming operators on angular separation exceedance in real-time (i.e.,
SCADA and State Estimator (SE) base cases) and potential post-contingency states (i.e., Real-Time Contingency
Analysis (RTCA)) provides system operators with near-real time awareness of phase angle differences. Comparing
these limits to the synchrocheck relay limits identifies any lines that could be unable to be restored after tripping.
According to the FERC-NERC investigation report and NERC Reliability Standard requirements, system operators
shall be positioned to proactively operate the system in a secure N-1 state during normal system conditions and
to restore the system to a secure N-1 state as soon as possible, but no longer than 30 minutes. By using RTCA tools
that usually run every 5 minutes or less, system operators gain near real-time awareness of phase angle difference
exceedances under pre-defined single contingency (N-1) or credible N-2 or N-1-1 contingency operating
conditions.
There are multiple ways for system operators to obtain awareness of system angular separation conditions using
State Estimator (SE) tools. At each state estimate solution, bus voltage phase angles are estimated and the phase
angle difference across defined transmission circuits can be reported as a branch record as shown in Figure 3.
Figure 3: Reported Phase Angle Differences over Threshold in SE
[Source: Peak Reliability]
The derived phase angle separation across these branch elements can then be compared against a user-defined
limit. The SE tools allow users to define a group of node pairs (NP) with pre-assigned Normal and Emergency
Limits. These NP limits can be directly linked to the limits defined in the synchrocheck relays for those respective
lines 2. Figure 4 shows a screenshot of the definition of NP limits for the North Gila-Imperial Valley 500kV
2
Synchrocheck relay settings change relatively infrequently; therefore, static limits are generally acceptable for these types of alarms.
NERC | Phase Angle Monitoring | June 2016
6
Phase Angle Difference Monitoring – Synchro-Check Awareness
transmission circuit. Both Normal and Emergency Limits are set to 50 degrees for the phase angle difference as
per defined operating procedures.
Figure 4: Phase Angle Difference Limits Based on Synchrocheck Relay Settings
[Source: Peak Reliability]
Once the SE-calculated phase angle difference for a given NP record is approaching or exceeding its limit, the
advanced application reports an NP exceedance violation of Normal Limit for base case conditions and gives the
time of the occurrence of the violation. This is shown in Figure 5.
Figure 5: Alarming of Current Operating Condition Large Phase Angle Differences
In addition to steady-state operating condition awareness, Real-Time Contingency Analysis (RTCA) is also running
on a timeframe of approximately 5 minutes or faster. The RTCA will further check for NP angle limit violations
during post-contingency conditions compared against the Emergency Limit (Figure 6). Unlike the SE application,
RTCA is designed to detect a potential angular separation exceedance ahead of the actual incidence, so that
system operators can develop timely mitigation plans to prevent a large angular separation from causing an
operational issue. The mitigation plan can be derived from operations engineering guidance as well as operating
procedures.
NERC | Phase Angle Monitoring | June 2016
7
Phase Angle Difference Monitoring – Synchro-Check Awareness
Figure 6: Post-Contingency Angle Monitoring through RTCA [Source: Peak Reliability]
Sensitivity analysis tools are being explored to provide automated mitigation analysis within the EMS platform.
When an angle separation exceedance is detected by the angle limits in the SE and RTCA, the software initiates
network sensitivity analysis against the angle separation constraint to identify which control actions are available
to remove or mitigate the angle separation violation. These actions include:
1. Generation re-dispatch to shift path or line MW flow;
2. Coordinated phase shifting transformer (PST) tap movements;
3. Curtailment of bilateral point to point (PTP) power transfer transaction;
4. Transmission switching including lines and series compensation elements 3;
3
In the WECC footprint, there are over 200 series capacitors installed on transmission circuits to allow compensating long distance
transmission lines by up to 80% of the line reactance.
NERC | Phase Angle Monitoring | June 2016
8
Phase Angle Difference Monitoring – Synchro-Check Awareness
Visualizing emergent N-1 contingencies is a tremendous help to the real-time system operators to have a physical
representation of possible problem areas rather than trying to digest conventional contingency lists. Figure 7
shows the Geo-Spatial Visualization System (GVS) application displayed on the control center wall map to increase
operational situational awareness 4. Each operator console has high resolution monitors that allow the operator
to customize their own view using laying capabilities. Violations, including phase angle differences exceeding
defined limits, are shown in tabular form as well as geo-spatially on the map.
Figure 7: Visualization of RTCA Results [Source: APS]
4
GVS application is currently deployed by Arizona Public Service in real-time operations.
NERC | Phase Angle Monitoring | June 2016
9
Phase Angle Difference Monitoring – Synchro-Check Awareness
SE and RTCA provide a near real-time means of monitoring system angular separation. These tools use SCADA
data and employ steady-state analysis tools for monitoring angle separation. PMU data can complement this by
monitoring phase angle difference dynamics and with much higher resolution. In Figure 8, the trend clearly
demonstrates the advantage of using synchronized PMU voltage angles to complement EMS network applications.
PMU phase angles are down-sampled to 1 sample/second, as compared with the SE solved bus angle difference
calculations for that same transmission circuit cycled at 1 minute intervals. As the grid dynamically changes, the
SE results become stale and do not reflect the changing nature of the grid.
Figure 8: SE Solved Bus Angle vs Down-Sampled PMU Phasor Angle
[Source: Peak Reliability]
NERC | Phase Angle Monitoring | June 2016
10
Phase Angle Difference Monitoring – Synchro-Check Awareness
Synchrophasor-Based Tools & Real-Time Awareness
Emerging synchrophasor technology enables utilities to monitor angular separation conditions with high
resolution synchronized PMU phase angle measurements at rates of 30-60 samples per second. PMU
measurements are being integrated with conventional EMS network applications discussed in the previous
section. Synchrophasor-based applications are also developing innovative ways to monitor, visualize, and alarm
on large angle exceedances to complement existing tools.
Figure 9 simply shows the high resolution voltage phase angle difference calculation between two specific points
on the grid over multiple minutes using PMU data. Overlaid on the plot is a hypothetical phase angle measurement
from a SE solution provided event 1-minute. Note that the phase angle can fluctuate significantly during these 1minute intervals and being able to visualize and understand this is crucial.
Figure 9: Voltage Phase Angle from PMU Data & SE Solution [Source: Peak Reliability]
Synchrophasor-based applications use the time-synchronized phase angle measurements from PMUs to calculate
phase angle differences at high resolution. These applications can also issue alarms if monitored phase angle
differences exceed limits immediately following a major system event. The benefit of using PMU data to
supplement the EMS applications is that it gives the operators immediate alarming of angle exceedances, rather
than waiting for the subsequent state estimator solution and RTCA alarms (as shown in Figure 9 above). That
period of time immediately following a major grid disturbance is when system operators are trying to understand
the event and discern if operating conditions are acceptable and any actions are necessary to mitigate potential
problems. Angle monitoring and alarming provides the operator with advanced notice of system stress. Figure 10
shows a synchrophasor-based display of angle differences compared against their respective limits.
Figure 10: Synchrophasor-Based Angle Alarming Tool [Source: Peak Reliability]
NERC | Phase Angle Monitoring | June 2016
11
Phase Angle Difference Monitoring – Synchro-Check Awareness
Arizona Public Service (APS) has extended its Geo-Spatial Visualization System (GVS) to include synchrophasor
applications. Figure 11 shows a wide-area visualization of PMU phase angle differences across the APS system.
Each defined phase angle difference (PAD) is shown in the geo-spatial map, as well as defined limits for each phase
angle. Again, a map feature allows the operator to visualize system stress and angle differences across the
network. PMU application results can be transferred in real-time to the EMS system, facilitating the ability for
system operators to monitor angular separation conditions with both EMS-based and PMU-based applications in
a complementary way.
Figure 11: Visualization of Phase Angle Differences [Source: APS]
Benchmarking PMU and SCADA Data
Ensuring the quality of synchrophasor data is a critical business need, particularly when analyzing angle differences
across large interconnected systems and across different operating entities (multiple Transmission Owners). The
primary purpose of benchmarking PMU (down-sampled) data, SCADA data, and solved state estimator data is to
determine the relative accuracy of each data source and identify any bad data issues within any of the data
sources. While SCADA and SE data are widely accepted and relatively trusted, PMU data benchmarking can be
used bi-directionally. Any one data source can be an outlier when compared with the others; PMU data can be
flagged as poor quality or can serve as a benchmark against the SE solution or SCADA data. One key goal of
benchmarking PMU data is to ensure they are within an acceptable range for the device they are measuring and
compare relatively close with other data sources, including:
•
Voltage Magnitude: PMU bus voltage magnitude is compared against SCADA telemetry bus voltage.
•
Voltage Phase Angle: PMU bus voltage phase angle is compared against state estimator solved bus
angle. One of the PMU reference angle points needs to be enabled in the SE in order to baseline the SE
solved bus angles against the PMU measurement such that relative angle differences can be compared5.
•
Frequency: PMU frequency is compared against SCADA telemetry frequency.
5
Only enable validated PMU voltage angles in the state estimate solution and reasonable limits need be assigned to filter out bad PMU
angle values.
NERC | Phase Angle Monitoring | June 2016
12
Phase Angle Difference Monitoring – Synchro-Check Awareness
•
Current Magnitude (and Angle): PMU current magnitudes are compared against SCADA telemetry
current signals if ICCP is available. Otherwise, PMU current and voltage phasors are used to calculate
line active (P) and reactive (Q) power flow to compare with SCADA P & Q values.
Benchmarking results are meaningful and valid only if the input data is representative of the physical equipment
being monitored. This assumes that the SE model is accurate, the PMU and SCADA data points are accurately
mapped, naming conventions are addressed in the PMU and Phasor Data Concentrator (PDC) as well as EMS, and
time alignment and down-sampling is handled appropriately. These can all be sources of error in benchmarking
that may or may not represent actual bad electrical data measurements.
Time Alignment
Raw synchrophasor data is captured at a rate of 30 samples per second, which is then down-sampled into EMS at
a rate of 1 sample per second. SCADA data is received from entities at a rate of 1 sample per 10 seconds, and the
EMS state estimator solves at 1 sample per 60 seconds. In general, there will be more PMU values than SCADA or
SE. The tool must carefully filter and choose values which are most time aligned.
Synchrophasor Data Validation Options
There are numerous methods being explored within the industry for determining the accuracy of synchrophasor
data. These are actively being developed within NASPI community and other forums. A formal definition or
process for data quality tracking is not yet well understood among industry professionals; however, industry is
making strides improving data quality prior to using the data in advanced applications. Examples of industry efforts
focused on data quality include:
•
A Linear State Estimator (LSE) application using C37.118 streamed data to estimate the system state
using direct non-iterative solutions at the PMU reporting rate. The linear state estimate can be used to
identify bad data quality using PMU data only.
•
PDQ Tracker 6 provides real-time data validation functions by interfacing with the LSE. This real-time data
validation methodology is intended to check PMU stream availability other than data quality.
Signal Mapping Guidelines
PMU measurements must be accurately mapped to matching SCADA analog data points to perform
benchmarking. Raw PMU measurements are integrated into EMS/SCADA with down-sampled PMU data, which
supplement SCADA measurements. The down-sampled PMU angle data points in SCADA need be mapped to the
EMS network model in order to be enabled for the SE solution as well as used for benchmarking. An example of
this mapping is illustrated in Table 1. The measurements must have matching units or an appropriate scaling
factor, and ideally should be monitoring the same network Elements as closely as possible. This may include using
SCADA and PMU measurements from the same current or voltage transformer. The mapping table can be
incorporated into the model update process, which includes checks for valid records, facilitating continual
updating of this table. A standardized naming convention for PMUs should be established for effective mapping.
6
Grid Protection Alliance (GPA). “PDQ Tracker”. [Online]. Available: https://pdqtracker.codeplex.com
NERC | Phase Angle Monitoring | June 2016
13
Phase Angle Difference Monitoring – Synchro-Check Awareness
Table 1: PMU Signal and EMS Naming Conventions [Source: Peak Reliability]
EMS Fields
PDC Fields
Area
Substation
Device
Device
ID
PMU Name
Signal Name
Signal
BPA
ALLSTON
BUS
500_NORTH_BUS
FRQ
W001ALLSTON___01
A500FREQ_____1F_
F
APS
PINPKAPS
BUS
900A
KVA
W066PINPKAPS__02
B500BUSA_____1VP
A
BC-HYD
NICOLA
ZBR
MICA_NIC__19Z2
KVM
W030NICOLA____01
L500MICA_____1VP
M
IPCO
KINPORT
LN
KINP_POPU_1345
AA
W034KINPORT___01
L345POPULUS__1IP
A
LADWP
ADLNTO
LN
ADLN_VICT_1500
AM
W068ADLNTO____01
L500VICTVL___1IP
M
PMU Data Quality
Poor PMU data quality, such as loss of synchronization, can have a significant impact on phase angle difference
calculations. Typically an PMU that is not time synchronized will report rapidly changing phase angle values that
can cause erroneous values in difference calculations. However, if appropriate data quality flags are utilized and
configured, these bad calculations can be omitted from applications using the data. Figure 12 highlights a common
PMU data quality issue that could affect an angular separation monitoring application. In this example, a
transmission line part of a major transmission interface is out-of-service, resulting in loss of PMU data integrity
and accuracy because the PMU is installed on the line side. After line tripping, PMU voltage angle fluctuates
between 180 and -180 degrees while the line is out of service (Figure 13). Network applications need data quality
intelligence to quickly and accurately flag this data as bad quality such that the calculated information does not
get displayed or portrayed to the system operator.
Figure 12: PMU Raw Data after Loss of Line Equipment [Source: Peak Reliability]
NERC | Phase Angle Monitoring | June 2016
14
Phase Angle Difference Monitoring – Synchro-Check Awareness
Figure 13: PMU Data Quality Issue after Loss of Line Equipment [Source: Peak Reliability]
EMS and PMU Data Quality Flags
Benchmarking must account for data quality flags from all data sources as well as the state estimator. Quality flags
should be pulled for all SCADA and PMU values prior to any comparison calculations. Only points with good quality
should be included in the validation calculations. Each EMS vendor has defined their own EMS/SCADA quality
flags. The State Estimator solution must also be converged network solution with reasonable mismatches. It is
assumed that the SE solution is of good quality if these conditions are met. The C37.118 protocol includes data
quality flags in the Status Word bits, and these can be manipulated throughout the PMU data stream if issues are
detected. The percentage of time a PMU cannot be validated due to communications network quality problems
should be calculated and included in a log file for awareness.
Benchmarking Calculations
Benchmarking results can be tracked as a percentage of time (number of points) the data is within the deviation
limit compared against the total amount of time (points) archived in the historian during the validation start and
end times, referred to as “Good %”. Figure 15 shows a process flowchart of PMU validation against SCADA and SE
values 7. For benchmarking PMU and SE solution data, the PMU measurements and SE solved quantities should be
sufficiently close enough. For example, Peak RC uses a deviation within ±2 degrees over 98% of time for a given
time period for validating phase angle measurements. When this is the case, both the network model and PMU
measurements can be validated as “good”.
7
The method proposed here has been vetted and presented in WECC Joint Synchronized Information Subcommittee (JSIS).
NERC | Phase Angle Monitoring | June 2016
15
Phase Angle Difference Monitoring – Synchro-Check Awareness
Figure 14: PMU (Down-Sampled in SCADA) and SE Estimated Angle Comparison
[Source: Peak Reliability]
NERC | Phase Angle Monitoring | June 2016
16
Phase Angle Difference Monitoring – Synchro-Check Awareness
Figure 15: EMS-PMU Validation Logic Diagram [Source: Peak Reliability]
NERC | Phase Angle Monitoring | June 2016
17
Phase Angle Difference Monitoring – Synchro-Check Awareness
Without this benchmarking and accuracy review, notable gaps can exist between the PMU phase angle differences
and the state estimator solved bus voltage angles. This highlights an issue with, and need to review, either the
PMU measurements or the network model. While many utilities rely and fall back on their network model as more
accurate, there needs to be objective analysis to determine where the differences are originating. Also to consider
are the potential inaccuracies in the instrument transformers that can lead to differences between these values.
Peak RC currently uses a threshold of ± 2 degrees to filter out PMU voltage angles inconsistent with SE solved bus
voltage angles. The 2 degree threshold is based on time lag in SE values, inconsistencies with the instrument
transformers, and noise in the high-resolution PMU measurements. Figure 16 shows an example of the PMU
measurements compared with the network model angles, highlighting nearly an 8 degree difference between
these two. This is a prime example of a discrepancy between SE and PMU data, highlighting a need to determine
the source of error.
Figure 16: Line-Based Angle Separation Curves – PMU (Down-Sampled in SCADA) vs. SE
Values [Source: Peak Reliability]
NERC | Phase Angle Monitoring | June 2016
18
Phase Angle Difference Monitoring – Synchro-Check Awareness
Mitigation and Operating Procedures for Line Restoration
As the 2011 Southwest Outage Finding and Recommendation 27 highlighted, monitoring excessive phase angle
differences between adjacent transmission circuit terminals to identify lines that cannot be restored following
outage is a viable and relatively straightforward use of PMU data. The thresholds for these angle differences are
based on the synchrocheck relay settings. Criteria to identify these phase angle difference exceedances should be
based on the following:
•
Different threshold settings and design philosophies among Transmission Owners within a Reliability
Coordinator (RC) footprint;
•
Mitigation strategies based on actual synchrocheck settings at the location where large phase angle
difference is occurring;
•
Assessments including high transfer analysis to stress the power system among key interties and transfer
paths to identify likely phase angle difference exceedances; and
•
Known operational restrictions or limitations; and
•
Planned outage conditions or historical outage events of interest.
Actions for Excessive Phase Angle Differences
The utility industry has worked collectively to develop effective mitigation strategies for excessive phase angle
separation. Here are practical control actions commonly employed:
•
Reconfiguration of in-series capacitors/reactors for compensation of transmission circuits
•
Generation redispatch

Reducing generation on the sending end of the angle difference path

Increasing generation on the receiving end of the path
•
Use of phase‐shifting transformers to reduce power flow (if available)
•
Reconfiguration of system topology to reduce power flow (if possible)
•
Curtailment of interruptible load, if necessary
•
Firm load shedding, if necessary
•
Point-to-point transmission service curtailment
NERC | Phase Angle Monitoring | June 2016
19
Correlating Phase Angle with System Conditions
Correlation analysis between bus angle differences and MW flows provides a deeper understanding of the
dynamic properties of the interconnected bulk power system. This better understanding will allow certain
thresholds for abnormal system operating regions to be determined. Identified thresholds can then be used to
configure alarms and operating procedures. Correlation analysis requires access to historical data and real-time
advanced network application results including:
•
PMU measurements
•
SCADA measurements
•
EMS Network Applications – state estimator solutions, RTCA results, voltage stability and transient
stability analysis results, oscillation event detection or mode meter results, etc.
Phase Angle and Real Power Correlation
Correlation between phase angle and real power flow is self-evident from the DC load flow (DCLF) equation, which
estimates active power line flow on AC power systems, neglecting reactive power. This non-iterative solution will
converge but is less accurate than a full AC power flow solution. DCLF is used wherever repetitive and fast load
flow estimations are required, as well as for sensitivity analysis around a defined operating state. In a DCLF, the
nonlinear model of the AC system is simplified to a linear form through these assumptions:
•
Line resistances (active power losses) are negligible (i.e. R<< X)
•
Voltage angle differences are assumed to be small (i.e. sin(θ) = θ, cos(θ) = 1)
•
Magnitudes of bus voltages are set to 1.0 per unit (flat voltage profile)
•
Tap settings are ignored
The bulk power system, at voltage generally 100kV and above, consists of transmission lines that exhibit an X/R
ratio that is usually small; therefore, the assumptions of DCLF are relevant for certain types of analysis. Based on
the above assumptions, voltage angles are the variables of a DCLF and active power injections are known in
advance. As a result, active power flow through transmission line i with reactance XLi between buses s and r can
be calculated by
1
(𝜃𝜃 − 𝜃𝜃𝑟𝑟 )
𝑃𝑃𝐿𝐿𝐿𝐿 =
𝑋𝑋𝐿𝐿𝐿𝐿 𝑠𝑠
It is clear that, as an estimate, MW flow across an in-service transmission line is proportional to the angle
difference between the sending and receiving bus phase angles of the line. The phase angle difference resulting
from the outage of a given transmission circuit is non-linear and based on stress pattern and the Thevenin
equivalent impedance between the two terminals.
Figure 17 shows a 20-day PI trend of transmission interface MW flow (e.g. Path flow) vs. phase angle difference
between two buses of the substations associated with the interface. The plot shows correlation between MW
flow magnitude and phase angle separation. Figure 18 shows a 2-Hour X-Y plot of transmission interface MW flow
(e.g. Path flow) vs. phase angle difference between two buses of the substations associated with the interface.
The plot shows correlation between MW flow magnitude and phase angle separation. The correlation coefficient
between the path flow and the angle pair is 0.96336 which indicates strong correlation. The dashed straight line
represents the linear correlation line.
NERC | Phase Angle Monitoring | June 2016
20
Correlating Phase Angle with System Conditions
Figure 17: Interface MW Flow and Phase Angle Difference Correlation – 20 Days
[Source: Peak Reliability]
Figure 18: Interface MW Flow and Phase Angle Difference Correlation – 2 Hours
[Source: Peak Reliability]
NERC | Phase Angle Monitoring | June 2016
21
Correlating Phase Angle with System Conditions
This correlation can be observed more clearly when the plot is zoomed in on a 2-day window (Figure 19). Some
interesting observations from this specific example correlation analysis include:
•
Phase angle separation can increase prior to interface MW flows increase (circled in red);
•
Angular separation rate-of-change can be sharper than the rate-of-change of interface MW flow; and
•
Phase Angle separation changes can lag behind changes in interface MW flows (circled in blue).
This indicates that system operators may gain earlier awareness of significant changes in operating conditions
from appropriate angular separation monitoring, in conjunction with and complementing interface MW flow
monitoring. A transmission interface consists of multiple lines and/or transformers that are connected to or
located at different substations. The correlation is sensitive to selection of a specific angle pair, and the correlation
analysis should consider these angle selection differences. This is particularly useful when defining backup or
alternative measurements in the event of loss of primary signal. For a single transmission line, the correlation of
angular separation and MW flow becomes highly observable. Figure 20 indicates that:
•
MW flow pattern matches the phase angle difference pattern before line tripping; and
•
Phase angle difference may indicate system stress (higher angle difference) while the MW flow has
dropped to zero after line tripping.
Figure 19: Correlation between Interface MW Flow and Phase Angle Difference
[Source: Peak Reliability]
Patterns of phase angle difference relative to MW flows can vary as a function of system conditions, topology
changes, angle pairs chosen, and other factors. It is necessary to study a long series of phase angle and MW flow
data for a variety of angle pairs and grid conditions to identify meaningful angle difference thresholds and
consistent indicative angle pairs.
NERC | Phase Angle Monitoring | June 2016
22
Correlating Phase Angle with System Conditions
ANGULAR SEPARATION vs LINE MW FLOW
Figure 20: Angle Difference between Line Terminals after Line Tripping (Zero MW)
[Source: Peak Reliability]
Large interconnected power system operating limits are often defined by establishing major transmission
interfaces or cut planes. These are defined as System Operating Limits (SOLs) and Interconnection Reliability
Operating Limits (IROLs) [4,5]. For example, the Western Interconnection has nearly one hundred established
transmission paths (“WECC Paths”) to monitor system operations [6]. Operations engineers run offline studies to
determine the Path operating limit (in MW) upon “assumed” system topology and forecasted area load levels.
Due to the strong correlation between MW and angle, in conjunction with the proliferation of PMU coverage and
redundancy, phase angles may be a suitable operating limit criteria for the future. Figure 21 shows 1) time series
of a large system event in WECC measured by PMUs, and 2) the relative comparison of angle vs. active power
transfer in the pre-contingency, post-contingency and during-contingency operating conditions.
Shown in Figure 22 is a hypothetical MW Limit, which could be associated with a SOL or IROL. Assuming this MW
limit is determined to be 1325 MW, a corresponding phase angle limit can also be defined based on either offline
or online methods. In this example, two hypothetical phase angle limits are determined:
1. Limit = 6.75 deg: This limit, based on the correlation analysis, is likely not to be hit prior to the MW limit
defined. In this case, the angle can really serve as a backup limit for unexpected conditions.
2. Limit = 6.60 deg: This limit, based on the correlation analysis, is likely to be hit prior to the MW limit
defined. In this case, the angle is a better indicator of system security compared to the MW flow lilmit
and could be used a primary or supplemental limit.
NERC | Phase Angle Monitoring | June 2016
23
Correlating Phase Angle with System Conditions
Figure 21: Path MW and Angle Measurement for Contingency Event
[Source: Bonneville Power Administration]
Figure 22: Path MW and Angle Compared with Interface Limits
[Source: Bonneville Power Administration]
The examples shown here provide some insights into how correlation analysis can be useful for phase angle
monitoring and limit monitoring.
NERC | Phase Angle Monitoring | June 2016
24
Identification of Key (Optimal) Angle Differences
Major Transmission Interfaces or Transfer Paths
Wide-area phase angle monitoring of major transmission interfaces is a useful application of PMU technology.
These interfaces are used to operate the bulk power system within known operating limits, and having additional
visibility into system conditions including angular separation provides operators with situational awareness. The
WECC Paths are used as an example to illustrate angle monitoring of major transmission interfaces.
WECC Intertie Paths
WECC coordinates a number of high voltage transmission interfaces in the Western Interconnection that consist
of one or more transmission circuits, called the WECC Paths. These interfaces include transmission lines and
transformers separating the system into cohesive areas or systems between various operating entities and
geographic regions. These areas can be quite distant, such as Path 65 (the Pacific DC Intertie (PDCI) between the
The Dalles, Oregon and Los Angeles, California) or relatively short such as Path 5 (West of Cascades – North),
primarily within the BPA footprint in Washington State. These Paths are currently numbered 1 to 83, with a few
numbers intentionally omitted. Since the interties may consist of multiple circuits, the operating voltages for these
circuits ranges from 55 kV to 500 kV.
Let us consider Path 5, West of Cascades North, which interconnects the Seattle, WA load center to Upper
Columbia generation. This Path consists of a handful of 500 kV, 230 kV, and 345 kV circuits. To illustrate the
complementary benefit of phase angle monitoring, consider an operational scenario where one of the Path 5 500
kV lines is removed from service. In this scenario, the Path 5 transfer stress is analyzed using bus phase angle
difference rather than MW flow and limit. Figure 23 shows pre- and post-contingency conditions visualized by (1)
Path MW flow, (2) Path MW limit, (3) Line MW flow; and (4) PMU phase angle difference (PAD) across the
terminals of the line removed from service [7]. The example reveals that:
1. There is a visible correlation between Path MW flow and PAD before the line is removed;
2. The Path operating limit remains constant before and after the line is lost (the Path operating limit is not
dynamically calculated in real-time for a forced outage);
3. The Path MW flow is reduced by about 200 MW as a result of line outage; and
4. The PAD has a sharp increase in response to loss of the line, indicating system stress.
Traditionally, system operators gain awareness of operating stress for a given Path by monitoring Path loading as
a percentage of the Path Limit in MW.
𝑃𝑃𝑃𝑃𝑃𝑃ℎ 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 =
𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝐹𝑀𝑀𝑀𝑀
∗ 100
𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝑀𝑀𝑀𝑀
In this scenario, the Path loading % actually decreases following the outage, so system operators don’t perceive
an apparent increase in system stress for the Path after the line outage. On the other hand, the angle separation
experiences a step increase, illustrating the system operator should also be aware of these values as well because
it reflects the topological change of impedance.
NERC | Phase Angle Monitoring | June 2016
25
Identification of Key (Optimal) Angle Differences
LINE MW FLOW PATH RATING in MW PATH MW FLOW BUS ANGLE SEPARATION
Figure 23: WECC Path 5 Flow & Limit, Line Flow and Phasor Angle Difference
[Source: Peak Reliability]
Oscillatory Stability Analysis
Inter-area oscillations are a wide-area electromechanical phenomenon involving coherent generators oscillating
against other generators. Local oscillations involve a single or small group of generators oscillating against the rest
of the system. Both these types of oscillations can affect the stability of the entire interconnected bulk power
system and impact transmission interfaces between these oscillating generators. For example, the North-South
modes in the Western Interconnection involve generators in Canada and the Pacific Northwest swinging against
generators in the Desert Southwest and Southern California. These oscillations are usually well damped but do
manifest themselves as power swings on major transmission circuits and interfaces such as the California–Oregon
Intertie, British Columbia–Northwest, and WECC Path 26.
One major difference between synchrophasor data and scan-rate SCADA data is that PMU data can detect interarea modes excited by a major grid disturbance while SCADA measurements cannot. The August 10, 1996 outage
in the Western Interconnection is a prime example of a sequence of events that led to undamped inter-area
oscillations and eventual system separation (Figure 24) [8]. While this plot shows voltage, wide-area phase angles
were also oscillating due to large power swings from electromechanical modes on the system. PMU data captures
these types of oscillations, and phase angle differences can be used to measure event oscillation ringdown for
major events. Upon detection of an event, automated tools can capture the modal characteristics such as
oscillation frequency and damping ratio. These tools could have detected a sustained undamped oscillation had
they been in place in 1996.
NERC | Phase Angle Monitoring | June 2016
26
Identification of Key (Optimal) Angle Differences
Figure 24: August 10, 1996 Oscillation – Malin 500kV Voltage [Source: BPA]
Another useful example in the Western Interconnection is the August 4, 2000 oscillation event that caused large
voltage, power, and angular swings on the bulk power system following a contingency. As Figure 25 shows, the
oscillation damping ratio was very low, requiring over 60 seconds for the oscillation to settle [9]. Operator
awareness that the system is marginally stable for contingency events provides awareness of the state of the bulk
power system. Identifying these types of events quickly and effectively helps the system operator decide whether
and how to respond. In this case, cutting scheduled transfers and generation redispatch would reduce the
oscillation risk being driven by wide-area power transfers.
Figure 25: August 4, 2000 Oscillation – Malin 500kV Voltage [Source: BPA]
Various oscillation monitoring applications and software tools using PMU data have been deployed at Bonneville
Power Administration, Southern California Edison, other WECC utilities, and Peak Reliability. Table 2 shows the
predominant (known) oscillation modes in the Western Interconnection and the PMU phase angle pairs used as
NERC | Phase Angle Monitoring | June 2016
27
Identification of Key (Optimal) Angle Differences
input to calculate oscillation frequency and damping ratio in some of the tools. Currently, the North-South Mode
A and Mode B are being monitored in real-time at Peak RC and BPA control centers using PMUs across the Western
Interconnection.
Table 2: Oscillation Modes in the Western Interconnection
Mode
Oscillation Frequency
North-South Mode A
0.25 Hz
PMU Locations Monitored
Custer 500 – Malin 500
Custer 500 – Captain Jack 500* (different PMU than BPA)
Malin 500 – John Day 500
North-South Mode B
0.34 Hz
East-West Mode
0.45 Hz
Not Monitored
Alberta Mode
0.60 Hz
Not Monitored
Montana Mode
0.80 Hz
Not Monitored
Malin 500 – Big Eddy 500
Maps of mode shape are used to illustrate how the inter-area electromechanical modes are manifesting on the
bulk power system. Figure 26 shows N-S Mode A and N-S Mode B mode shape maps. N-S Mode A involves the
Northern generation fleet oscillating against Southern California generation, while N-S Mode B has Alberta
generation oscillating in phase with the Southern California units. It is clear that these modes are heavily
influenced by the status of Alberta connection with the remaining Western Interconnection [10].
Figure 26: N-S Mode A (left) and N-S Mode B (right) [10] [Source: WECC]
Input signals of PMU angle differences for N-S Mode A (Canada-U.S. border) and N-S Mode B (Lower Columbia
Hydro-California to Oregon border) were selected for the Mode Meter engine by both BPA and Peak RC because
of the correlation with North-South flows predominantly across the California-Oregon Intertie (COI) (Path 66) [12].
Monitoring a particular mode requires PMU placement at the substations where the electromechanical mode is
NERC | Phase Angle Monitoring | June 2016
28
Identification of Key (Optimal) Angle Differences
most observable. Observability of a mode can be determined using offline system studies and oscillation analysis.
Monitoring the locations with highest observability provides a more accurate estimation of frequency and
damping ratio of the mode. Monitoring the shape of the mode requires a higher level of placement with PMUs
located at as many possible observability points within the interconnection. In general, is has been found that
mode shapes rarely change unless major grid topology or generation shifts occur.
N-S mode B results calculated from both BPA and Peak’s Mode Meter applications are shown in Figure 27. These
applications using phase angle differences in their modal estimation algorithms. The software platforms and
installations were benchmarked against each other to ensure consistent results. As Figure 27 shows, mode
frequency and damping ratio results are very close. For the system conditions tested, the N-S Mode B damping
ratio was impacted due to the events on the WECC system.
Figure 27: Brake Test – N-S Mode B Results – Peak vs. BPA [Source: Peak, BPA]
NERC | Phase Angle Monitoring | June 2016
29
Identification of Key (Optimal) Angle Differences
Phase Angle Visualization of Operating Boundaries
Utilities are working with transient stability analysis software vendors to develop a new phase angle visualization
feature. One desired feature allows users to visualize angle separation between the two regions where power is
being transferred. It uses the angle separations calculated from base case powerflow and transient stability based
transfer limits. This visualization feature shall contain two graphics:
•
Bar charts for interface and source MW limits
•
Dial gauges for angle spread limits
Figure 28: DSA Manager/TSAT Angle Separation Visualization [Source: Peak Reliability]
The user will have the ability to select different nodal pairs from the dial gauges. The software shall provide a
display of angle-spreads base case and limit values in the “History” window. This new visualization feature can
facilitate correlation baselining between power transfer level and bus angle separation degree for transient
stability limited WECC Paths and cut planes. The identified bus angle pairs and correlation baselining results will
be valuable input to angle separation exceedance alarms.
Voltage Stability and Phase Angle
Utilities are working with voltage stability analysis software vendors to develop a new approach to compute phase
angle limit. The intended software is capable of computing the angle limits from State Estimator data only, PMU
data only, or both for three types of different scenarios of stressing:
1. User-defined scenario (e.g. “sources” and “sinks”) for stressing
Conventional, but sub-optimal, stressing technique. The maximum transfer capability may be reached due
to exhausting resources before reaching voltage/thermal/steady state stability violation. The tool
computes both the most critical (sensitive) phase angle differences and user-defined angle pair
differences based on SE base case for each stressing. The function is applicable in both real time and offline. The approach is being explored by ISO-NE in more detail.
2. Optimal scenario based stressing
Planning tool to determine the maximum interface flow and phase angle limits. In principle, the software
maximizes the interface/path flow by optimal source and sink grouping so that maximum phase angle
limits may be calculated for the given interface/path.
3. “Natural” direction of system stressing
PMU or SCADA data are used to determine the “natural” direction of stressing based on historical
information. Phase angle limits are computed based on SE and PMU data. PMU data is used to determine
the change in system conditions, and thus the direction in which the system is stressed, while SE data is
used to determine the limit for the “natural” stressing direction. No traditional stressing needs to be
performed in the approach.
NERC | Phase Angle Monitoring | June 2016
30
Identification of Key (Optimal) Angle Differences
Figure 29: ISO-NE Angle Separation Stressing Analysis [Source: V&R Energy]
Figure 30: Computing Interface Limits-Angle vs MW [Source: V&R Energy]
NERC | Phase Angle Monitoring | June 2016
31
Linking Phase Angles with System Studies
Definition of Safe & Alert Operating States
Angle separation limits should be defined in the context of system operation reliability and security criteria, and
are contextually dependent on a number of factors such as system dispatch and topology. If violated, it signals
that the system is being operated under unsafe/adverse conditions such as:
•
Synchrocheck relay reclose angle difference exceedance
•
Excessive thermal limit violation that potentially leads to cascading outages
•
SOL or IROL exceedance due to voltage stability and transient stability concerns
•
Subsynchronous resonance (SSR) driven by bulk wind generation and weak system connection issues
•
Triggering RAS/SPS unexpectedly
•
Transaction schedules or economic transfer constraints
•
Combination of multiple factors listed above
The angle separation limit can be examined and confirmed by various reproducible system studies for a given base
case and post-contingency states (steady state and transient state) and other assumptions. Such angle separation
limit is justified with a “Safe” operating state. Otherwise, the angle separation limit simply indicates historically
defined “Normal” or “Off-Normal” security region. This type of angle separation limit basically gives “Alert” or
“Warning” of unusual system operating state. These two types of limits are complementary in that one identifies
violations and the root cause while the other defines action plans when adverse conditions occur.
Defining Inter-Area Stability Limits Based on Phase Angle
Transient stability studies are performed to ensure that oscillation damping ratios do not drop to unacceptable
levels after credible contingencies occur in order to maintain some margin of stability in the system. Ringdown
analysis can be performed on the transient stability results to identify the oscillation frequency and damping ratio
of the predominant electromechanical modes. Example analysis tools include Prony analysis and VARPRO
developed for these purposes 8. Pre- and post-contingency damping ratios are strongly correlated based on a
number of factors. Figure 31 shows this correlation for a number of stability studies performed at various
operating conditions, stress patterns, dispatches, topologies, etc. Notice the relationship between pre- and postcontingency damping ratio values for the critical contingency studied in this example. In this case, operating
conditions are identified that result in < 0% damping ratio (unstable) for pre-contingency damping ratio values
around 6%. This provides information to the real-time tools for setting limits on oscillation detection and mode
meter applications, in coordination with SCADA or PMU data relating the damping ratio calculation to system
condition information.
8
D. Trudnowski, J. Johnson, J. Hauer, “Making Prony analysis more accurate using multiple signals,” IEEE Trans. on Power Systems, vol. 14,
no. 1, pgs. 226-231, 1999.
A. Borden, B. Lesieutre, “Variable Projection Method for Power System Modal Identification,” IEEE Trans. on Power Systems, vol. 29, no. 6,
2014.
NERC | Phase Angle Monitoring | June 2016
32
Linking Phase Angles with System Studies
Figure 31: Pre- and Post-Contingency Damping Ratios Based on Studies [Source: BPA]
NERC | Phase Angle Monitoring | June 2016
33
Linking Phase Angles with System Studies
In transient stability simulations, pre-contingency operating conditions are extracted from the steady-state base
case (Figure 32) along with generation dispatch and major intertie real power flows. This data can be used for
comparison and correlation analysis; there is an inverse correlation between phase angle differences and
oscillation damping ratios. For each angle pair identified, one can determine a pre-contingency phase angle
difference threshold to ensure sufficient damping ratio is maintained post-contingency for the critical contingency
studied. For example, if a 2% post-contingency damping ratio is defined as the limit, then each angle difference
pair, or more likely selected critical phase angle pairs, can be assigned a phase angle limit as well.
Figure 32: Post-Contingency Damping Ratio and Phase Angle Difference [Source: BPA]
NERC | Phase Angle Monitoring | June 2016
34
References
[1]
Federal Energy Regulatory Commission, “Final Report on the August 14, 2003 Blackout in the United
States and Canada: Causes and Recommendations,” U.S.-Canada Power System Outage Task Force, Apr
2004. [Online]. Available:
http://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/BlackoutFinal-Web.pdf.
[2]
Federal Energy Regulatory Commission, “Arizona-Southern California Outages on September 8, 2011:
Causes and Recommendations,” FERC and NERC Staff, Apr 2012. [Online]. Available:
https://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-nerc-report.pdf.
[3]
M. J. Thompson, “Fundamentals and Advancements in Generator Synchronizing Systems,” Schweitzer
Engineering Laboratories, Inc., 2012 Texas A&M Conference for Protective Relay Engineers, 2012.
[4]
NERC Reliability Standard. FAC-010-2.1: System Operating Limits Methodology for the Planning Horizon.
Atlanta, GA. [Online]. Available:
http://www.nerc.com/pa/stand/Pages/ReliabilityStandardsUnitedStates.aspx?jurisdiction=United States
[5]
NERC Reliability Standard. FAC-011-2: System Operating Limits Methodology for the Operations Horizon.
Atlanta, GA. [Online]. Available:
http://www.nerc.com/pa/stand/Pages/ReliabilityStandardsUnitedStates.aspx?jurisdiction=United States
[6]
Western Electricity Coordinating Council, “Path Rating Process,” Salt Lake City, 2015. [Online]. Available:
https://www.wecc.biz/PlanningServices/Pages/PathRatingProcess.aspx
[7]
OSIsoft PI System. [Online]. Available: https://www.osisoft.com/Default.aspx
[8]
D. Kosterev, C. Taylor, W. Mittelstadt, “Model Validation for the August 10, 1996 WSCC System Outage,”
IEEE Trans. on Power Systems, vol. 14, no. 3, pgs. 967-979, 1999.
[9]
D. Kosterev, “Composite Load Model Development and Implementation,” NERC-DOE FIDVR Conference,
Alexandria, VA, September 2015.
[10]
WECC, “Modes of Inter-Area Power Oscillations in Western Interconnection,” Salt Lake City, UT, Nov. 30
2013. [Online]. Available: https://www.wecc.biz/Reliability/WECC%20JSIS%20Modes%20of%20InterArea%20Oscillations-2013-12-REV1.1.pdf.
[11]
D. Brancaccio, “Peak Reliability Synchrophasor Project (PRSP),” WECC JSIS Meeting, March 2015.
[Online]. Available: https://www.wecc.biz/Administrative/Dan%20Brancaccio%20%20JSIS%2003-0315%20PRSP.PDF.
[12]
D. Trudnowski, J. Pierre, N. Zhou, J. Hauer, M. Parashar, “Performance of Three Mode-Meter BlockProcessing Algorithms for Automated Dynamic Stability Assessment,” IEEE Trans. on Power Systems, vol.
23, no. 2, pgs. 680-690, 2008.
NERC | Phase Angle Monitoring | June 2016
35
Appendix A – Utility Practices
Peak Reliability Coordinator (Peak Reliability)
Peak RC is planning three phases to implement the angular separation correlation study and baselining project.
1. Identify a list of sensible phase angle pairs that provide strong indication of system power transfer stress
on WECC Paths, IROL-related, and other cut planes for reliable operation monitoring. By leveraging use of
both PMU and EMS data in PI Historian, Peak will develop preliminary thresholds for alarming angular
separation exceedance.
2. Perform in-depth offline studies using current EMS applications’ SE/RTCA and Sensitivity Calculator, plus
voltage stability analysis, transient stability, small signal stability analysis and oscillation detection, etc. to
gain a better understanding of angular separation limits, implications of angle exceedances, and
actionable measures to mitigate the large angle separation.
3. Employ “Big Data” techniques to leverage historical PMU and EMS data, operation study results, real-time
transfer analysis (e.g. ATC and different real-time system stability analysis results, etc.) to calculate and
verify the angle separation limits.
California ISO (CAISO)
At CAISO, system operators are currently provided the pre-contingency and post-contingency angle differences
computed using State Estimator solutions and using PMU data. These are available to the operators in the EMS
display and allow operators to:
1. Know what is the existing SE and PMU based phase angle difference across the terminals of a line and
what is the synch-check relay setting for the corresponding line. This information is displayed to the
operators on substation onelines where the synch-check relay resides allowing operators to make an
informed decision on when it is safe to close in the breakers at the terminals of a line that is currently out.
In addition, operators are also provided approved mitigation steps in the same oneline next to the phase
angle differences allowing operators to take quick actions in the event an outaged line is to be brought
back into service.
2. Know what would be the SE based phase angle difference following a credible contingency and how the
post-contingency phase angle difference would compare to the synch-check relay setting for the
corresponding line. This would provide operators with an indication of system stress following the loss of
a line and if any pre-contingency actions are necessary to mitigate the effects of the monitored
contingencies.
Arizona Public Service (APS)
APS has recently upgraded the operators’ real-time tools (State Estimator and Real Time Contingency Analysis
application) to incorporate phase angle differences in the contingency results. APS trains all system operators to
reliably identify and address large phase angle differences, including any coordination with neighbors or the RC.
APS system operators are provided the pre-contingency and post-contingency angle differences using State
Estimator solutions and PMU data to improve operational situational awareness. Currently APS has 23 pairs of
PMU phase angle differences within its EMS and 103 open-ended BES angles programmed in its Contingency
Analysis.
These angle differences are available in EMS and allow the operator to:
1. Know what is the existing SE and PMU-based phase angle difference across the terminals of a line and
compare it to the synch-check relay setting for the corresponding line terminal breakers.
NERC | Phase Angle Monitoring | June 2016
36
Appendix A – Utility Practices
2. Know what would be the SE-based phase angle difference following a credible contingency and how the
post-contingency phase angle difference would compare to the synch-check relay setting for the
corresponding line.
APS has implemented a Geo-spatial Visualization System (GVS) which allows for visualizing PMU data and SE/RTCA
contingency results. A key attribute of this application is that it will geo-spatially display angle differences on the
Control Center Wall display and/or operator console. If phase angle difference across the terminals of an open
line is exceeding synch-check relay settings then a visual alarm is generated.
Salt River Project (SRP)
SRP has expanded their contingency set with thirty-six (36) new open-ended 500kV line contingencies. Therefore,
system operators are currently provided with pre- and post-contingency angle differences computed using the
State Estimator solutions. These are available to the operators in the EMS display and allow operators to:
1. Know what the existing SE phase angle difference across the terminals of a line are and what the synchcheck relay setting for the corresponding line is.
2. Make informed decisions on when it is safe and allowable to close in the breakers at the terminals of a
line that is currently out of service.
3. Be warned/alarmed if phase angle difference across the terminals of an open line is approaching or
exceeding synchro-check relay settings.
Currently, engineers are preparing mitigation steps allowing operators to take quick actions in the event an
outaged line is to be brought back into service.
SRP is also working towards providing appropriate PMU data to operators, enabling monitoring of phase angle
differences explained in (1) in near real-time fashion. This would also help operators to be more familiar with the
fact that phase angle difference is an excellent indicator of power system stress.
San Diego Gas & Electric (SDG&E)
SDG&E transmission operators have situational awareness when closing transmission lines with closing angle
limits. The operators know where closing angle limits are entered/displayed in the real-time tool, and are aware
that these limits should always be enforced for monitoring in the base case (SE solution) and contingency case
(power flow). RTCA displays the voltage angle difference when the closing angle limit is exceeded.
SDG&E sends certain PMU measurements to Peak RC and CAISO. CAISO calculates the phase angle differences
and sends them to SDG&E via ICCP and these angle differences are displayed on an EMS screen. For example, the
voltage angle for the 500kV North Gila bus is provided by APS to the CAISO, and SDG&E provides the Imperial
Valley 500kV bus voltage angle. The CAISO calculates the difference and provides this data to APS and SDG&E for
monitoring and when closing the Imperial Valley – North Gila 500kV line. There is no need to wait for this line to
be energized to become aware of the actual angle difference as measured on the breakers.
Currently SDG&E is measuring voltage phase angles at every 230 kV and 500 kV bus and values are archived in SEL
SynchroWAVe Central and OSIsoft PI database at 30 samples per second. Phase angle differences are also provided
in SynchroWAVe application to operating engineers. Engineers can look at the angles using graphical displays.
SDG&E also records unwrapped phase angles at specific buses along with the wrapped phase angles. Unwrapped
phase angles are shown to be valuable in calculating frequency and identifying frequency events.
NERC | Phase Angle Monitoring | June 2016
37