Phase Angle Monitoring and
Control
For the MISO RSC, OPWG, and OWG
Bob Roddy, Dairyland Power Cooperative
Mark Tiemeier, Xcel Energy
Agenda
 Review September 8, 2011 Arizona/So. California event recommendation
 Review results of FORUM survey
 Review Whitepaper contents
 Phase Angle Difference Assessment
 Affect on MISO operational processes
 Training Needs for operators
 Discuss next steps
Arizona/So. California Event
 September 8, 2011
 Trip of a 500 kV line  Transmission Operator could not reclose line due to a large phase angle difference across the line’s terminals
 Report Recommendation 27: “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.”
Phase Angle Difference Overview
 As power flow increases, the voltage phase angle difference from the sending terminal to the receiving terminal also increases
 System topology also has an affect on the phase angle difference (line outages, lines covering long distances)
 Closing transmission lines unsupervised across a large phase angle could cause large step changes in real power to nearby generators Phase Angle Task Team
 Task Team within the Operations Planning Working Group (OPWG) created to draft whitepaper on phase angle
 Purpose is to address the Recommendation 27 from the Arizona/So. California Event on September 8, 2011
 Introduce a high‐level construct for how MISO and its Transmission Operators (TOPs) could address large phase angle differences and to identify the necessary tools and mitigation strategies to accomplish this task
Phase Angle Monitoring and Control Survey Summary
Information Requested
 In response to “Finding 27: Phase Angle Difference Following Loss of Transmission Line” of the FERC/NERC report on the 9/8/2011 Southwest US blackout.
 Survey regarding the capability to determine the phase angle difference across an open breaker for both pre‐
contingency and post‐contingency conditions.
Survey Participants
 21 Entities responded to 12 questions. From a broad range of utilities throughout the US and Canada.
 Conducted in June and July of 2013 by the North American Transmission Forum (“Forum”) on MISO’s behalf.
 Anyone who is a Forum member can view the details of the survey.
Summary
 32% provide their operators with specific operating guides that address high phase angle concerns.
 50% have either performed or have an RC that has performed off‐line studies to identify potential high phase angle issues on their systems.
 14% are using PMU data to address reclosing of transmission lines with a high phase angle difference between 2 terminals.
 20‐40 degree phase angle settings on synchro‐check relays for auto reclose is common. However, there many special cases with settings as high as 60 degrees.
Summary (Cont’d)
 81% indicated they have synchro‐check supervision to prevent the operator‐initated SCADA close of a breaker with a high phase angle.
 55% provide the operator with “quick” access to the phase angle settings of the synchro‐check relays.
 23% said tools are available and utilized by operators that predict possible high phase angle issues for n‐1
 36% indicated that if a pre‐contingency condition is identified that would prevent a breaker from closing due to high phase angle, they would take pre‐
contingent actions to reduce the angle.
Summary (Cont’d)
 55% indicated that tools are available to the operator to estimate the real‐time phase angle difference across an open breaker from the control center.
 32% indicated that actual angle measurements are available to the operator.
 27% indicated that there is no remote capability to estimate or measure the real‐time phase angle difference.
Summary (Cont’d)
 Actions available to reduce phase angle include:
 Redispatch (primary response)
 Load Management
 Phase Shifter Adjustments
 Load‐shedding
 Start gas turbines
 Reconfigure Transmission System
 If Redispatch, is cost a consideration? Most responded, cost is NOT a consideration, post‐
contingency.
Application of Survey
 The survey information was used by the Adhoc Phase Angle Working Group of the OPWG to develop a whitepaper called “MISO Phase Angle Differences Monitoring and Control”
 Like any FORUM survey, its results are available in detail to all FORUM members.
Phase Angle Monitoring and Control Whitepaper
Whitepaper Overview
 Introduce a high‐level construct for how MISO and its 


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Transmission Operators (TOPs) could address large phase angle differences and to identify the necessary tools and mitigation strategies to accomplish this task
Draft of whitepaper reviewed by the OPWG on 12/5/2013 and was endorsed for review by the OWG
OWG reviewed the draft whitepaper on 1/28/2014 and provided feedback
Whitepaper was revised based on feedback from OWG
Present whitepaper to RSC and solicit feedback to prepare for eventual decision by the RSC
Whitepaper: Phase Angle Difference Identification
 Identify high risk areas for large phase angle differences
 Identification is the foundation of developing operator response and training
 There are several options available to identify risk of large phase angle differences
 Outstanding Question/Discussion Topic: Which option is preferred?
Whitepaper: Option #1 Ad‐Hoc Identification
 Identify at‐risk lines through normal course of operating the power system
 Pros:
 Little additional resource requirements needed
 Resulting operating procedures would be limited to only lines that have a known risk
 Cons
 Does not proactively identify issues
 There would not be specific guidance to operators on how to address an emergent issue
Whitepaper: Option #2 MISO/TOP One‐Year Monitoring Identification
 TOPs would provide a list of facilities to monitor in RTCA for potential phase angle issues. After one‐year of monitoring, MISO and TOP would decided which facilities to analyze further
 Pros:
 Provides real‐time experience over a range of different operating conditions
 Identifies lines truly at risk based on actual synchro‐check relay settings
 Cons:
 Delays identification and assessment for 1 year
 Depends on a list of facilities from TOP
 There would not be specific procedural guidance for results that would be seen by the operators
 Could distract operators from other real‐time duties
Whitepaper: Option #3 Individual TOP Assessment
 Individual TOPs within MISO would conduct their own analysis to assess at‐risk lines
 Pros:
 Analysis would be tailored to the local system to better identify lines at risk
 TOPs can apply their specific synchro‐check relay settings to only identify issues above actual settings
 Cons:
 Inconsistent application of study scope, criteria, process, and frequency
 Potentially inconsistent results across footprint
 Study results will be available at different times making it more difficult to coordinate results into operating procedures
 TOP may decide not to run a study leaving a portion of the MISO footprint unanalyzed
Whitepaper: Option #4 MISO Assessment
 MISO‐wide assessment of lines at risk with Member involvement. Similar to annual seasonal assessment.
 Pros:
 There would be one, consistent approach for identifying at‐risk lines
 Efficient use of resources to only conduct one study for the MISO footprint
 Study results can be more easily transitioned to operating procedures since results would be available at one time
 Cons:
 Additional resources at MISO may be required to conduct analysis
 Study results may have to be verified against actual synchro‐check relay settings
 Additional effort would be required to develop scope for the study
 Still requires some TOP effort to review results and compare them against actual synchro‐check relay settings
Whitepaper: Assessment Criteria and Assumptions
 Criteria to identify “large” phase angle differences should be based on 
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
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synchro‐check relay settings
Varying levels of settings among Transmission Owners within MISO
Mitigation strategies should be based on actual synchro‐check settings at location where large phase angle difference is occuring.
Assessment must include a high transfer analysis to stress the power system and identify the likely large phase angle differences
Consideration should be given to conducting a prior outage analysis as well
Whitepaper: Outage Coordination and Next‐
Day Processes
 Consideration should be given to include a large phase angle difference analysis into the Outage Coordination and Next‐Day study processes
 Goal of these analyses would be to identify trouble spots for real‐time operations and to create operating procedures to address short‐term conditions
 Decision to conduct these analyses should be weighed against available personnel resources
 Outstanding Question: To what level should phase angle analysis be conducted by Outage Coordination? By Next‐Day?
Whitepaper: Real‐Time Operation
 Operating procedures need to be developed to include monitoring of phase angle differences in RTCA runs for at‐
risk lines
 Could be either a global procedure or individualized procedure depending on identification approach taken and results of assessment
 MISO and TOPs, if able, should monitor their RTCA for phase angle difference violations
 Procedures need to include strategies for recognizing large phase angle differences and an operator decision‐making structure based on violations identified in RTCA or the inability to reclose a tripped line due to a large phase angle difference
Whitepaper: Real‐Time Decision‐Making Structure
 Pre‐trip or post‐trip actions could be taken
 Large phase angle difference typically only a concern post trip because the operator will be unable to reclose the line  Therefore, need to limit pre‐trip actions to only situations where the failure to reclose a tripped line due to a large phase angle difference would result in an IROL exceedance following the next contingency (N‐1‐1) and the ability to reposition the power system to mitigate the IROL exceedance
 Real‐time assessment would be needed to determine risk of IROL exceedance post‐trip
Whitepaper: Possible mitigation strategies
 Generation re‐dispatch
 Placing generation on‐line on receiving end of tripped line
 Use of phase‐shifting transformers to reduce power flow (if available)
 Re‐configure system to reduce power flow (if possible)
 Load curtailment (interruptible or firm load shed if necessary)
Whitepaper: Tools and Training
 Several tools can identify phase angle differences
 State Estimators
 Online VSAT
 Phasor Measurement Units
 SCADA measurement
 Training for operators is needed and should include:
 General overview of system physics that cause large phase angle differences
 How to identify large phase angle differences with available tools
 The possible mitigation strategies and when they should be used Next Steps
 Present to the RSC and incorporate feedback – May
 Finalize the whitepaper at the OPWG – TBD
 OPWG to bring a motion to the RSC for MISO to address whitepaper recommendations – TBD
 Develop a high level work plan