Encari attended WECC’s Compliance Open Webinar on July 16, 2015 regarding CIP-014. Below are Encari’s key takeaways.
FERC approved CIP-014-2 on July 14, 2015, with the substantive change being removing the term “widespread.”
Practical examples of CIP-014-2 R1 application will be the policy and your role. As you are the technically educated one, you will essentially be the expert as well as the first and last line of defense. Make sure to get the story straight, to correct the inaccuracies, and to calm the policymakers. You need to make sure to advocate for your industry – to make sure people also get the facts straight.
The purpose of CIP-014 is to identify and protect Transmission stations and Transmission substations, and their associated primary control centers that, if rendered inoperable or damages as a result of a physical attack, could result in widespread instability, uncontrolled separation, or Cascading within an interconnection.
What does “rendered inoperable” mean? Rendered inoperable means no breakers, lines on the ground, buses on the ground, no protection, no communication…
The reality is that a bad person can blow up or fault a substation, all at once with a truck bomb, as well as other methods….but, you can defeat a truck bomb. You just need to make them go somewhere else. It becomes a game of keep away.
Notes on the stations studied and the study methodology that was presented:
Stations Studied:
- Western Rocky Mountain Region determined which facilities to include in the assessment using the Applicability section of CIP-014-1.
- 1.1.1 Transmission facilities operated at 500 kV or higher
- 1.1.2 Transmission facilities that are operating between 200 kV and 499 kV, connected to >=3 other stations with aggregate weighted value >3000
- 1.1.3 Transmission facilities that are identified as critical to the derivation of an IROL
- 1.1.4 Transmission facilities identified as essential to meeting Nuclear Plant Interface Requirements
- RMR’s identified 6 stations for Risk Assessment
Study Methodology:
- Simulations were run assuming the post-contingent condition did not allow for automatic tap changes and reactive devices to operate
- Contingency run initially assuming no SPS of UVLS operation. Following each contingency, transmission lines and transformers that load beyond their relay trip point were removed from service and the simulation was run again. Process was repeated up to two additional times beyond the initial solution. Subsequent runs could utilize SPS/UVLS to mitigate violations or obtain solution.
- SPS/UVLS at other stations were considered active and implemented as needed. SPS/UVLS at the event substation were considered disabled.
- Total amount of load throughout process was tabulated:
- If amount of load loss was less than 1000 MW, continue subsequent tripping of any facility that exceeds trip point.
- If amount load loss was greater than 1000 MW before the last overloaded element is taken out of service or divergence occurs, the facility was deemed a critical facility
- If the process was Simulations were run assuming the post-contingent condition did not allow for automatic tap changes and reactive devices to operate
- Contingency run initially assuming no SPS of UVLS operation. Following each contingency, transmission lines and transformers that load beyond their relay trip point were removed from service and the simulation was run again. Process was repeated up to two additional times beyond the initial solution. Subsequent runs could utilize SPS/UVLS to mitigate violations or obtain solution.
- SPS/UVLS at other stations were considered active and implemented as needed. SPS/UVLS at the event substation were considered disabled.
- Total amount of load throughout process was tabulated:
- If amount of load loss was less than 1000 MW, continue subsequent tripping of any facility that exceeds trip point.
- If amount load loss was greater than 1000 MW before the last overloaded element is taken out of service or divergence occurs, the facility was deemed a critical facility
- If the process was repeated at least 3 times and contributed to result in lines to overload past their expected trip point, this was possible indication of Cascading and study moved to Transient Stability Analysis
- Evaluated loss of entire substation including all voltage levels. Simulated by applying a 3-phase fault to each bus at each station with delayed clearing of 24 cycles
- The following conditions were used as indicators of possible instability
- First swing voltage dips below 0.7 pu for more than 12 cycles
- Frequency below 59.0 Hz for more than 6 cycles
- Negatively damped oscillations
- Only if the first and second condition result in the loss of more than 1000 MW of load or the third condition is not met will the facility under evaluation be determined critical.
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