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Christopher Ott
Christopher Ott
·Posted in Home
Mon, Aug 12

Navigating CIP-014 Version 4: What's Changing and What It Means for Transmission Stations

Anticipation is growing around the release of version 4 of the NERC CIP-014 standard, which is expected to broaden the criteria under which locations fall within the CIP-014 eligibility scope.

This standard, designed to enhance the security of transmission station locations in the bulk electric system and bulk power system, aims to prevent catastrophic cascading outages from the failure of single or multiple components.

Here's what you need to know about the anticipated changes and how they might impact operations.

 

Focus on Transmission Stations

The purpose of CIP-014 has always been to secure transmission station locations to prevent widespread outages. With the upcoming version 4, many utilities have urged NERC to provide clearer criteria for determining which locations are in scope. Significant changes are expected, particularly to Requirement R1.

 

Clarifications Being Made to R1
  1. Methodology for Studying Instability: Clearer guidelines on assessing instability and uncontrolled separation within an interconnection will be provided.
  2. Assessment Cases: The study period and base cases used by transmission owners to avoid discrepancies will be aligned.
  3. Scenarios and Study Assumptions: The scenarios and assumptions which are considered appropriate and reasonable will be defined.
  4. Adjacent Transmission Stations: Stations with different ownership or those within line-of-sight of each other will be accounted for.
 
Additional Requirements

In addition to the clarifications, R1 will be broken out into additional requirements. The new requirements are outlined below:

R1 Applicability: Assessments schedule will be every 36 months.

R2 Proximity Criteria: Transmission owners must define how they handle proximity, including a definition of line-of-sight and criteria for single events affecting multiple stations.

R3 Methodology: Each transmission owner must have a functional and documented methodology with defined criteria for stability studies and various fault simulations.

3.1 - Rationale for determining acceptable load loss, generation loss and post-event response.

  • 3.1.1 - List of conditions to monitor.
  • 3.1.2 - Document thresholds for load loss and acceptable generation loss.

3.2 - Requirement for dynamic and steady state simulations for each applicable substation.

3.3 - Fault simulations.

  • 3.3.1 - Bolted 3-phase fault at highest voltage level for single stations.
  • 3.3.2 - Single-phase fault at highest voltage level for single stations.

3.4 - Loss of communications and system protections.

  • 3.4.1 - Delayed clearing unless otherwise justified.
  • 3.4.2 - Use of actual instead of generic clearing times – unless otherwise justified.

R4 Coordination of Jointly Owned Facilities: Transmission owners are required to coordinate with other owners of jointly owned stations to determine responsibilities for risk assessments.

R5 Conducting the Risk Assessment: Previously set at 30 months, risk assessments will now need to be preformed every 36 months. This change better aligns with the model-building requirements in other NERC standards. If a station is classified as critical, then it does not need additional assessments to see if it falls into scope. Identification of the associated primary control center for each in-scope station will be unchanged.

 

When Will it Change?

These changes are anticipated to become enforceable and effective 24 months after approval, with CIP-014-4 set to supersede CIP-014-3.

 

 

Article originally published on the POWER Engineers website.Â