To ensure that System Operating Limits (SOLs) used in the reliable operation of the Bulk Electric System (BES) are determined based on an established methodology or methodologies.
4.1. Reliability Coordinator
5. Effective Date: See Implementation Plan for the Revised Definition of “Remedial Action Scheme”.
R1. The Reliability Coordinator shall have a documented methodology for use in developing SOLs (SOL Methodology) within its Reliability Coordinator Area. This SOL Methodology shall:
R1.1. Be applicable for developing SOLs used in the operations horizon.
R1.2. State that SOLs shall not exceed associated Facility Ratings.
R1.3. Include a description of how to identify the subset of SOLs that qualify as IROLs.
R2. The Reliability Coordinator’s SOL Methodology shall include a requirement that SOLs provide BES performance consistent with the following:
R2.1. In the pre-contingency state, the BES shall demonstrate transient, dynamic and voltage stability; all Facilities shall be within their Facility Ratings and within their thermal, voltage and stability limits. In the determination of SOLs, the BES condition used shall reflect current or expected system conditions and shall reflect changes to system topology such as Facility outages.
R2.2. Following the single Contingencies1 identified in Requirement 2.2.1 through Requirement 2.2.3, the system shall demonstrate transient, dynamic and voltage stability; all Facilities shall be operating within their Facility Ratings and within their thermal, voltage and stability limits; and Cascading or uncontrolled separation shall not occur.
R2.2.1. Single line to ground or 3-phase Fault (whichever is more severe), with Normal Clearing, on any Faulted generator, line, transformer, or shunt device.
R2.2.2. Loss of any generator, line, transformer, or shunt device without a Fault.
R2.2.3. Single pole block, with Normal Clearing, in a monopolar or bipolar high voltage direct current system.
R2.3. In determining the system’s response to a single Contingency, the following shall be acceptable:
R2.3.1. Planned or controlled interruption of electric supply to radial customers or some local network customers connected to or supplied by the Faulted Facility or by the affected area.
R2.3.2. Interruption of other network customers, (a) only if the system has already been adjusted, or is being adjusted, following at least one prior outage, or (b) if the real-time operating conditions are more adverse than anticipated ithe corresponding studies
R2.3.3. System reconfiguration through manual or automatic control or protection actions.
R2.4. To prepare for the next Contingency, system adjustments may be made, including changes to generation, uses of the transmission system, and the transmission system topology.
R3. The Reliability Coordinator’s methodology for determining SOLs, shall include, as a minimum, a description of the following, along with any reliability margins applied for each:
R3.1. Study model (must include at least the entire Reliability Coordinator Area as well as the critical modeling details from other Reliability Coordinator Areas that would impact the Facility or Facilities under study.)
R3.2. Selection of applicable Contingencies
R3.3. A process for determining which of the stability limits associated with the list of multiple contingencies (provided by the Planning Authority in accordance with FAC014 Requirement 6) are applicable for use in the operating horizon given the actual or expected system conditions.
R3.3.1. This process shall address the need to modify these limits, to modify the list of limits, and to modify the list of associated multiple contingencies.
R3.4. Level of detail of system models used to determine SOLs.
R3.5. Allowed uses of Remedial Action Schemes.
R3.6. Anticipated transmission system configuration, generation dispatch and Load level
R3.7. Criteria for determining when violating a SOL qualifies as an Interconnection Reliability Operating Limit (IROL) and criteria for developing any associated IROL T v .
R4. The Reliability Coordinator shall issue its SOL Methodology and any changes to that methodology, prior to the effectiveness of the Methodology or of a change to the Methodology, to all of the following:
R4.1. Each adjacent Reliability Coordinator and each Reliability Coordinator that indicated it has a reliability-related need for the methodology.
R4.2. Each Planning Authority and Transmission Planner that models any portion of the Reliability Coordinator’s Reliability Coordinator Area
R4.3. Each Transmission Operator that operates in the Reliability Coordinator Area.
M1. The Reliability Coordinator’s SOL Methodology shall address all of the items listed in Requirement 1 through Requirement 3.
M2. The Reliability Coordinator shall have evidence it issued its SOL Methodology, and any changes to that methodology, including the date they were issued, in accordance with Requirement 4.
1. Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization
1.2. Compliance Monitoring Period and Reset Time Frame
Each Reliability Coordinator shall self-certify its compliance to the Compliance Monitor at least once every three years. New Reliability Authorities shall demonstrate compliance through an on-site audit conducted by the Compliance Monitor within the first year that it commences operation. The Compliance Monitor shall also conduct an onsite audit once every nine years and an investigation upon complaint to assess performance.
The Performance-Reset Period shall be twelve months from the last non-compliance.
1.3. Data Retention
The Reliability Coordinator shall keep all superseded portions to its SOL Methodology for 12 months beyond the date of the change in that methodology. In addition, entities found non-compliant shall keep information related to the non-compliance until found compliant
The Compliance Monitor shall keep the last audit and all subsequent compliance records.
1.4. Additional Compliance Information
The Reliability Coordinator shall make the following available for inspection during an on-site audit by the Compliance Monitor or within 15 business days of a request as part of an investigation upon complaint:
1.4.1 SOL Methodology.
1.4.2 Superseded portions of its SOL Methodology that had been made within the past
1.4.3 Evidence that the SOL Methodology and any changes to the methodology that
occurred within the past 12 months were issued to all required entities.
2. Levels of Non-Compliance for Western Interconnection: (To be replaced with VSLs once developed and approved by WECC):
2.1. Level 1: There shall be a level one non-compliance if either of the following conditions exists
2.1.1 The SOL Methodology did not include a statement indicating that Facility Ratings shall not be exceeded.
2.2. Level 2: The SOL Methodology did not include a requirement to address all of the elements in R3.1, R3.2, R3.4 through R3.7 and E1.
2.3. Level 3: There shall be a level three non-compliance if any of the following conditions exists:
2.3.1 The SOL Methodology did not include a statement indicating that Facility Ratings shall not be exceeded and the methodology did not include evaluation of system response to one of the three types of single Contingencies identified in R2.2.
2.3.2 The SOL Methodology did not include a statement indicating that Facility Ratings shall not be exceeded and the methodology did not include evaluation of system response to two of the seven types of multiple Contingencies identified in E1.1.
2.3.3 The System Operating Limits Methodology did not include a statement indicating that Facility Ratings shall not be exceeded and the methodology did not address two of the six required topics in R3.1, R3.2, R3.4 through R3.7.
2.4. Level 4: The SOL Methodology was not issued to all required entities in accordance with R4.
1. The following Interconnection-wide Regional Difference shall be applicable in the Western Interconnection:
1.1. As governed by the requirements of R3.3, starting with all Facilities in service, shall require the evaluation of the following multiple Facility Contingencies when establishing SOLs:
1.1.1 Simultaneous permanent phase to ground Faults on different phases of each of two adjacent transmission circuits on a multiple circuit tower, with Normal Clearing. If multiple circuit towers are used only for station entrance and exit purposes, and if they do not exceed five towers at each station, then this condition is an acceptable risk and therefore can be excluded.
1.1.2 A permanent phase to ground Fault on any generator, transmission circuit, transformer, or bus section with Delayed Fault Clearing except for bus sectionalizing breakers or bus-tie breakers addressed in E1.1.7
1.1.3 Simultaneous permanent loss of both poles of a direct current bipolar Facility without an alternating current Fault.
1.1.4 The failure of a circuit breaker associated with a Remedial Action Scheme to operate when required following: the loss of any element without a Fault; or a permanent phase to ground Fault, with Normal Clearing, on any transmission circuit, transformer or bus section.
1.1.5 A non-three phase Fault with Normal Clearing on common mode Contingency of two adjacent circuits on separate towers unless the event frequency is determined to be less than one in thirty years.
1.1.6 A common mode outage of two generating units connected to the same switchyard, not otherwise addressed by FAC-011.
1.1.7 The loss of multiple bus sections as a result of failure or delayed clearing of a bus tie or bus sectionalizing breaker to clear a permanent Phase to Ground Fault.
1.2. SOLs shall be established such that for multiple Facility Contingencies in E1.1.1 through E1.1.5 operation within the SOL shall provide system performance consistent with the following:
1.2.1 All Facilities are operating within their applicable Post-Contingency thermal, frequency and voltage limits.
1.2.2 Cascading does not occur.
1.2.3 Uncontrolled separation of the system does not occur.
1.2.4 The system demonstrates transient, dynamic and voltage stability
1.2.5 Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall security of the interconnected transmission systems.
1.2.6 Interruption of firm transfer, Load or system reconfiguration is permitted through manual or automatic control or protection actions.
1.2.7 To prepare for the next Contingency, system adjustments are permitted, including changes to generation, Load and the transmission system topology when determining limits.
1.3. SOLs shall be established such that for multiple Facility Contingencies in E1.1.6 through E1.1.7 operation within the SOL shall provide system performance consistent with the following with respect to impacts on other systems:
1.3.1 Cascading does not occur.
1.4. The Western Interconnection may make changes (performance category adjustments) to the Contingencies required to be studied and/or the required responses to Contingencies for specific facilities based on actual system performance and robust design. Such changes will apply in determining SOLs.
- The Contingencies identified in FAC-011 R2.2.1 through R2.2.3 are the minimum contingencies that must be studied but are not necessarily the only Contingencies that should be studied ↩