Seasonal Assessments and Modeling of Sub-100 kv Elements (Southwest Outage Recommendations 5, 6, 7 and NERC2) May 7, 2014

Transcription

1 Seasonal Assessments and Modeling of Sub-100 kv Elements (Southwest Outage Recommendations 5, 6, 7 and NERC2) May 7, 2014 Background In April 2012, the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) issued the joint report, Arizona-Southern California Outages on September 8, 2011 (Outage Report). The sequence of events and causes of the Arizona-Southern California outages were illustrated in the Outage Report. The report also presented 27 key findings and recommendations aimed at improving power system reliability. This proposal concentrates on recommendations 5, 6, and 7 of the Outage Report. Recommendation 5: WECC RE should ensure better integration and coordination of the various subregions seasonal studies for the entire WECC system. To ensure a thorough seasonal planning process, at a minimum, WECC RE should require a full contingency analysis of the entire WECC system, using one integrated seasonal study, and should identify and eliminate gaps between subregional studies. Individual [Transmission Operators] TOPs should also conduct a full contingency analysis to identify contingencies outside their own systems that can impact the reliability of the [Bulk Power System] BPS within their system and should share their seasonal studies with TOPs shown to affect or be affected by their contingencies. Recommendation 6: TOPs should expand the focus of their seasonal planning to include external facilities and internal and external sub-100 kv facilities that impact BPS reliability. Recommendation 7: TOPs should expand the cases on which they run their individual planning studies to include multiple base cases, as well as generation maintenance outages and dispatch scenarios during high load shoulder periods. To address the Outage Report recommendations, the Western Electricity Coordinating Council (WECC) issued several recommended NERC activities in the September 28, 2012 report, Response to the Arizona-Southern California Outages on September 8, Approved by the Planning Committee June 11, 2014.

2 The recommended NERC activities which specifically responded to recommendations 5, 6, and 7 of the Outage Report included Sub-100-kV Elements (NERC2). NERC2: To maintain consistency continent-wide, WECC recommends that NERC identify technically-based criteria for identifying which sub-100-kv elements must be modeled in the real-time, next day, seasonal, and near- and long-term horizons. NERC should also identify technically-based criteria for which sub-100-kv elements should be included in the Bulk Electric System. Such criteria must be consistent with any FERC-approved definition of the Bulk Electric System, and should clarify which facilities may be included through any FERC-approved exception process. The System Analysis and Modeling Subcommittee (SAMS) and Modeling Working Group (MWG) were tasked with providing the Planning Committee with guidance on addressing recommendations 5, 6, and 7 of the Outage Report and WECC recommended NERC activity NERC2. SAMS/MWG Assessment Although the Outage Report as written directly addresses WECC TOPs, the issues raised by the recommendations are applicable to all NERC Regions. The recommendations cover the network to be modeled, dispatch scenarios, load levels, outages, base cases, contingencies to be considered, and integrated and coordinated studies. SAMS and MWG believe that Outage Report recommendations 5, 6, and 7, along with WECC recommended NERC activity NERC2, are addressed for all Regions as follows: Outage Report Recommendation 5 (recommendation 5) SAMS and MWG identified the following key components for coordination of seasonal studies in recommendation 5: TOPs should utilize an integrated study model that allows reliability impacts to be identified and coordinated between affected TOPs and RCs; and TOPs should collaborate to identify contingencies outside of their systems which can impact reliability internal to their areas. As established above, SAMS and MWG found that recommendation 5 indicates TOPs should utilize an integrated study model that allows reliability impacts to be identified and coordinated between affected TOPs and RCs. Presently, TOPs establish SOLs (as directed by the Reliability Coordinator) for [their] portion of the Reliability Coordinator Area that are consistent with [their] Reliability Coordinator s SOL methodology, pursuant to FAC-014-2, Requirement R2. To comply with the Reliability Coordinator s SOL methodology, a study model that include[s] 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 (FAC-011-2, Requirement R3/R3.1), must be used by Seasonal Assessments and Modeling of Sub-100 kv Elements 2

3 TOPs to conduct their seasonal studies. SAMS and MWG believe that the study model described in FAC results in an integrated study model that is coordinated amongst TOPs and RCs. Additionally, proposed standard TOP-002-3, Requirement R2, requires each TOP to plan to operate within each Interconnection Reliability Operating Limit (IROL) and each System Operating Limit (SOL), in accordance with their Operational Planning Analysis 1. Since the SOLs and IROLs determined by the Operational Planning Analysis must be consistent with the Reliability Coordinator s SOL Methodology 2, the use of the FAC integrated study model is required by TOP Therefore, TOP-002-3, which also applies to the operations planning time horizon, also supports the first goal of recommendation 5 to ensure better integration and coordination of the various subregions seasonal studies as required by an interconnection. The second key component of recommendation 5 indicates that TOPs should collaborate to identify contingencies outside of their system which can impact reliability internal to their areas. The existing standard TOP b, Requirement R6, requires TOPs to plan to meet unscheduled changes in system configuration and generation dispatch (at a minimum N-1 Contingency planning) in accordance with NERC, Regional Reliability Organization, subregional, and local reliability requirements. The proposed standard TOP-002-3, Requirement R1 (which would supersede the above standard), states that Each Transmission Operator shall have an Operational Planning Analysis that represents projected System conditions that will allow it to assess whether the planned operations for the next day within its Transmission Operator Area will exceed any of its Facility Ratings or Stability Limits during anticipated normal and Contingency event conditions. Additionally, as a component of the Operational Planning Analysis, TOPs are required to develop a plan to operate within each SOL and IROL that supports reliability internal to its TOP Area (TOP-002-3, Requirement R2). These SOLs and IROLs need to be respected when evaluating normal and Contingency event conditions as part of the Operational Planning Analysis. Contingencies, both internal and external to a TOP Area must be evaluated to fully assess SOLs, IROLs, Facility Ratings, and Stability Limits associated with a TOP s operations. Furthermore, since the above requirements apply to identification of any exceedance of applicable Facility Ratings, Stability Limits, SOLs, and IROLs, the normal and Contingency event conditions to be evaluated should be consistent with the SOL Methodology described in FAC-011-2, Requirement R2. Additionally, FAC-011-2, Requirement R2, requires TOPs to evaluate all normal conditions and single Contingencies, which include, Single line to ground or 3-phase Fault [conditions] (whichever is more severe), with Normal Clearing, on any Faulted 1 Operational Planning Analysis - An analysis of the expected system conditions for the next day s operation. (That analysis may be performed either a day ahead or as much as 12 months ahead.) Expected system conditions include things such as load forecast(s), generation output levels, and known system constraints (transmission facility outages, generator outages, equipment limitations, etc.). Glossary of Terms Used in NERC Reliability Standards, (July 22, 2013) 2 As described above. Seasonal Assessments and Modeling of Sub-100 kv Elements 3

4 generator, line, transformer, or shunt device. This contingency analysis also evaluates both internal and external reliability impacts, as TOPs are required to demonstrate [that each TOP Area maintains] transient, dynamic and voltage stability; all Facilities [are planned to] operate within their Facility Ratings and within their thermal, voltage and stability limits; and [that] Cascading or uncontrolled separation shall not occur. Together, the requirements in the above TOP and FAC standards address the second key component of recommendation 5, for TOPs to identify contingencies outside of their system that can impact reliability internal to their areas. Finally, sharing of seasonal studies is covered through the following standard requirements. FAC-014-2, Requirement R5 ensures that SOLs and IROLs are shared amongst Reliability Coordinators (as appropriate), TOPs, Transmission Service Providers, Transmission Planners, and Planning Coordinators. TOP b, Requirement R4 requires each Transmission Operator [to] coordinate (where confidentiality agreements allow) its seasonal planning and operations with neighboring Transmission Operators." MWG and SAMS believe that this requirement facilitates TOP sharing of information such as seasonal studies. In the mapping document for Project Realtime Operations, TOP b, Requirement R4 is proposed for retirement and replaced by TOP-003-2, Requirement R1, which requires TOPs to create specifications for data and information needed to support its Operational Planning Analyses. TOP-003-2, Requirement R5 obligates other TOPs to provide the requested data and information as defined in TOP-003-2, Requirement R1. The above requirements allow TOPs to coordinate seasonal studies and share their seasonal studies with TOPs shown to affect or be affected by their contingencies. As a result the goal of recommendation 5 is met. However, SAMS and MWG recommend that TOPs share the results of their seasonal studies with all affected TOPs and RCs, even if a seasonal study is not requested by an affected TOP/RC, pursuant to proposed standard TOP Outage Report Recommendation 6 (recommendation 6) and NERC2 Recommendation 6 requests that TOPs include 1) external facilities, and 2) internal and external sub- 100 kv facilities that impact BPS reliability in their seasonal planning efforts. Similarly, recommendation NERC2 requests that NERC identify criteria for inclusion of sub-100 kv facilities that should be modeled in real-time, next-day, seasonal, and planning studies. External facilities rated above 100 kv that impact reliability are already included in study models, as explained in the SAMS/MWG proposal for meeting the goals of recommendation 5 above. SAMS and MWG believe that a NERC-wide criteria for which sub-100-kv elements should be modeled and assessed is not appropriate due to regional differences. Therefore, SAMS and MWG recommend that Transmission Planners and Planning Coordinators (Planning Authorities) conduct periodic assessments to identify sub-100 kv facilities either internal or external to their area that impact BES reliability of their system. Any sub-100 kv facilities identified in periodic assessments should be Seasonal Assessments and Modeling of Sub-100 kv Elements 4

5 modeled in long-term planning models, and also be submitted to applicable TOPs and RCs for consideration to be included in their studies. SAMS and MWG believe that this response addresses recommendation 6 and NERC2. Outage Report Recommendation 7 (recommendation 7) Existing standard TOP b, Requirement R5 states that [e]ach Transmission Operator shall plan to meet scheduled system configuration, generation dispatch, interchange scheduling and demand patterns. The requirement covers recommendation 7 from the perspective of base case parameters such as, modeling system configurations, generation dispatch, and load scenarios. However, it does not explicitly mention modeling of dispatch scenarios specific to high load shoulder periods. Proposed standard TOP-002-3, Requirement R1, requires TOPs to conduct an Operational Planning Analysis that considers the following base case parameters that should be used to conduct simulations, which meet the reliability goal of recommendation 7: Transmission and generation outages; Load forecasts(s); and Planned dispatch scenarios (i.e., generation output levels). Although neither the existing standard TOP b nor the proposed standard TOP specifically mention modeling of high load shoulder periods, SAMS and MWG recommend that such scenarios may need to be modeled in order to satisfy these requirements in the standards. As the proposed standard does not specifically mention projected power transfers (interchange scheduling), SAMS and MWG recommend that Regions and TOPs clarify their study procedures, as applicable to incorporate these study parameters. Additionally, SAMS and MWG recommend that base case parameters such as load forecasts incorporating load Mvar/power factor data and reactive resource schedules, should be included in study models consistent with VAR and proposed VAR Conclusions and Recommendations In conclusion SAMS and MWG recommend the current or proposed standards described above, in general address the Outage Report recommendations 5, 6, 7 and NERC2. However, SAMS and MWG recommend that Regions and TOPs develop their own specific guidelines as needed to address the following enhancements: TOPs should share the results of their seasonal studies with all affected TOPs and RCs, pursuant to standard TOP-003-2; SAMS and MWG believe that a NERC-wide criteria for which sub-100-kv elements should be modeled and assessed is not appropriate due to regional differences. Therefore, SAMS and Seasonal Assessments and Modeling of Sub-100 kv Elements 5

6 MWG recommend that Transmission Planners and Planning Coordinators (Planning Authorities) conduct periodic assessments to identify sub-100 kv facilities either internal or external to their area that impact BES reliability of their system. Any sub-100 kv facilities identified in periodic assessments should be modeled in long-term planning models, and also be submitted to applicable TOPs and RCs for consideration to be included in their studies. Incorporate modeling of scenarios specific to high load shoulder periods relevant to the area under study; Model projected power transfers (interchange scheduling); and Base case parameters such as load forecasts incorporating load Mvar/power factor data and reactive resource schedules, should be included in study models consistent with VAR and proposed VAR Seasonal Assessments and Modeling of Sub-100 kv Elements 6