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Philip Augustin, P.E. Portland General Electric. 1) MOD-025-2 – Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous.

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Presentation on theme: "Philip Augustin, P.E. Portland General Electric. 1) MOD-025-2 – Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous."— Presentation transcript:

1 Philip Augustin, P.E. Portland General Electric

2 1) MOD – Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability (GO, TO*) 2) MOD – Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions (GO, TP) (R1, R3-R6) 3) MOD – Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions (GO, TP) (R1, R3-R5) 1

3  MOD Establishes consistent modeling data requirements and reporting procedures for development of planning horizon cases necessary to support analysis of the reliability of the interconnected transmission system.  MOD Establishes consistent validation requirements to facilitate the collection of accurate data and building of planning models to analyze the reliability of the interconnected transmission system. 2

4 1) PRC – Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection (GO, TO*) 2) PRC – Generator Frequency and Voltage Protective Relay Settings (GO) 3

5 Reliability StandardTitleEffective Date MOD Verification & Data Reporting of Generator Real & Reactive Power Capability & Synchronous Condenser Reactive Power Capability 7/1/ % Verified 7/1/ % Verified 7/1/ % Verified 7/2/ % Verified MOD Verification of Models & Data for Generator Excitation Control System or Plan Volt/VAR Control Functions 7/1/2014 R1, R3 thru R6 7/1/2018 R2, 30% Verified 7/1/2020 R2, 50% Verified 7/1/2024 R2, 100% Verified MOD Verification of Models & Data for Turbine / Governor & Load Control or Active Power / Frequency Control Functions 7/1/2014 R1, R3 thru R5 7/1/2018 R2, 30% Verified 7/1/2020 R2, 50% Verified 7/1/2024 R2, 100% Verified PRC Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls & Protection 7/1/ % Verified 7/1/2017 R1, 60% Verified 7/1/2018 R1, 80% Verified 7/1/2019 R1, 100% Verified PRC Generator Frequency & Voltage Protective Relay Settings 7/1/2016 R1, R2, R3 & R4, 40% Verified 7/1/2017 R1, R2, R3, & R4, 60% Verified 7/1/2018 R1, R2, R3, & R4, 80% Verified 7/1/2019 R1, R2, R3, & R4, 100% Verified 4

6  To Prevent a physical attack from resulting in widespread instability, uncontrolled separation, or Cascading within an Interconnection.  Applicable to TO with substation(s)/switching station(s) operated at 200 kV or higher and has an aggregate “weighted value” of 3000 or more  The collector system of a generation plant is not applicable Voltage Value of a Line Weight Value Per Line Less than 200 kV (not applicable) (not applicable) 200 kV – 299 kV kV- 499 kV kV and above0 5

7 R1. Risk Assessment TO shall perform an initial risk assessment of Transmission stations/ substations (existing and planned to be in service within 24 months). Identify the Transmission station/ substation(s) that if rendered inoperable or damaged could result in widespread instability, uncontrolled separation, or Cascading. Subsequent risk assessments shall be performed:  At least once every 30 months (2 1/2 years) for a TO that identified one or more Transmission station/ substation(s) in their initial risk assessment  At least once every 60 months (5 years) for a TO that has not identified any Transmission stations/ substations in their initial risk assessment. The TO shall identify the primary operational control center for each Transmission station/ substation(s) identified in the R1 risk assessment. 6

8 R2. Third party verification. Each TO shall have an unaffiliated third party verify the risk assessment performed under Requirement R1. The unaffiliated third party verification may include recommendations for the addition or deletion of a Transmission station/ substation(s). The TO shall ensure the verification is completed within 90 calendar days R3. TO-TOP Notification for Primary control center(s) Primary control center(s) that operationally control(s) an identified Transmission station/ substation not under the operational control of the TO: The TO, within seven calendar days following completion of Requirement R2 notify the TOP that of the identification and the date of completion of Requirement R2. R4. Evaluation of the potential threats and vulnerabilities Each TO & TOP shall evaluate threats and vulnerabilities to a physical attack for each of their identified Transmission station(s), substation(s), and primary control center(s) The evaluation shall consider the following:  Unique characteristics of the identified and verified Transmission station(s), Transmission substation(s), and primary control center(s);  Prior history of attack on similar facilities taking into account the frequency, geographic proximity, and severity of past physical security related events; and  Intelligence or threat warnings received from sources such as law enforcement, the Electric Reliability Organization (ERO), the Electricity Sector Information Sharing and Analysis Center (ES-ISAC), U.S. federal and/or Canadian governmental agencies, or their successors. 7

9 R5. Physical Security Plan(s) and Implementation Schedule Within 120 days of completion of requirement R2. Each TO &TOP shall develop and implement a documented physical security plan(s) and implementation schedule for their respective Transmission station/ substation(s) and primary control centers. The physical security plan(s) shall include the following attributes: Resiliency or security measures designed collectively to deter, detect, delay, assess, communicate, and respond to potential physical threats and vulnerabilities identified during the evaluation conducted in Requirement R4. Law enforcement contact and coordination information. A timeline for executing the physical security enhancements and modifications specified in the physical security plan. Provisions to evaluate evolving physical threats, and their corresponding security measures, to the Transmission station(s), Transmission substation(s), or primary control center(s). 8

10 R6. Third party review of the security plan(s) and implementation schedule TO & TOP shall select an unaffiliated third party reviewer with one or more of the following qualifications: An entity or organization with electric industry physical security experience, and whose review staff has at least one member who holds either a Certified Protection Professional (CPP) or Physical Security Professional (PSP) certification. An entity or organization approved by the ERO. A governmental agency with physical security expertise. An entity or organization with demonstrated law enforcement, government, or military physical security expertise. The TO&TOP shall ensure the verification is completed within 90 calendar days If the third party reviewer recommends changes to the evaluation performed threats and vulnerabilities to a physical attack or security plan(s) developed under Requirement R5, the Transmission Owner or Transmission Operator shall, within 60 calendar days of the completion of the unaffiliated third party review, for each recommendation:  Modify its evaluation or security plan(s) consistent with the recommendation; or  Document the reason(s) for not modifying the evaluation or security plan(s) consistent with the recommendation. 9

11 Anticipated ActionsAnticipated Dates 5-day Final Ballot ClosedMay 1, 2014 Anticipated BOT AdoptionMay 15, 2014 Expecting to file with applicable Regulatory Authorities June 5, 2014 Becomes effective the first day of the first calendar quarter 6 months after standard is approved 10

12 During a GMD event, geomagnetically-induced currents (GIC) may cause transformer hot-spot heating or damage, loss of Reactive Power sources, increased Reactive Power demand, and Misoperation, the combination of which may result in voltage collapse and blackout. 11

13 R1. Each PC and TP shall maintain ac System models and geomagnetically-induced current (GIC) System models within its respective area for performing the studies needed to complete its GMD Vulnerability Assessment. Establishes Category P8 as the normal System condition for GMD planning in Table 1. The System models shall include: 1.1. Existing Facilities 1.2. Known outage(s) of generation or Transmission Facility(ies) with a duration of at least six months New planned Facilities and changes to existing Facilities 1.4. Real and reactive Load forecasts 1.5. Known commitments for Firm Transmission Service and Interchange 1.6. Resources (supply or demand side) required for Load 12

14 13

15 R2. Each PC and TP shall complete a GMD Vulnerability Assessment of the Near Term Transmission Planning Horizon for its respective area once every 60 months. This GMD Vulnerability Assessment shall use studies, document assumptions, and document summarized results of the steady state analysis Studies shall include the following conditions: System peak Load for one year within the Near-term Transmission Planning Horizon System Off-Peak Load for one year within the Near-term Transmission Planning Horizon Studies shall be conducted based on the benchmark GMD event described in Attachment 1 to determine 14

16 Attachment 1: Calculating Geoelectric Fields for the Benchmark GMD Event (1) A reference peak geoelectric field amplitude of 8 V/km derived from statistical analysis of historical magnetometer data; (2) Scaling factors to account for local geomagnetic latitude; (3) Scaling factors to account for local earth conductivity; and (4) A reference geomagnetic field time series or waveshape to facilitate time-domain analysis of GMD impact on equipment. 15

17 16  Substation Location and Grounding resistance  Transmission Line Information  Transformer/autotransformer winding resistance

18 R3. If the determination through the GMD Vulnerability Assessment that its System does not meet the performance requirements of Table 1 Each PC and TP shall develop a Corrective Action Plan addressing how the performance requirements will be met. R4. Each PC and TP shall have criteria for acceptable System steady state voltage limits for its System during the GMD conditions described in Attachment 1. 17

19 R5. Each PC, in conjunction with its TP’s shall determine and identify the individual and joint responsibilities of entities in the PC’s area for performing the required studies for the GMD Vulnerability Assessment. R6. Each PC and TP shall distribute its GMD Vulnerability Assessment results and Corrective Action Plan, if any, to adjacent PC, adjacent TP, and TO and GO in its respective planning area within 90 calendar days of completion, and to any functional entity that has a reliability related need and submits a written request for the information within 30 days of such a request. 18

20 R7. Each TO and GO shall conduct an assessment of thermal impact for all of its solely and jointly owned power transformers with high- side, wye-grounded windings connected at 200 kV or higher. The assessment shall: 7.1. Be based on the benchmark GMD event described in Attachment 1 with peak geomagnetically-induced current (GIC) flows 7.2. Document assumptions used in the analysis 7.3. Describe suggested actions and supporting R8. Provide its assessment of thermal impact from R7 within 90 days of completion to the PC and TP with responsibility for the area in which the associated power transformer is located. 19

21  Informal Comment Period Closes 5/21/2014 Anticipated ActionsAnticipated Date 45-day Formal Comment Period with Initial Ballot June day Formal Comment Period with Additional BallotAugust 2014 Final ballotOctober 2014 BOT adoptionNovember

22 Week of May 5: Disturbance Monitoring: PRC (45-day comment period and additional ballot) Week of May 12: Protection System (Misoperations): PRC (45-day comment period and additional ballot) Week of May 19: Periodic Review of BAL-004: Recommendation (45-day comment period, no ballot) Revisions to TOP/IRO Reliability Standards (45-day comment period and initial ballot) Week of May 26: System Protection Coordination: PRC (45-day comment period and additional ballot) BARC: BAL (45-day comment period and additional ballot) 21


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