Overview of Activities Resource... · 2018. 8. 31. · 7 RELIABILITY | ACCOUNTABILITY •R2. The...

Overview of ActivitiesHigh Level Discussion

IRPTF MeetingApril 2018

RELIABILITY | ACCOUNTABILITY2

• Technical discussion points shown here intended ONLY for group discussion, not the “position” or “opinion” of NERC

• Goal is to gather information, have technical discussion, to provide most effective information to our leadership.

Disclaimer


• Disturbances and Actions to Mitigate Risk: Disturbance Report – Blue Cut Fire Alert I Disturbance Report – Canyon 2 Fire Alert I Actions and Follow-up (WECC/NERC) Alert II (coming) Alert II Actions and Follow-up (WECC/NERC, coming)

Overview of Activities


• Reliability Guideline Recommended performance specifications Opportunity to clarify key topics in sufficient detail Need to drive consistency in performance Need to mitigate risks Cornerstone document for progress moving forward No compliance obligation or mandatory requirements for Registered

Entities Intended to be used at face value by industry – strong recommendations



• BPS vs. BES SIGNIFICANT jurisdictional challenge moving forward (something we can

tackle together as an industry in most effective way) Few BES inverter-based resources (decent MW capacity though) Need to drive similar performance reqs/standards for BPS connected Need continued clarification/education for state jurisdictions

• LGIA/SGIA What is being done to cover the < 20 MW resources? What is being done to cover the > 20 MW yet < 75 MW resources? Any standards revisions/modifications will take years to implement.



• Modeling Existing models in the base case(s) are WRONG (in aggregate). Do not capture the large disturbance aspects of inverter-based resources We MUST correct this issue, and asap Linkage the Alert Modeling Notification: Momentary Cessation Model improvements (WECC REMTF – Songzhe) User-written model



• Studies Using user-written model to study momentary cessation – best

representation we have at the moment due to modeling deficiency Studied low inertia, low reserve case (essentially absolute minimum)o Identified potential stability issueso Strong basis and illustration of need to disallow momentary cessation – aligns

with expectations of standards Next studieso Preparation for wildfire season

– Light summer, high renewables, reasonably high transfers– Peak summer, reasonably high renewables, high transfers

o Assurance of interconnection stability o Same study approach – wide set of contingencies, hone in on sensitivities



• Potential Standards Revisions Discussions in IRPTF of struggles and clarity needed in NERC Reliability

Standardso Clarity in existing standards requirementso Clarity in performance (potential future standards/requirements/modifications)

Discussion later this week in more detail



• Education NERC-NATF-EPRI-ESIG Webinar Series Disturbance Report webinar (Rich and Ryan) Industry workshop in Q3/Q4 2018 Potential need for education to the non-BES entities (GO/GOPs), as well as

TO/TOPs Need education to the non-BES, BPS resources to enact change and

educate at that level. Message to manufacturers (IEEE?)


Relevant StandardsOverview and Discussion

IRPTF MeetingApril 2018


• R1. Each Transmission Owner shall document Facility interconnection requirements, update them as needed, and make them available upon request. Each Transmission Owner’s Facility interconnection requirements shall address interconnection requirements for: 1.1. generation Facilities; 1.2. transmission Facilities; and 1.3. end-user Facilities.

FAC-001-2


• R1. Each Transmission Planner and each Planning Coordinator shall study the reliability impact of: (i) interconnecting new generation, transmission, or electricity end-user Facilities and (ii) materially modifying existing interconnections of generation, transmission, or electricity end-user Facilities. The following shall be studied: 1.1. The reliability impact of the new interconnection, or materially

modified existing interconnection, on affected system(s); 1.2. Adherence to applicable NERC Reliability Standards; regional and

Transmission Owner planning criteria; and Facility interconnection requirements;

1.3. Steady-state, short-circuit, and dynamics studies, as necessary, to evaluate system performance under both normal and contingency conditions; and

FAC-002-2


• R3. Each Transmission Owner, each Distribution Provider, and each Load-Serving Entity seeking to interconnect new transmission Facilities or electricity end-user Facilities, or to materially modify existing interconnections of transmission Facilities or electricity end-user Facilities, shall coordinate and cooperate on studies with its Transmission Planner or Planning Coordinator, including but not limited to the provision of data as described in R1, Parts 1.1-1.4.

FAC-002-2


• R4. Each Transmission Owner shall coordinate and cooperate with its Transmission Planner or Planning Coordinator on studies regarding requested new or materially modified interconnections to its Facilities, including but not limited to the provision of data as described in R1, Parts 1.1-1.4.

• R5. Each applicable Generator Owner shall coordinate and cooperate with its Transmission Planner or Planning Coordinator on studies regarding requested interconnections to its Facilities, including but not limited to the provision of data as described in R1, Parts 1.1-1.4.

FAC-002-2


• R1. The Reliability Coordinator shall maintain a documented specification for the data necessary for it to perform its Operational Planning Analyses, Real-time monitoring, and Real-time Assessments. The data specification shall include but not be limited to: 1.1. A list of data and information needed by the Reliability Coordinator to

support its Operational Planning Analyses, Real-time monitoring, and Real-time Assessments including non-BES data and external network data, as deemed necessary by the Reliability Coordinator.

1.2. Provisions for notification of current Protection System and Special Protection System status or degradation that impacts System reliability.

1.3. A periodicity for providing data. 1.4. The deadline by which the respondent is to provide the indicated data.

IRO-010-2(RCs requested/collected data)


• R2. The Reliability Coordinator shall distribute its data specification to entities that have data required by the Reliability Coordinator’s Operational Planning Analyses, Real-time monitoring, and Real-time Assessments.

IRO-010-2


• R1. Each Planning Coordinator and each of its Transmission Planners shall jointly develop steady-state, dynamics, and short circuit modeling data requirements and reporting procedures for the Planning Coordinator’s planning area that include: 1.1. The data listed in Attachment 1. 1.2. Specifications of the following items consistent with procedures for

building the Interconnection-wide case(s): o 1.2.1. Data format; o 1.2.2. Level of detail to which equipment shall be modeled; o 1.2.3. Case types or scenarios to be modeled; and o 1.2.4. A schedule for submission of data at least once every 13 calendar months.

1.3. Specifications for distribution or posting of the data requirements and reporting procedures so that they are available to those entities responsible for providing the data.

MOD-032-1


• R2. Each Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, Transmission Owner, and Transmission Service Provider shall provide steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s) according to the data requirements and reporting procedures developed by its Planning Coordinator and Transmission Planner in Requirement R1. For data that has not changed since the last submission, a written confirmation that the data has not changed is sufficient.

MOD-032-1


• R1. Each Planning Coordinator shall implement a documented data validation process that includes the following attributes: 1.1. Comparison of the performance of the Planning Coordinator’s portion

of the existing system in a planning power flow model to actual system behavior, represented by a state estimator case or other Real-time data sources, at least once every 24 calendar months through simulation;

1.2. Comparison of the performance of the Planning Coordinator’s portion of the existing system in a planning dynamic model to actual system response, through simulation of a dynamic local event, at least once every 24 calendar months (use a dynamic local event that occurs within 24 calendar months of the last dynamic local event used in comparison, and complete each comparison within 24 calendar months of the dynamic local event). If no dynamic local event occurs within the 24 calendar months, use the next dynamic local event that occurs;

MOD-033-1


• R1. Each Planning Coordinator shall implement a documented data validation process that includes the following attributes: 1.3. Guidelines the Planning Coordinator will use to determine

unacceptable differences in performance under Part 1.1 or 1.2; and 1.4. Guidelines to resolve the unacceptable differences in performance

identified under Part 1.3.

MOD-033-1(cont.)


• R1. Each Generator Owner that has generator frequency protective relaying1 activated to trip its applicable generating unit(s) shall set its protective relaying such that the generator frequency protective relaying does not trip the applicable generating unit(s) within the “no trip zone” of PRC-024 Attachment 1, subject to the following exceptions:2

Generating unit(s) may trip if the protective functions (such as out-of-step functions or loss-of-field functions) operate due to an impending or actual loss of synchronism or, for asynchronous generating units, due to instability in power conversion control equipment.

Generating unit(s) may trip if clearing a system fault necessitates disconnecting (a) generating unit(s).

Generating unit(s) may trip within a portion of the “no trip zone” of PRC-024 Attachment 1 for documented and communicated regulatory or equipment limitations in accordance with Requirement R3.

PRC-024-2


• R2. Each Generator Owner that has generator voltage protective relaying1 activated to trip its applicable generating unit(s) shall set its protective relaying such that the generator voltage protective relaying does not trip the applicable generating unit(s) as a result of a voltage excursion (at the point of interconnection3 ) caused by an event on the transmission system external to the generating plant that remains within the “no trip zone” of PRC-024 Attachment 2.4 If the Transmission Planner allows less stringent voltage relay settings than those required to meet PRC-024 Attachment 2, then the Generator Owner shall set its protective relaying within the voltage recovery characteristics of a location-specific Transmission Planner’s study. Requirement R2 is subject to the following exceptions:

PRC-024-2


Generating unit(s) may trip in accordance with a Special Protection System (SPS) or Remedial Action Scheme (RAS).

Generating unit(s) may trip if clearing a system fault necessitates disconnecting (a) generating unit(s).

Generating unit(s) may trip by action of protective functions (such as out-of-step functions or loss-of-field functions) that operate due to an impending or actual loss of synchronism or, for asynchronous generating units, due to instability in power conversion control equipment.

Generating unit(s) may trip within a portion of the “no trip zone” of PRC-024 Attachment 2 for documented and communicated regulatory or equipment limitations in accordance with Requirement R3.

PRC-024-2


• R3. Each Generator Owner shall document each known regulatory or equipment limitation5 that prevents an applicable generating unit with generator frequency or voltage protective relays from meeting the relay setting criteria in Requirements R1 or R2 including (but not limited to) study results, experience from an actual event, or manufacturer’s advice. 3.1. The Generator Owner shall communicate the documented regulatory

or equipment limitation, or the removal of a previously documented regulatory or equipment limitation, to its Planning Coordinator and Transmission Planner within 30 calendar days of any of the following: o Identification of a regulatory or equipment limitation. o Repair of the equipment causing the limitation that removes the limitation. o Replacement of the equipment causing the limitation with equipment that

removes the limitation. Creation or adjustment of an equipment limitation caused by consumption

of the cumulative turbine life-time frequency excursion allowance.

PRC-024-2


• R4. Each Generator Owner shall provide its applicable generator protection trip settings associated with Requirements R1 and R2 to the Planning Coordinator or Transmission Planner that models the associated unit within 60 calendar days of receipt of a written request for the data and within 60 calendar days of any change to those previously requested trip settings unless directed by the requesting Planning Coordinator or Transmission Planner that the reporting of relay setting changes is not required.

PRC-024-2


• 1 Each Generator Owner is not required to have frequency or voltage protective relaying (including but not limited to frequency and voltage protective functions for discrete relays, volts per hertz relays evaluated at nominal frequency, multi-function protective devices or protective functions within control systems that directly trip or provide tripping signals to the generator based on frequency or voltage inputs) installed or activated on its unit.

PRC-024-2


• 2 For frequency protective relays associated with dispersed power producing resources identified through Inclusion I4 of the Bulk Electric System definition, this requirement applies to frequency protective relays applied on the individual generating unit of the dispersed power producing resources, as well as frequency protective relays applied on equipment from the individual generating unit of the dispersed power producing resource up to the point of interconnection.

• 3 For the purposes of this standard, point of interconnection means the transmission (high voltage) side of the generator step-up or collector transformer.

PRC-024-2


• 4 For voltage protective relays associated with dispersed power producing resources identified through Inclusion I4 of the Bulk Electric System definition, this requirement applies to voltage protective relays applied on the individual generating unit of the dispersed power producing resources, as well as voltage protective relays applied on equipment from the individual generating unit of the dispersed power producing resource up to the point of interconnection.

• 5 Excludes limitations that are caused by the setting capability of the generator frequency and voltage protective relays themselves but does not exclude limitations originating in the equipment that they protect.

PRC-024-2


• R1. Each Transmission Operator shall maintain a documented specification for the data necessary for it to perform its Operational Planning Analyses, Real-time monitoring, and Real-time Assessments. The data specification shall include, but not be limited to: [Violation Risk Factor: Low] [Time Horizon: Operations Planning] 1.1. A list of data and information needed by the Transmission Operator to

support its Operational Planning Analyses, Real-time monitoring, and Real-time Assessments including non-BES data and external network data as deemed necessary by the Transmission Operator.

1.2. Provisions for notification of current Protection System and Special Protection System status or degradation that impacts System reliability.

1.3. A periodicity for providing data. 1.4. The deadline by which the respondent is to provide the indicated data.

TOP-003-3(TOPs and BAs requested data)


• R2. Each Balancing Authority shall maintain a documented specification for the data necessary for it to perform its analysis functions and Real-time monitoring. The data specification shall include, but not be limited to: 2.1. A list of data and information needed by the Balancing Authority to

support its analysis functions and Real-time monitoring. 2.2. Provisions for notification of current Protection System and Special

Protection System status or degradation that impacts System reliability. 2.3. A periodicity for providing data. 2.4. The deadline by which the respondent is to provide the indicated data.

TOP-003-3(TOPs and BAs requested data)


• R2. Each Transmission Planner and Planning Coordinator shall prepare an annual Planning Assessment of its portion of the BES. This Planning Assessment shall use current or qualified past studies (as indicated in Requirement R2, Part 2.6), document assumptions, and document summarized results of the steady state analyses, short circuit analyses, and Stability analyses.

TPL-001-4(TP/PC model/study performance)


• R5. Each Transmission Operator shall specify a voltage or Reactive Power schedule (which is either a range or a target value with an associated tolerance band) at either the high voltage side or low voltage side of the generator step-up transformer at the Transmission Operator’s discretion. 5.1. The Transmission Operator shall provide the voltage or Reactive

Power schedule (which is either a range or a target value with an associated tolerance band) to the associated Generator Operator and direct the Generator Operator to comply with the schedule in automatic voltage control mode (the AVR is in service and controlling voltage).

5.2. The Transmission Operator shall provide the Generator Operator with the notification requirements for deviations from the voltage or Reactive Power schedule (which is either a range or a target value with an associated tolerance band).

VAR-001-4.2


5.3. The Transmission Operator shall provide the criteria used to develop voltage schedules or Reactive Power schedule (which is either a range or a target value with an associated tolerance band) to the Generator Operator within 30 days of receiving a request.

VAR-001-4.2


• R2. Unless exempted by the Transmission Operator, each Generator Operator shall maintain the generator voltage or Reactive Power schedule3 (within each generating Facility’s capabilities4) provided by the Transmission Operator, or otherwise shall meet the conditions of notification for deviations from the voltage or Reactive Power schedule provided by the Transmission Operator. 2.1. When a generator’s AVR is out of service or the generator does not

have an AVR, the Generator Operator shall use an alternative method to control the generator reactive output to meet the voltage or Reactive Power schedule provided by the Transmission Operator.

2.2. When instructed to modify voltage, the Generator Operator shall comply or provide an explanation of why the schedule cannot be met.

VAR-001-4.2


2.3. Generator Operators that do not monitor the voltage at the location specified in their voltage schedule shall have a methodology for converting the scheduled voltage specified by the Transmission Operator to the voltage point being monitored by the Generator Operator.

• 3 The voltage or Reactive Power schedule is a target value with a tolerance band or a voltage or Reactive Power range communicated by the Transmission Operator to the Generator Operator.

• 4 Generating Facility capability may be established by test or other means, and may not be sufficient at times to pull the system voltage within the schedule tolerance band. Also, when a generator is operating in manual control, Reactive Power capability may change based on stability considerations.

VAR-001-4.2


• Are there other key standards related to all this?• Do we see any major gaps/issues with the standards?• Where should the most focus be on the risks we have today?• Do we see any issues in the future that are not captured?

• MOD-026-1• MOD-027-1

• NEED EDUCATION AROUND MUCH OF THE “FLEXIBILITIES” IN THESE STANDARDS

Brainstorm Discussion

SPP Renewable Based Resource Studies

1

SPP Operating Region 2017

• Summer peak load of 50,662 MW Northern portion of SPP winter peaking

• Approximately 16,124 MW of wind generation Wind peak of 13,342 MW on February 09, 2017 Previous wind penetration peak 49.17% on April 24, 2016 New wind penetration peak 52.08% on February 12, 2017

• SPP operates as a Consolidated Balancing Authority and Reliability Coordinator

• Generation unit commitment on a regional basis

2

SPP Operating Region Current

3

Wind Integration Study Recommendations

1. Install Voltage reactive support capabilities for existing wind farms install enhanced operations tools for Dynamic Reactive Reserves and develop criteria requirements for real-time operations.

2. Install real-time operations tools to calculate and monitor real-time voltage stability limits using an applicable real-time software suite.

3. Provide additional flexibility to the Reliability Coordinator for NDVER redispatch.

4. Develop additional planning criteria to enhance analysis requirements for incorporating a more robust scenario development.

5. Expedite approved ITP projects.

6. Evaluate the bulk electric system impacts with the addition of Solar PV in combination with wind.

7. Perform an additional evaluation of PMU applications to provide real-time situational awareness.

4

5

1. SPP Staff shall manage voltage stability to an appropriate stability margin using an online voltage stability analysis (VSA) tool.

2. The Transmission Working Group (TWG) shall assess and define requirements for SPP to perform voltage stability analysis during low load scenarios as part of SPP Planning process.

3. TWG shall re-evaluate and consider increasing the existing Damping Ratio of 0.8% found in the SPP Disturbance Performance Requirements criteria.

4. SPP Staff shall install online transient stability contingency screening and time domain analysis tools for next day operational analysis.

5. SPP Staff shall analyze and quantify the risk of short-term and long-term load and renewable forecast deviations.

6. TWG shall assess the cause and impact of modes of inter-area oscillation for machines identified within the VIS report for the SPP Planning area.

7. Synchrophasor Strike Team (SST) shall use the VIS report findings as parameters for future PMU siting.

Variable Generation Integration Study Recommendations (VIS)

IBIS Process Overview

6

PSS/E DSATools

TASK 1a: Model Development (N-0/N-X)

TASK 1b: Fast Fault Screening (FFS)(N-0/N-X)

TASK 1c: Transient Stability Analysis (N-0/N-X)

TASK 6: EPRI transient Analysis (PSCAD)

Wolf Creek/Waverly

TASK 2: PLI Model Building and Bench Marking (N-0/N-X)

TASK 3: Transient Stability Analysis (TSAT)

(N-0/N-X)

TASK 4: Prony (N-0/N-X)

TASK 7: Short Circuit Ratio (SCR)

TASK 5: Small Signal Stability

(SSAT) (N-0/N-X)

SPP Models

2021

2018

IBIS Goals

Create New Criteria to Determine System Bus

Strength

Determine the Root Cause of Oscillations

Additional TSAT Scenarios to Prepare us for Online TSAT

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Overview of Activities Resource... · 2018. 8. 31. · 7 RELIABILITY | ACCOUNTABILITY •R2. The...

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