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Meeting Agenda MRO Protective Relay Subgroup

August 11, 2020 – 8:00 a.m. to 11:00 p.m. and

1:00 p.m. – 4:00 p.m.

Webex

Meeting Agenda – MRO Protective Relay Subgroup – August 11, 2020

VIDEO AND AUDIO RECORDING

Please note that Midwest Reliability Organization (MRO) may make a video and/or an audio recording of

this organizational group meeting for the purposes of making this information available to board members,

members, stakeholders and the general public who are unable to attend the meeting in person.

By attending this meeting, I grant MRO:

1. Permission to video and/or audio record the meeting including me; and

2. The right to edit, use, and publish the video and/or audio recording.

3. I understand that neither I nor my employer has any right to be compensated in connection with the

video and/or audio recording or the granting of this consent.


MRO ORGANIZATIONAL GROUP GUIDING PRINCIPLES

These MRO Organizational Group Guiding Principles complement charters. When the Principles are

employed by members, they will support the overall purpose of the organizational groups.

Organizational Group Members should:

1. Make every attempt to attend all meetings in person or via webinar.

2. Be responsive to requests, action items, and deadlines.

3. Be active and involved in all organizational group meetings by reviewing all pre-meeting materials and

being focused and engaged during the meeting.

4. Be self-motivating, focusing on outcomes during meetings and implementing work plans to benefit

MRO and MRO’s registered entities.

5. Ensure that the organizational group supports MRO strategic initiatives in current and planned tasks.

6. Be supportive of Highly Effective Reliability Organization (HEROTM) principles.

7. Be supportive of proactive initiatives that improve effectiveness and efficiency for MRO and MRO’s

registered entities.


MEETING AGENDA

Agenda Item 1 Call to Order and Introduction

John Grimm, PRS Chair

2 Determination of Quorum and Standards of Conduct and Anti-trust Guidelines Mike Bocovich, PRS Technical Liaison

3 Consent Agenda John Grimm, PRS Chair a. Approve May 19, 2020 PRS Meeting Minutesb. Approve August 11, 2020 PRS Meeting Agenda

4 Chair’s Report John Grimm, PRS Chair

5 Secretary’s Report Mike Bocovich, PRS Technical Liaison

6 PRS Business a. Charter Review

John Grimm, PRS Chairb. Whitepaper and Lessons Learned on Cold Weather Operation of SF6 Breakers

John Seidel, MRO Principal Technical Advisorc. Chair and Vice Chair Approvals

Bryan Clark, Director Reliability Assessment and Performance Analysis

7 NERC Activities a. Update on NERC SPCS

Mark Gutzmann Director, System Protection & Communication Engineering, Xcel Energyb. NERC MIDASWG Update

Mike Bocovich, PRS Technical Liaisonc. FERC/NERC Protection System Commissioning Program Review

Mike Bocovich, PRS Technical Liaison

8 Misoperations Mike Bocovich, PRS Technical Liaison a. First Quarter 2020 Results and Reviewb. Minnesota Power System Conference Submittal regarding Misoperations

John Grimm, PRS Chair and Mike Bocovich, PRS Technical Liaisonc. Survey of Protection System Scheme Typed. Lessons Learned Updates

i. 86 Lockout Relay Failures (NERC Review May 7, 2020)ii. Mixing Technologies in Blocking Schemes (NERC Review May 8, 2020)iii. Verification of AC Quantities during Protection System Design and Commissioning

e. Using a transistor output to drive an opto-isolated inputCasey Malskeit

9 Event Analysis Report Jake Bernhagen, MRO Sr. Systems Protection Engineer, David Kuyper, MRO Power System Engineer

10 Update on SPS Review Team Activities David Kuyper, MRO Power Systems Engineer


Agenda Item 11 TPL-001-5 Footnote 13


12 PRS Roundtable Discussion John Grimm, PRS Chair

13 Upcoming PRS Meeting Dates Mike Bocovich, PRS Technical Liaison

14 Other Business and Adjourn John Grimm, PRS Chair


AGENDA 1

Call to Order, Introductions and Standards of Conduct and Anti-Trust Guidelines John Grimm, PRS Chair

Standards of Conduct Reminder: Standards of Conduct prohibit MRO staff, committee, subgroup, and task force members from sharing non-

public transmission sensitive information with anyone who is either an affiliate merchant or could be a

conduit of information to an affiliate merchant.

Anti-trust Reminder: Participants in Midwest Reliability Organization meeting activities must refrain from the following when

acting in their capacity as participants in Midwest Reliability Organization activities (i.e. meetings,

conference calls, and informal discussions):

Discussions involving pricing information; and

Discussions of a participants marketing strategies; and

Discussions regarding how customers and geographical areas are to be divided among

competitors; and

Discussions concerning the exclusion of competitors from markets; and

Discussions concerning boycotting or group refusals to deal with competitors, vendors, or suppliers.


AGENDA 2

Determination of Quorum Mike Bocovich, PRS Technical Liaison

Name Locale Company Term

John Grimm, Chair Minnesota Northern States Power 12/31/2019

Robert Soper, Vice Chair Dakotas Western Area Power

Administration 12/31/2019

Alex Bosgoed Canada Saskatchewan Power Company 12/31/2019

Casey Malskeit Nebraska Omaha Public Power District 12/31/2019

Cody Remboldt Dakotas Montana-Dakota Utilities 12/31/2021

David Wheeler AR/TX/LA/NM Southwestern Public Services Co. 12/31/2020

Dennis Lu Canada Manitoba Hydro 12/31/2020

Derek Vonada Kansas/Missouri Sunflower Electric Power

Cooperative 12/31/2022

Derrick Schlangen Minnesota Great River Energy 12/31/2020

Forrest Brock Oklahoma Western Farmers Electric

Cooperative 12/31/2022

Gary Stoedter Regional MidAmerican Energy Company 12/31/2021

Greg Hill Nebraska Nebraska Public Power District 12/31/2019

Greg Sessler Wisconsin American Transmission Company 12/31/2020

Jeff Beasley Oklahoma Grand River Dam Authority 12/31/2021

Ryan Einer Oklahoma Oklahoma Gas & Electric Co. 12/31/2020

Ryan Godwin AR/TX/LA/NM American Electric Power 12/31/2021

Scott Paramore Kansas/Missouri Kansas City Board of Public Utility 12/31/2021

Terry Fett Iowa Central Iowa Power Cooperative 12/31/2020

Wayne Miller Iowa ITC Holdings 12/31/2021


AGENDA 3

Consent Agenda

a. Approve May 19, 2020 PRS Meeting Minutes


Action Approve May 19, 2020 PRS meeting minutes.

Report May 19, 2020 PRS Meeting Minutes attached.

Draft Minutes of the Protective Relay Subgroup (PRS) Meeting

Webex

May 19, 2020 8:00 a.m. – 11:00 a.m. Central Daylight Savings

1:00 p.m. – 4:00 p.m. Central Daylight Savings

1. Call to Order and Introductions

PRS Chair John Grimm called the meeting to order at 8:06 a.m. Chair Grimm extended a warm

welcome to all attendees, roll call was taken and introductions were made.

2. Determination of Quorum, Standards of Conduct, and Anti-Trust Guidelines

The meeting secretary Mike Bocovich determined that a quorum was present. A complete list of

attendees is included as Exhibit A. Pursuant to Policy and Procedure 4, MRO’s Standards of Conduct,

Conflict of Interest and Anti-Trust Guidelines were presented.

3. Consent Agenda

a. The PRS reviewed the minutes of the February 25-26, 2020 PRS Meeting. b. The PRS reviewed the May 19, 2020 PRS Meeting Agenda

Upon a motion duly made and seconded, the Protective Relay Subgroup unanimously approved the

minutes from the February 2526, 2020 PRS Meeting as drafted and the May 19, 2020 PRS Meeting

Agenda.

4. Chairman’s Report

Chair John Grimm welcomed attendees and expressed thanks for technology to allow the PRS

meeting to be held. John Grimm stated there is a full agenda, and there will be a two hour break from

11:00 am to 1:00 pm.

5. Secretary’s Report

Mike Bocovich reiterated the schedule of today’s meeting. It was stated attendees should raise their

hand to be noticed in the web meeting. Dana was introduced who will be assisting with the meeting.


6. PRS Business

a. Chair and Vice Chair approval

Chair Grimm stated that he and Bob Soper were approved as Chair and Vice Chair respectively

and new members were appointed to the PRS. All positions are filled in this group.

b. Whitepaper on Breaker Low SF6 Gas Philosophy John Seidel presented a draft of a Whitepaper and provided an overview of the January 29-30

2019 event when some SF6 gas breakers hit their critical low pressure due to severe cold weather.

A presentation was made at the 2019 MIPSYCON which acquired the attention of many. It was

decided to develop a white paper to gain situation awareness. A query was sent to the PRS

members and a few additional Entities in the northern portion of the MRO footprint. Twelve of

fourteen entities in the north replied to the query. The paper discusses the results of the data

query, observations, and recommendations. Recommendations will be proposed as a lessons

learned which will be sent to NERC for situation awareness during severe cold events.

Seidel provided background on the paper; a subgroup (John Grimm, Cody Remboldt, Derek Vonada, and Bob Soper) was formed about 6 months ago to help prepare the whitepaper and have met once. He mentioned he is seeking comments from the PRS group on the whitepaper, and asked to send and comments to him or to John Grimm. Action item. John will set up subgroup meeting to finalize the whitepaper and then send back to the PRS for final review and approval.

c. MRO Webinar on PRS Phase II White Paper It was mentioned that in 2019, misoperations associated with breakers failure schemes have

increased and have resulted in a number of Category 1.a event analysis reports. MRO staff

suggested that the PRS Phase II Whitepaper be re-presented through a webinar since this

whitepaper identified ways to increase the security of these critical protection systems. The PRS

phase II Whitepaper covers these breaker failure schemes as well as best practices for

commissioning system protection equipment, which is presently a subject of interest by FERC and

NERC.

Mike Bocovich asked for volunteers to assist in planning and presenting the webinar which is not

yet scheduled, but anticipating the time frame of late June. John Grimm, Jeff Beasley, and Ryan

Einer (by e-mail) volunteered to help with the webinar. MRO will reach out to these PRS members

to plan and prepare for the webinar of this whitepaper.

The PRS recessed for break at 9:23 a.m. and reconvened at 9:35 a.m.

7. NERC Activities

a. Update on NERC SPCS Mike Bocovich mentioned that there has not been a NERC SPCS meeting since the last time the PRS met. There is a subgroup of the SPCS looking at the impacts of inverter based resources (IBR) on the bulk power system. There is increasing concern regarding how IBRs will result in


overall reduced fault current. A document is expected to be completed by the end of 2020/beginning of 2021 which will become public after it is approved.

b. NERC MIDASWG Update Mike Bocovich presented an overview of the past meeting and noted that MIDAS data reporting

instructions (DRI) have been approved and are posted. He mentioned they are trying to get

overcurrent included in the system scheme reporting field as overcurrent elements are responsible

for a large number of misoperations. Mike stated the MIDASWG is always looking for examples to

include in the DRI.

c. FERC/NERC Protection System Commissioning Program Review

FERC has noted a larger than expected number of misoperations could be eliminated with good

commissioning practices. Mike Bocovich stated no one wants a standard on commissioning. There

has been a history of trying to encourage the industry to adopt good commissioning practices

through an IEEE paper and NERC lessons learned. A few entities will be invited to participate in

this effort through a survey of questions and interviews to determine best practices.

They hope to have the program review wrapped up in first part of 2021. It is desired to see

immediate improvement, but it will take time to see a reduction of misoperations that can be tied to

commissioning.

8. Misoperations

a. 2019 Year End Results and Trending

Mike Bocovich presented and provided an overview on an article in the MRO newsletter and

directed people’s attention to it. He noted that misoperations’ rates have dropped substantially over

the last three years, but still remain slightly above the ERO average and that there is room for

improvement. When you break down the misoperations, there are incorrect settings, relay

failures/malfunctions and logic errors noted as frequent contributors to the misoperation count that

could be reduced with good commissioning practices. Discussion ensued on new relay settings

and commissioning practice.

Reporting of first quarter 2020 MIDAS data has been pushed out until end of June due to COVD-

19. 40% of entities have not reported into MIDAS yet. MIDAS submittals will be reviewed and sent

for PRS review after the reporting period.

MIDAS was opened and a few charts presented. Instantaneous overcurrent related misoperations

comprise of about 80% of the “Other” system scheme category. Some discussions occurred

surrounding overcurrent and instantaneous ground overcurrent philosophies. Additional charts

were presented in MIDAS.

b. Minnesota Power System Conference Submittal regarding Misoperations

Chair Grimm mentioned that this paper submitted for presentation at MIPSYCON: Analysis of

Composite Protection System Misoperations was accepted. Grimm provided an update and


mentioned a presentation still needs to be prepared. The presentation given at the 2019 MRO

Reliability Conference will be modified to include 2019 data. The PRS subgroup will be advertised

as available to assist Entities.

c. Misoperations Discussions and Help from Friends – Xcel Energy Chisago Substation Event

Chair Grimm presented an event that occurred at Chisago County substation involving a free

standing current transformer failure. Discussion ensued regarding free standing CT failure

detection schemes.

The PRS recessed for lunch at 11:00 a.m. and reconvened at 1:02 p.m.

d. Survey of Protection System Scheme Type

Mike Bocovich presented work towards a survey of protection system schemes. The survey is to

determine a relative population of different high speed, communications assisted transmission line

protection schemes to determine if directional comparison blocking schemes are experiencing a

disproportionate number of misoperations. The survey is intended to be distributed to PRS

members only. PRS members’ Entities represent about 73% of the transmission line circuits within

the MRO footprint according to TADS inventory data. It was desired that the survey include the

number of transmission lines by voltage class listed in the TADS inventory. A request was made to

provide an example on how to complete the survey. The survey should be a fairly simple exercise

and should not to have too much time devoted to it, approximations are acceptable.

Action item: The survey will be prepared and sent to those who volunteered to work on it for review.

After review the survey will be sent to PRS members.

e. Lessons Learned Updates

Reviews of lessons learned were conducted by NERC review boards. Both lessons learned were

well received with a few edits. The lessons learned will be sent to technical writers, then sent back

to the review boards to assure the technical writers did not change the meaning of the lessons

learned. These lessons learned are expected to be published June 2020.

ii. Mixing Technologies in Blocking Schemes (NERC Review May 8, 2020).

Mike Bocovich reviewed the lessons learned on mixing technologies in blocking schemes. A

noted edit was to state the preferred method to mitigate the problem is to assure schemes

utilize the same manufacturer, make and model of protection equipment at all terminals. If that

can’t be done then the use of other listed corrective actions can be evaluated.

i. Relay Failures (NERC Review May 7, 2020).

Gary Stoedter of MidAmerican provided a history of the event that started a lessons learned on

lockout relay switch failures and reviewed the lessons learned. A few bullet items were added

to the lessons learned section to develop a procedure to log and track actions associated with

advisory notes. Mike and Gary are to discuss how to deal with outside queries associated with

this lessons learned.


9. Event Analysis Report

Jake Bernhagen, MRO Sr. Systems Protection Engineer noted that as of this month MRO is caught up

to within a year in EA events and thanked everyone on the call for participating on the cause coding

calls. He noted MRO’s goal is to complete cause coding within six months of the event to close out the

event. Jake relayed thanks from the NERC staff to all the MRO entity participants, also.

10. Update on SPS Review Team Activities

David Kuyper, MRO Power System Engineer discussed transitioning duties of remedial action scheme

(RAS) reviews to RCs and PCs. He mentioned SaskPower has taken responsibility for their RAS

reviews which were most of those within the MRO region up for review in 2020. There are a few new

RASs submitted for review to be implemented this year. One RAS will be retired. An overview of the

future schedule of reviews was provided.

11. PRC-002-2 SMET Standard Application Guide (SAG) Team Update

Mike Bocovich provided an update of the SAG and noted it will go to the CMEPAC for acceptance at

their next meeting and noted the personnel who worked on the SAG and provided a brief overview. It

was mentioned the SAG is expected to be accepted by the CMEPAC the first week of June and then

sent to NERC for ERO wide approval. It can be utilized by MRO entities when it is accepted by the

CMEPAC. Discussion occurred regarding the process for SAGs and when they are available to MRO

Entities for use.

12. PRS Roundtable Discussion

Chair Grimm mentioned all the good work that the PRS is currently doing and asked if there are any

other discussion topics.

a. The approved TPL-001-5 topic was raised regarding single points of failure, footnote 13. The group

would like information on developing a process to help guide transmission planners on how to

analyze delayed fault clearing due to the failure of a non-redundant component of a protection

system.

i. One method presented was for planning to study every bus and then provide protection

engineering with busses that failed (required fast clearing). System Protection was able to

eliminate half of the locations by knowing they are fully redundant. This reduced the

number of substations requiring a mitigation plan. (Run a study on every bus then triage.)

ii. Discussions regarding sequential tripping and difficulty if performing a study if everything

doesn’t trip at the same time.

iii. Another similar method is for system protection to identify single points of failure, then

perform a planning study on these locations,

iv. Would like MRO wide interpretation on what footnote 13 actually means. Would like to

know what constitutes “redundant”. Example: Are two communications channels on a

single microwave station redundant or not?

Action item: Footnote 13 MRO wide interpretation was asked for, add to future meeting agenda.


b. Per a PRS member request, discussion ensued on working from home plans; several entities

shared their current schedule and future plans and noted restrictions, successes, and potential

issues.

13. Upcoming PRS Meeting Dates

Mike Bocovich noted that the next meeting was tentatively set for Tuesday, August 11th from 8:00 –

4:00 p.m. and a tentative date of November 17 for the following meeting.

If there are any misoperations topics or events to discuss next meeting please send to Mike Bocovich

to add to the Agenda.

14. Other Business and Adjourn

Having no further business to discuss, the meeting was adjourned at 2:42 p.m.

Prepared by: Dana Klem, Reliability Assessment and Performance Analysis Administrator.

Reviewed and Submitted by: Mike Bocovich, PRS Technical Liaison


Exhibit A – Meeting Attendees

Subgroup Members Present

Name Company, Role

John Grimm (Chair) Northern States Power

Robert Soper (Vice Chair) Western Area Power Administration

Alex Bosgoed Saskatchewan Power Company

Casey Malskeit Omaha Public Power District

Cody Remboldt Montana-Dakota Utilities

David Wheeler Southwestern Public Services Co.

Dennis Lu Manitoba Hydro

Derek Vonada Sunflower Electric Power Cooperative

Derrick Schlangen Great River Energy

Forrest Brock Western Farmers Electric Cooperative

Gary Stoedter MidAmerican Energy Company

Greg Hill Nebraska Public Power District

Greg Sessler American Transmission Company

Jeff Beasley Grand River Dam Authority

Ryan Einer Oklahoma Gas & Electric Co.

Ryan Godwin American Electric Power

Scott Paramore Kansas City Board of Public Utility

Terry Fett Central Iowa Power Cooperative

Wayne Miller ITC Holdings

MRO Staff

Name Title

Dana Klem Administrator, RAPA

David Kuyper Power System Engineer (PM only)


Jake Bernhagen Sr. Systems Engineer (PM only)

John Seidel Principal Technical Advisor

Mike Bocovich Principal System Protection Engineer

Max Desruisseaux Sr. Power System Engineer

Guests

Name Company

Mark Gutzmann Xcel Energy/Northern States Power

David Oswald Liberty Utilities

Doug Jackson Grand River Dam Authority

Kevin Goolsby GDS Associates

Terry Volkmann Glencoe Light and Power Commission


AGENDA 4

Chairman’s Report


Action Discussion

Report Chair Grimm will provide an oral report during the meeting.


AGENDA 5

Secretary’s Report


Action Information

Report Mike Bocovich will provide an oral report during the meeting.


AGENDA 6

PRS Business

a. Charter Review


Action Review and approve changes to the PRS Charter.

Report Chair Grimm, will lead the review and discussion of the Charter during the meeting.

1

MRO PROTECTIVE RELAY SUBGROUP CHARTER

September 19, 2019 I. Purpose The purpose of the MRO Protective Relay Subgroup (PRS) is to identify, review and discuss system protection and control issues relevant to the reliability of the bulk electric system and to develop and implement regional procedures for applicable NERC PRC standards. The MRO Protective Relay Subgroup (MRO PRS) reports to the Reliability Advisory Council (RAC).

II. Membership Pursuant to Policy and Procedure 3: Establishment, Responsibilities, and Procedures of Organizational Groups and MRO Sponsored Representatives on NERC Organizational Groups (PP3), membership of organizational groups shall be determined based upon experience, expertise and geographic diversity and to the extent practicable, shall include a balanced representation of the sectors. The MRO PRS is comprised of industry experts in the areas of system protection and control. The specific experience and expertise needs of the MRO PRS are determined by the MRO PRS. The subgroup shall be comprised of no more than 19 members, with not more than one member from the same company and membership based on geographic representation as follows:

• Arkansas/Texas/Louisiana/New Mexico – 2 • Canada – 2 • Dakotas – 2 • Iowa – 2 • Kansas/Missouri – 2 • Minnesota – 3 • Nebraska – 2 • Oklahoma – 2 • Wisconsin – 2

If after soliciting membership based on the above geographic representation, one or more seat cannot be filled, then MRO will solicit for members from the entire region and the member will be designated “Regional.” When the term for that seat ends, MRO will again solicit a member from the state(s) which gave rise to the Regional member.

III. Key Objectives • Develop, maintain, and implement regional procedures as needed that address the

requirements of NERC PRC standards. • Annually review the summary of Misoperations (prepared by MRO staff) for the purpose of

identifying Lessons Learned and communicating these lessons with MRO membership.

2

• Trend the Event Analysis reports submitted to MRO for the purpose of identifying misoperations that are causing, or increasing the severity of, these events. Through the MRO PRS, work with the Entities involved with these events to assure that the misoperations are effectively identified and mitigated. Assure that any protection-related Lessons Learned of value to the industry are prepared and submitted to NERC Event Analysis staff.

• Prepare as necessary additional reports/whitepapers that identify methods that can reduce the likelihood and/or severity of system events or misoperations that can lead to system events.

• Provide oversight of the Remedial Action Schemes (RAS) review process to ensure that all new and modified RASs are reviewed before they come into service, and that all RASs in the MRO region are reviewed every five years.

• Provide technical input related to system protection and control to MRO. • Interface with the NERC groups related to protection and control.

IV. Meetings The MRO PRS will meet quarterly, or as necessary, in person, or via conference call, or web meeting. Meetings of the MRO PRS are open to public attendance; however, an executive session may be called by the chair or vice-chair. Additional meeting requirements related to agendas and minutes, voting and proxy, and rules of conduct are outlined in MRO Policy and Procedure 3, Organizational Groups.

V. Costs Meeting costs incurred by MRO PRS members are reimbursable by MRO according to MRO Policy and Procedure 2, Expense Reimbursement.

VI. Reporting Requirements The chair of the MRO PRS, or delegate, will provide a written and/or oral report describing the activities and actions of the group quarterly to the Reliability Advisory Council (RACRAC). The MRO PRS shall perform an annual review of this charter and the group’s overall purpose and key objectives to ensure that the group is efficient and effective in its operations and according to its purpose. The chair shall provide an annual summary report, including a statement of its conclusions, to the RAC.

1

MRO PROTECTIVE RELAY SUBGROUP CHARTER

September ___, 2020

I. Purpose

The purpose of the MRO Protective Relay Subgroup (PRS) is to identify, review and discuss system

protection and control issues relevant to the reliability of the bulk electric system and to develop and

implement regional procedures for applicable NERC PRC standards. The PRS reports to the Reliability

Advisory Council (RAC).

II. Membership

Pursuant to Policy and Procedure 3: Establishment, Responsibilities, and Procedures of Organizational

Groups and MRO Sponsored Representatives on NERC Organizational Groups (PP3), membership of

organizational groups shall be determined based upon experience, expertise and geographic diversity and

to the extent practicable, shall include a balanced representation of the sectors. The PRS is comprised of

industry experts in the areas of system protection and control. The specific experience and expertise

needs of the PRS are determined by the PRS. The subgroup shall be comprised of no more than 19

members, with not more than one member from the same company and membership based on geographic

representation as follows:

Arkansas/Texas/Louisiana/New Mexico – 2

Canada – 2

Dakotas – 2

Iowa – 2

Kansas/Missouri – 2

Minnesota – 3

Nebraska – 2

Oklahoma – 2

Wisconsin – 2

If after soliciting membership based on the above geographic representation, one or more seat cannot be

filled, then MRO will solicit for members from the entire region and the member will be designated

“Regional.” When the term for that seat ends, MRO will again solicit a member from the state(s) which

gave rise to the Regional member.

III. Key Objectives

Develop, maintain, and implement regional procedures as needed that address the

requirements of NERC PRC standards.

Annually review the summary of Misoperations (prepared by MRO staff) for the purpose of

identifying Lessons Learned and communicating these lessons with MRO membership.

2

Trend the Event Analysis reports submitted to MRO for the purpose of identifying

misoperations that are causing, or increasing the severity of, these events. Through the MRO

PRS, work with the Entities involved with these events to assure that the misoperations are

effectively identified and mitigated. Assure that any protection-related Lessons Learned of

value to the industry are prepared and submitted to NERC Event Analysis staff.

Prepare as necessary additional reports/whitepapers that identify methods that can reduce the

likelihood or severity of system events or misoperations that can lead to system events.

Provide oversight of the Remedial Action Schemes (RAS) review process to ensure that all

new and modified RASs are reviewed before they come into service, and that all RASs in the

MRO region are reviewed every five years.

Provide technical input related to system protection and control to MRO.

Interface with the NERC groups related to protection and control.

IV. Meetings

The PRS will meet quarterly, or as necessary, in person, via conference call, or web meeting. Meetings

of the PRS are open to public attendance; however, an executive session may be called by the chair

or vice-chair. Additional meeting requirements related to agendas and minutes, voting and proxy, and

rules of conduct are outlined in MRO Policy and Procedure 3, Organizational Groups.

V. Costs

Meeting costs incurred byPRS members are reimbursable by MRO according to MRO Policy and

Procedure 2, Expense Reimbursement.

VI. Reporting Requirements

The chair of the PRS, or delegate, will provide a written or oral report describing the activities and

actions of the group quarterly to the RAC. The PRS shall perform an annual review of this charter and

the group’s overall purpose and key objectives to ensure that the group is efficient and effective in its

operations and according to its purpose. The chair shall provide an annual summary report,

including a statement of its conclusions, to the RAC.

Approved by the Organizational Group Oversight Committee on September ____, 2020


AGENDA 6

PRS Business

b. Whitepaper and Lessons Learned on Cold Weather Operation of SF6 Breakers

John Seidel, MRO Principal Technical Advisor

Action Discussion

Report John Seidel will lead the discussion at the meeting.

RELIABILITY | RESILIENCE | SECURITY

Lesson Learned Title: Cold Weather Operation of SF6 Circuit Breakers Primary Interest Groups: Transmission Owners and Operators, Generation Owners and Operators, Reliability Coordinators.

Problem Statement: When a SF6 circuit breaker hits its critical low pressure, its fault interrupting capability can be compromised. Most Transmission Owners protect against this by either auto-opening the circuit breaker at the critical low pressure level, or blocking the circuit breaker from tripping and relying on adjacent circuit breakers to open in the event of a fault (breaker failure mode). As this occurs across multiple locations, as it did during the severe cold weather event that hit the upper Midwest region of North America on January 29-30, 2019, it can place the BES at additional risk since it weakens the overall topology of the system and it can result in more facilities being removed from service to clear a fault. Contingency outages studied in Real-Time Contingency Analysis (RTCA) may no longer be accurately modeled, thereby potentially putting the BES in a less secure or unknown state.

Details: At the 2019 Minnesota Power Conference held on November 12-14, 2019, a presentation was given on the operation of SF6 circuit breakers (CBs) under low SF6 pressure conditions caused by severe ambient cold weather conditions. This conference session focused on the SF6 breaker operations that occurred on two upper Midwest utilities’ systems during the severe cold weather event that hit the upper Midwest region of North America on January 29-30, 2019. The MRO Protective Relay Subgroup (PRS) discussed this topic at their November 19, 2019 meeting in St Paul, MN. It became clear that additional Transmission Owners within MRO were also impacted by the cold weather event due to reaching critical low pressure levels on their BES CBs. The MRO PRS agreed to explore this issue further to provide more understanding and situational awareness on this topic.

Discussion of SF6 and Mixed Gas Circuit Breaker Technology Gas insulated circuit breakers must maintain a design pressure in order for the breaker to achieve its full fault interrupting capability. When pressure starts to drop in the tank, such as when the gas starts to condense (liquefy) due to cold ambient temperatures, it may eventually reach two alarm levels.

The first alarm is a low pressure alarm. This first alarm serves as a warning that SF6 gas density has decreased approximately half way to the lockout pressure. This alarm level is provided to allow the entity time to perform corrective actions prior to the lockout pressure.

The second alarm is the lockout (or critical) pressure alarm. This occurs at the lowest SF6 gas pressure at which the OEM has designed the circuit breaker (CB) to achieve its rated interrupting capability, corresponding to the SF6 gas density based on ambient temperature. Tripping operations below this level may not successfully interrupt rated fault current and may also damage the circuit breaker. At this level, a protection scheme is typically installed to either auto-open the CB, or block the trip and rely on a breaker failure relay to open all adjacent (or remote) breakers in the event of a fault.

When installed, tank heaters warm the SF6 inside the circuit breaker, raising it above the ambient temperature and the temperature where it may start to condense. During severe cold weather, ambient

Appendix E: Lesson Learned Template 2

temperatures outside of the circuit breakers specified operating range may overwhelm the tank heater’s ability to keep the SF6 in a gaseous state. It is likely this may have occurred during the January 29-30, 2019 event in the upper Midwest; 13 of the 81 CBs that hit their critical lockout pressure during that two-day event had heaters that were confirmed to be working. Additionally, there were high winds throughout the Midwest on January 29, 2019, and the effectiveness of the heaters was likely compromised due to these high winds1. Mixed Gas CBs: For areas that can be regularly subjected to temperatures in the -30° to -40° F range or colder, a mixed gas approach is usually used. Mixed-gas circuit breakers were developed for use at temperatures as low as -50° C (-58° F). These breakers utilize a gas mixture of SF6 and CF4 or SF6 and N2 to prevent condensation of the SF6 gas. Today’s mixed-gas circuit breakers offer excellent cold weather performance and provide the reliability needed for even the most severe cold weather conditions. This is achieved without the use of heaters. Mixed gas CBs used for severe cold weather are predominantly live tank design vs. dead tank design which can accommodate tank heaters2. The two Canadian utilities within MRO (SaskPower and Manitoba Hydro) predominantly use mixed gas live tank CBs on their bulk power system and they performed without issue during the severe cold of January 29-30, 2020. The below Figure 1 illustrates how a mixture of SF6 and CF4 remains gaseous at much lower temperatures than pure SF6 gas.

1 MISO Balancing Authority wind output was approximately 13,500 MW during the early morning hours of January 29, 2019; SPP Balancing Authority wind output was approximately 15,300 MW at that time. Wind turbines throughout the upper Midwest were hitting their cold weather cutout limits (typically -30° C (-22° F) as well, causing wind plants to shut down during high output (Refer to LL20200601, “Unanticipated Wind Generation Cutoffs during a Cold Weather Event”). 2 There are two main categories of circuit breakers: one in which the enclosure for the extinguishing medium and the contacts is metallic and grounded, and the other in which the chamber containing the extinguishing medium and contacts is insulated from ground. The former is commonly referred to as a dead tank design and the latter as a live tank design.


Figure 1: SF6 and SF6-CF4 Mixed Gas Phase Change Diagram

MRO Data Query for CB Operations Due to Critical Low Pressure Since there was no formal event analysis report for this cold weather event, MRO staff sent a data query to the Transmission Owners/Operators within the event area. Information was collected on each


company’s philosophy of SF6 breaker protection during critical low pressure conditions. The query also requested information on actual occurrences on January 29-30, 2019, regarding SF6 breakers hitting their critical low pressure alarm level and what opening or blocking actions occurred. The query targeted the northern Transmission Owners/Operators since they experienced temperatures in the -30° to -40° F range. The Transmission Owners/Operators in the southern half of MRO experienced moderate ambient temperatures and were mostly unaffected by the January 29-30, 2019 cold weather event. Summary of Results from the MRO Data Query Protection scheme philosophy when SF6 CBs hit critical low pressure (12 Entity responses):

• 7 Entities rely on breaker failure scheme protection upon hitting critical low pressure • 3 Entities auto-trip the breaker and block the close upon hitting critical low pressure • 2 Entities will auto-trip or rely on breaker failure, depending on location/situation.

Summary of actual operations on January 29-30, 2019:

• 6 of the 12 Entities had no occurrences of BES CBs hitting critical low pressure • 6 Entities had a total of 81 CBs hit critical pressure and block or auto-open • One CB was mixed gas design (-50° C, no heater); operation was unrelated to cold weather • 56 of the remaining 80 CBs did not have heaters operating (70%)

o 13 CBs had heaters working o 11 CBs - heater operation was unknown

• Pre-Winter Heater Inspections/Maintenance: o 3 of the 12 Entities indicated they perform pre-winter inspections of heaters

• Ambient temperatures were recorded for 27 of the 81 CBs that their hit critical pressure level. With the exception of two CBs, the temperatures ranged from -8° F to -35° F. Some of these temperatures were estimated after the fact, based on historic weather data for that day/hour and for the vicinity of the substation.

Observations and Conclusions Observations of protection scheme philosophy when SF6 CBs hit critical low pressure:

- Auto-open vs. blocking at critical low pressure both appear to be routinely used schemes. - RTCA results may be compromised (for CBs that have blocked trips), thereby potentially putting

the BES in a less secure or unknown state. Observations of live tank mixed gas CBs:

- Mixed gas CBs perform exceptionally well down to -50° C (-58° F). - Mixed gas CBs do not rely on heaters. - Live tank mixed gas CBs are predominantly used in far northern locations where ambient

temperatures can readily reach -50° C. - Live tank mixed gas CBs may be more costly, requiring free standing CTs. - Back-fitting a dead tank CB with a live tank CB at an existing substation may be difficult. - Mixed gas CBs require more equipment to handle mixed gases.

Observations of dead tank SF6 CBs:


- SF6 dead tank CBs are very dependent on their tanks heaters to avoid hitting critical low pressure. - Only three members out of 12 (25%) performed inspections on tank heaters prior to winter. - Only two entities indicated they receive SCADA alarms for tank heater failures. - Wind speed can impact the effectiveness of the tank heaters and wind speed was significant

during this cold weather event. Lesson Learned: Live tank mixed gas CBs have proven to be very reliable performers down to the extreme cold temperatures that they are designed for (-50° C/-58° F). These types of CBs are predominantly used in far northern locations where ambient temperatures can readily reach -50° C. Mixed gas technology is the key to preventing condensation within the breaker tank during severe low temperature conditions. Since condensation doesn’t occur, pressure is maintained within the tank and heaters are therefore not required. This inherently makes these breakers more reliable since there is no reliance on tank heaters. Dead tank SF6 CBs are predominantly used by the MRO members within the US (with the exception of remaining oil tank CBs that are still in service). In the southern half of the MRO region, SF6 circuit breakers perform very well for the cold weather conditions that the southern portion of the region can experience. However, the northern portion of MRO (roughly the area north of Kansas and Missouri) relies on tank heaters to maintain SF6 pressure in their CBs during severe cold ambient temperatures. As can be seen from the query results, 56 CBs (70%) of the SF6 CBs that auto-opened or blocked their trip on January 29-30, 2019 had inoperable tank heaters. Another 11 heaters had unknown status. This is a key disadvantage of using dead tank SF6 CBs in cold weather climes: reliance of external tank heaters to maintain SF6 tank pressure to assure sufficient interrupting capability during a fault condition. Recommendation The maintenance and inspection of SF6 CB tank heaters prior to winter season is important to assure the heaters are available going into the winter season. Additionally, alarming for a tank heater failure can alert operations staff in advance that a CB may hit critical low pressure such that a maintenance crew can be scheduled. These are two best practices that several MRO entities have adopted to minimize the risk of having SF6 CBs block their trip or auto-open during severe cold weather conditions. In the event an SF6 CB reaches critical low pressure and blocks its trip, the Transmission Owner/Operator should assure that the contingency model involving that CB is updated and shared with all impacted TOPs and RCs such that all EMS models will accurately reflect the outage that will occur for fault clearing (breaker failure mode).

Click here for: Lesson Learned Comment Form

For more Information please contact:

NERC – Lessons Learned (via email) [email protected]

Source of Lesson Learned: MRO

Lesson Learned #: XXXXXXXX

Date Published: XX/XX/XXXX

https://www.surveymonkey.com/r/ll20200701

mailto:[email protected]


Category: Transmission Facilities, Bulk Power System Operations This document is designed to convey lessons learned from NERC’s various activities. It is not intended to establish new requirements under NERC’s Reliability Standards or to modify the requirements in any existing Reliability Standards. Compliance will continue to be determined based on language in the NERC Reliability Standards as they may be amended from time to time. Implementation of this lesson learned is not a substitute for compliance with requirements in NERC’s Reliability Standards.


AGENDA 6

PRS Business

c. Chair and Vice Chair Approvals

Bryan Clark, Director Reliability Assessment and Performance Analysis

Action Discussion

Report Bryan Clark will lead the discussion at the meeting.


AGENDA 7

NERC Activities

a. Update on NERC SPCS

Mark Gutzmann Director, System Protection & Communication Engineering, Xcel Energy

b. NERC MIDASWG Update


c. FERC/NERC Protection System Commissioning Program Review


Action Discussion

Report Mark Gutzmann and Mike Bocovich will provide oral reports during the meeting for the topics above.


AGENDA 8 Misoperations

a. First Quarter 2020 Results and Review Mike Bocovich, PRS Technical Liaison

Action Discussion

Report Mike Bocovich will lead this discussion during the meeting.

32% High Impact!



b. Minnesota Power System Conference Submittal regarding Misoperations John Grimm, PRS Chair and Mike Bocovich, PRS Technical Liaison

Action Discussion

Report Chair Grimm will lead this discussion during the meeting.



c. Survey of Protection System Scheme Type Mike Bocovich, PRS Technical Liaison

Action Discussion


TADS <200kV

TADS 230kV

TADS 345kV

TADS 500kV

TADS Total

Total Responded to Survey 1917 323 280 5 2084 MRO Total Circuits (Approx) 3109 399 419 6 3932 Percent of Total Reporting 61.66% 80.95% 66.83% 83.33% 53.00% Schemes Reported

DCUB 253 19 92 0 364 DCB 511 25 76 4 616 POR/POTT 1030 306 184 6 1526 DUTT 25 26 5 0 56 Phase Comparison 3 2 14 0 19 Differential 477 61 213 0 751 Other 0 6 0 0 6 Total for Voltage Class 2299 445 584 10 3338

Schemes Reported Percentage DCUB 11.00% 4.27% 15.75% 0.00% 10.90% DCB 22.23% 5.62% 13.01% 40.00% 18.45% POR/POTT 44.80% 68.76% 31.51% 60.00% 45.72% DUTT 1.09% 5.84% 0.86% 0.00% 1.68% Phase Comparison 0.13% 0.45% 2.40% 0.00% 0.57% Differential 20.75% 13.71% 36.47% 0.00% 22.50% Other 0.00% 1.35% 0.00% 0.00% 0.18%



d. Lessons Learned Updates i. 86 Lockout Relay Failures (NERC Review May 7, 2020)


Action Discussion



Lesson Learned Lockout Relay Component Failure Causes Misoperation and Reportable Event Primary Interest Groups Transmission Owners (TOs) Generator Owners (GOs) Distribution Providers (DPs) Problem Statement Unnecessary trips for nonfault conditions are problematic for any protective relay and can be particularly problematic for lockout relays. Lockout relays are typically used to isolate and hold BES electrical equipment out of service for extended periods of time to allow for visual inspection and typically result in the operation of multiple interrupting devices. Many lockout relay types require manual reset, meaning that field personnel must travel to the relay location, inspect, and perform switching to restore systems to service. The resulting extended abnormal operating condition of the system may put the reliability of the BES at risk. Figure 1 illustrates a recent example of a lockout relay misoperation. The lockout relay associated with 345 kV BKR A1 at Substation A misoperated during a nonfault condition, resulting in the trip of the circuit breakers circled in the figure. 345 kV BKR B1 at Substation B was out of service as part of a planned outage prior to the event. The breaker operations removed the following BES equipment from service as a result of the misoperation of this lockout relay:

345 kV transmission line for Substation A–Substation B–Substation C

345 kV transmission line for Substation A–Substation D

345/161 kV transformer A-T1 at Substation A Field personnel were dispatched to Substation A to investigate in response to this event. Their subsequent investigation determined that the lockout relay had failed due to a faulty lighted nameplate control circuit board. The investigation and repairs took approximately eight hours and the system was returned to the pre-event condition later the same day.

Lesson Learned: Lockout Relay Component Failure Causes Misoperation and Reportable Event 2

Figure 1: Breaker Operations Resulting from Lockout Relay Misoperation

Details It was determined the misoperation was due to a faulty lighted nameplate control circuit board within the lockout relay. A detailed investigation uncovered a 2014 product advisory note from the lockout relay manufacturer. The note documented a potential problem with the lighted nameplate circuit board on their lockout relays manufactured between 2000 and 2008. The note stated “…symptoms have included the nameplate LEDs not lit or flashing, the SCADA contact alarm on or intermittent and in a very few reported instances, failures resulting in an unintended breaker “trip/open” operation.” Figure 2 below contains photos of the failed circuit board that illustrate the circuit discoloration mentioned in the product advisory note.


Figure 2: Failed Lighted Nameplate Circuit Board from Lockout Relay

There was no record of receiving the manufacturer’s product advisory note in 2014 or thereafter prior to the event. If the note had been received, the wording was vague enough as to the risk of failure that it would not have caused excessive concern. The product advisory note concluded by suggesting customers consider replacement where the nameplates may have been subjected to elevated voltages or were exhibiting the symptoms described in the advisory note. Symptoms included the nameplate LEDs not lit or flashing, the SCADA contact alarm on or on intermittently in addition to discoloration of the board itself. The discoloration symptom of the lighted nameplate circuit board can only be observed by removal of the nameplate cover, which is not a standard practice during maintenance and is considered risky without taking an outage on the affected equipment. This event seems to indicate that the insulating material and electrical clearances used within the lighted nameplate controls may be less than adequate, resulting in dielectric breakdown and undesired breaker trip and lockout operations. The entity believed that this lockout relay had been operated within normal device specifications (i.e. control voltage and temperature). Lighted nameplate circuit boards have been replaced on a few other lockout relays that exhibited symptoms discovered after the event. Further research has revealed more entities have experienced similar lighted nameplate circuit board failures that had also caused unintended operations. Corrective Actions Conduct a system-wide survey to determine locations of lockout relays affected by the product advisory note. Work with the manufacturer to determine a corrective action that best fits constraints of the user.


The following actions have been implemented by different entities:

Replacement of the lighted nameplate circuit board with manufacturer recommended model on individual lockout relays.

Replacement of individual lockout relays with lighted nameplate circuit boards affected by the product advisory note with lockout relays of a different model.

Lesson Learned Improve the response to product advisories for existing or planned equipment:

When information is insufficient to determine the system risk or required corrective action associated with a product advisory, request additional details from the manufacturer, including in-service failures, and develop a corrective action plan that is suitable to individual requirements.

Processes and procedures are needed to ensure all future advisory notes are received from manufacturers of relay equipment employed and logged appropriately. Included in those needs to be a methodology to review each advisory, determine what actions are needed, and track the actions to completion.

Review previously received advisories to determine the need to apply the above process.

Survey manufacturers of equipment determined critical to BES reliability to assure all advisories have been received, logged, reviewed and assessed to the extent practical.

NERC’s goal with publishing lessons learned is to provide industry with technical and understandable information that assists them with maintaining the reliability of the bulk power system. NERC is asking entities who have taken action on this lesson learned to respond to the short survey provided in the link below.

Click here for: Lesson Learned Comment Form For more Information please contact: NERC – Lessons Learned (via email) Region Contact Information: [email protected]

Source of Lesson Learned: Midwest Reliability Organization

Lesson Learned #: LL20200703

Date Published: July 30, 2020

Category: Relaying and Protection Systems

This document is designed to convey lessons learned from NERC’s various activities. It is not intended to establish new requirements under NERC’s Reliability Standards or to modify the requirements in any existing Reliability Standards. Compliance will continue to be determined based on language in the NERC Reliability Standards as they may be amended from time to time. Implementation of this lesson learned is not a substitute for compliance with requirements in NERC’s Reliability Standards.



d. Lessons Learned Updates ii. Mixing Technologies in Blocking Schemes (NERC Review May 8, 2020)


Action Discussion



Lesson Learned Mixing Relay Technologies in Directional Comparison Blocking Schemes Primary Interest Groups Transmission Owners (TOs) Problem Statement Multiple composite protection system misoperations have occurred on the Bulk Electric System (BES) as a result of mixing protective relay technologies at the remote terminals of directional comparison blocking (DCB) schemes. One of the most challenging mix of technologies is utilizing a relay system based on newer microprocessors (μP) at one terminal and an older electromechanical (EM) relay system at the opposite terminal (examples shown in the figures below). Utilizing different models of μP based relays at each terminal can also be problematic. Often, only one terminal of a DCB system is upgraded to μP based relays due to various reasons, including different ownership of terminals, budget constraints, and emergency replacements. Relay timing and directional coordination is critical in DCB schemes that may be overlooked when relay technology or relay models vary between terminals. Details Electromechanical DCB Schemes DCB schemes that utilize EM relays are high speed protective schemes that use very fast phase and ground fault detectors to transmit or “start” a blocking signal by opening contacts. Opening contacts to start a blocking signal allows quicker operation by minimizing the time required to overcome inertia in EM relays. It is common to have this blocking signal transmission initiated within a quarter cycle of the start of a fault in EM DCB schemes. Also in this scheme, one cycle or more is usually required for EM relays to determine the directionality of a fault and issue a trip to open a local breaker if the fault is internal to the line. This time difference between block and trip provides an inherent margin of error within EM schemes for relays at the remote terminal(s) to receive a blocking signal and prevent tripping for faults beyond the remote terminal. Figure 1 demonstrates this timing difference between block and trip associated with EM DCB schemes. The blocking signal is started and received at both terminals before the directionality of a fault is determined between either internal or external faults. Once directionality is determined and it is found that a fault is internal, the blocking signal is removed and tripping is allowed at the opposite terminal.

Lesson Learned: Mixing Relay Technologies in DCB Schemes 2

Figure 1: Approximate Timing Associated with a typical EM DCB schemes

Microprocessor DCB Schemes Microprocessor DCB schemes work under the same protocols and similar protection elements as an EM scheme. However, due to the need for internal filters in the relay, most (not all) μP relays require one cycle of information to determine that an electrical fault has actually occurred versus the quarter cycle for EM schemes. Thus, μP relays cannot start sending a blocking signal until this determination is made. A time delay between detection of the fault and relay decision to trip is also required to allow for the transmission and receipt of the blocking signal from the remote terminal(s). In addition to this time delay and for the security of the scheme, it is prudent to include an additional margin of time. Figure 2 demonstrates a timing scenario associated with some μP DCB schemes for external faults. No blocking signal should be transmitted for internal faults, and tripping of local breakers should occur after the relay senses the internal fault and the allotted time margin to receive the blocking signal has expired.


Figure 2: Approximate Timing Associated with typical μP DCB Schemes Mixing Technologies Mixing these technologies between EM and μP relay models can introduce timing problems. The EM relay can send a blocking signal fast enough for the remote μP terminal to detect and block tripping for external faults. However, the μP relay at the remote terminal may not send a blocking signal until after the EM terminal relay(s) has made a decision to trip, thus causing the EM end to incorrectly trip. Figure 3 demonstrates likely timing problems associated with mixing these technologies.


Figure 3: Timing Demonstrated with Mixing EM and μP Technologies


1 https://www.nerc.com/comm/PC/Protection%20System%20Misoperations%20Task%20Force%20PSMTF%202/PSMTF_Report.pdf

Timing Issues with Mixing EM and μP Technologies Timing differences are seen when differing technologies are used at opposing terminals. In general, Electro-mechanical relays are seen as slower to operate than solid-state or microprocessor-based relays. However, Electro-mechanical relays are usually quicker than most microprocessor based relays regarding sending a blocking signal. In April 2013, the Protection System Misoperation Task Force (PSMTF) issued the Misoperations Report1. It has information relevant to this Lessons Learned: On page 34 – “…As a practice, the timing issues should be studied and the appropriate delays applied to the faster terminal to allow for coordination. Timers available in both microprocessor-based relays and newer carrier equipment can be used to eliminate most misoperations due to carrier signal dropout during faults. Use of a carrier hole override timer on digital systems may be used, in part, to replace the override inherent in the magnetic circuits of electro-mechanical systems. While carrier hole timers can provide added security to DCB schemes, they may also mask carrier system setting or component deficiencies. Similar to carrier coordination timers, care should be applied to avoid unwanted interactions with other DCB logic. Intermittent carrier signals are often an indication that maintenance is required. The recording and logic capability of these newer devices can be used to detect carrier holes and alert maintenance personnel to the need for maintenance. Regular maintenance of coupling equipment, wave traps, and spark gaps can improve communication performance.” On Page 35 - “Proper Application of Relay Elements Applications requiring coordination of functionally different relay elements should be avoided. This type of coordination is virtually always problematic, and is the cause of numerous misoperations reported in the study period. Some examples to avoid include:

coordination of distance elements and overcurrent elements

coordination of distance or directional overcurrent elements that use different directional polarization methods

distance and directional overcurrent elements at opposite line terminals that use different directional polarization methods, particularly in the same pilot scheme

overcurrent elements that use different measurement methods, such as phase vs. residual ground vs. negative-sequence current measurement

If mixed measurement or polarization methods cannot be avoided, then there must be a clear understanding of how these elements respond to different fault types under normal and abnormal source conditions to ensure their proper application and coordination.”


Corrective Actions The best and preferred method to mitigate the problems discussed is to assure all terminals of a single composite protection scheme utilize the same manufacturer, make, and model of protection equipment to implement a DCB scheme. When utilizing the same equipment at all terminals of a DCB scheme is not possible, the following corrective actions have been used to mitigate timing issues associated with mixing technologies or μP relay models in DCB schemes:

Add an additional time delay(s) where required to prevent tripping by allowing the block signal(s) to be received from the remote system(s) or introduce an additional time delay where the remote system(s) may be slower to transmit the blocking signal.

Start the μP blocking signal transmission quickly at the earliest signs of a fault on the system then remove the blocking signal after relays have determined directionality and security timing margins have expired. Some μP relays do provide a high speed, nondirectional, current-only fault detector that can be used to start blocking signal communications. The blocking signal can then be removed if required after correct directionality of the fault is determined.

Disable the DCB tripping at the faster terminal until the relay system can be replaced with a like-kind relay system (ensure blocking remains enabled). This option may be dependent on system studies to determine if a high speed tripping scheme is required at the affected terminal.

Lesson Learned It is imperative that sufficient time be provided to first receive a blocking signal from the remote terminal in any DCB schemes prior to permitting a trip. The timing of the protection elements at each terminal of a DCB scheme must be understood so as to provide appropriate time margins in the receipt of a blocking signal from the remote terminal. The following actions could be applied to prevent problems associated with mixing technologies in DCB schemes:

Establish a design philosophy that does not mix relay technology (incl. different manufacturers and models) in directional comparison blocking (DCB) schemes.

Work with neighboring entities to eliminate mixing relay technology at the ties/seams.

If unable to avoid mixing relay technologies in DCB schemes, consider corrective actions listed above.

NERC’s goal with publishing lessons learned is to provide industry with technical and understandable information that assists them with maintaining the reliability of the bulk power system. NERC is asking entities who have taken action on this lesson learned to respond to the short survey provided in the link below. Click here for: Lesson Learned Comment Form


NERC – Lessons Learned (via email) MRO – RAPA


Source of Lesson Learned: Midwest Reliability Organization

Lesson Learned #: 20200701


Category: Relaying and Protection Systems

This document is designed to convey lessons learned from NERC’s various activities. It is not intended to establish new requirements under NERC’s Reliability Standards or to modify the requirements in any existing Reliability Standards. Compliance will continue to be determined based on language in the NERC Reliability Standards as they may be amended from time to time. Implementation of this lesson learned is not a substitute for compliance with requirements in NERC’s Reliability Standards.



d. Lessons Learned Updates iii. Verification of AC Quantities during Protection System Design and Commissioning


Action Discussion



Lesson Learned Verification of AC Quantities during Protection System Design and Commissioning

Primary Interest Groups Transmission Owners (TOs) Transmission Operators (TOPs) Generation Owners (GOs) Generation Operators (GOPs)

Problem Statement Failure to employ effective commissioning testing practices or effective quality checks of protection system designs when installing or modifying protection systems can lead to protection system misoperations. These can occur with all components of protection systems, but issues with voltage and current instrument transformer wiring regularly surface when protection system misoperations occur. Protection system misoperations have an immediate negative impact on the reliability of the bulk power system and may cause a significant increase in the magnitude and scope of a disturbance.

It should be noted that this lessons learned document is an expanded version of the NERC lesson learned document titled “Verification of AC Quantities during Protection System Commissioning” that was issued on March 11, 2014. The document has been expanded to provide additional guidance based on events noted since 2014.

Details Event 1: Effective commissioning and testing practices were not implemented during the installation of a new transformer. As a result, associated line relays were placed in service with the incorrect CT ratio. The defect remained undetected until the occurrence of a system disturbance when the relaying operated incorrectly, increasing the disturbance’s magnitude and scope.

Event 2: Effective quality checks of a protection system design and effective commissioning testing practices were not implemented. As a result, associated transformer relays were placed in service with a missing connection in a residual current circuit. This defect remained undetected until the occurrence of a system disturbance when again a misoperation resulted, increasing the disturbance’s impact and resulting in a significant loss of load and impact on BES equipment.

Corrective Actions Event 1: The entity re-wired the affected relays to the correct CT ratio, and an in-service test was performed to verify current magnitudes and phase angles were correct.

Lesson Learned: Verification of AC Quantities During Protection System Design and Commissioning 2

Event 2: The entity re-wired the affected relays to the correct the missing connection in the residual current circuit and performed primary injection current testing to verify connections. Lesson Learned

Design Accountability

The goal of engineering groups must be to issue error free protection system designs. Protection system designs should include appropriate independent reviews and quality checks to detect errors before releasing to the field. Quality checks should be performed for both schematic diagrams and wiring diagrams. An effective quality program will include clear direction on whether engineering, design, or testing personnel are responsible for verification of the accuracy of wiring diagrams. The IEEE working group documents, I12 ”Quality Assurance for Protection and Control Design” and I25 “Commissioning Testing of Protection Systems,” both provide additional discussion on practices to help prevent errors in protection system designs.

Commissioning testing must include installation tests and effective in-service tests. In-service tests provide an overall check of current and potential circuits to verify these circuits are properly connected and that measured levels of voltage and current are as expected. In-service tests can uncover errors not discovered during installation tests.

The System Protection and Control Subcommittee put together some guidance for commissioning testing in Attachment 1.

NERC’s goal with publishing lessons learned is to provide industry with technical and understandable information that assists them with maintaining the reliability of the bulk power system. NERC is asking entities who have taken action on this lesson learned to respond to the short survey provided in the link below. Click here for: Lesson Learned Comment Form


NERC – Lessons Learned (via email)

Source of Lesson Learned: ERO Team (Multi-Region)

Lesson Learned #: 20200702


Category: Relaying and Protection Systems This document is designed to convey lessons learned from NERC’s various activities. It is not intended to establish new requirements under NERC’s Reliability Standards or to modify the requirements in any existing Reliability Standards. Compliance will continue to be determined based on language in the NERC Reliability Standards as they may be amended from time to time. Implementation of this lesson learned is not a substitute for compliance with requirements in NERC’s Reliability Standards.


Attachment 1 Commissioning Testing Cautions: An open circuit on an in-service CT can produce a high voltage up to 1000 volts or more depending on CT characteristics. Testing personnel performing in-service CT checks should have training and awareness of the potential of high voltage, plan work appropriately, and follow all applicable company safety procedures. Additionally, the consequences of a fault occurring on the primary equipment during in-service testing procedures must be considered prior to isolating protective relay systems to facilitate testing. In-Service Voltage Tests In-service tests of voltage circuits consist of comparing voltage magnitudes and phase angles of newly installed circuitry with known proper voltage magnitudes and phase angles of an unaffected circuit at the same location. The reference circuit should be connected to the circuit with the newly installed equipment at the same primary voltage level. In-service tests to verify all phase voltages are correct in terms of magnitude and angle should be done by comparing direct measurements of the voltage magnitudes and phase angles, metered quantities, fault recorder records, etc. of newly installed relays with the reference circuit. Loading of a new circuit is not required to perform in-service voltage tests. Where external zero sequence voltage is used for determining fault direction in a protective relay, this voltage also needs to be verified. When relays calculate zero sequence voltages directly from the phase voltages, only phase voltage in-service testing is necessary. In-service tests for zero sequence voltage quantities (if required) are done by removing one of the phase voltages on either the primary or secondary side and verifying that the zero sequence voltage magnitude and phase angle is as expected per calculation. In-Service Current Tests General Considerations for In-Service Current Tests In-service tests of current circuits consist of comparing current magnitudes and phase angles of newly installed circuitry with known, proper current magnitudes and phase angles of an unaffected circuit or circuits. The reference circuit or circuits may be at the same location or other locations. In-service tests should be done to verify magnitude and angle of all phase currents, residual currents, and zero sequence polarizing currents. When relays calculate residual current directly from phase currents, the residual current circuit still needs to be verified as intact via primary current tests and/or secondary current tests. Various additional factors may need to be taken into consideration when comparing current circuits. For example, if a relay is changed at one end of a two-terminal 230kV transmission line, currents could be compared with the other end of the transmission line to determine proper connections. However, the current magnitude and phase angle at one end of a line will not be exactly the same as at the other end of the line due to loads tapped off the line, line charging current (especially on long lines), tapped shunt loads, phase shifting transformers, etc. Secondary currents may also be different due to the use of different CT ratios at the ends of the line. Similar considerations may be required in order to test installations with other


varying configurations. Testing personnel must be cognizant of these factors and consider them when performing and interpreting in-service current test results. Phase Current In-Service Current Tests In-service tests for phase current quantities are done by comparing measurements of newly installed relays with other known, undisturbed relays and circuits by comparing the direct measurements of the current magnitudes and phase angles, metered quantities, fault recorder records, etc. Loading of a new circuit, at a measurable level, is required to perform in-service current tests. When system conditions are such that loading of the new circuit is too low to accurately verify proper magnitude and phase angle of the new current circuits, system reconfiguration will be temporarily required to attain a sufficient level of load to attain a measurable level of current. Residual Current In-Service Current Tests Testing and verifying residual currents are correct can be more challenging than testing and verifying phase currents are correct. Where the relays being checked are connected in the residual current circuit, the method employed to verify that residual current is proper will depend on the type of relay and the presence of residual current on the primary circuit while performing the test. Verification of magnitude and phase angle in the residual current circuit of an electromechanical relay requires direct measurement in the circuit. To verify residual current in an electromechanical relay, one method is to force residual current to flow in the relay by bypassing a phase current around the relay. In order to minimize the chance of an open circuit during this type of testing, it is recommended that secondary current testing of the CT circuit be done prior to performing this test. A generic illustration of this is shown in the figure below.


Aɸ Relay

Bɸ Relay

Cɸ Relay

Residual Relay Under Test

Temp Open for TestTemp Jumper

for Test

To Aɸ CT

To CT Neutral

To Cɸ CT

To Bɸ CTIA* IB*

IC*

IB + IC*IRES*

*Current Flow during In-Service TestNote: Test Switches not shown

If circuit loading is high enough and enough imbalance between phase currents is present, a measurable level of residual current may exist. In this case a second method of verifying residual current is to compare the directly measured residual current with the calculated residual current based on the verified phase currents. This comparison should be done in a relatively short time period where circuit loading is stable. The residual current input to a modern relay can be verified by comparing the relay’s phase currents versus its residual current using the relays metering capability or fault recorder records. When relays calculate residual current directly from phase currents, the residual current circuit still needs to be verified as intact via primary current tests and/or secondary current tests. Some types of equipment (e.g. generators, generator step-up transformers, transformers with delta windings) have very low levels of residual current or no residual current under load conditions. Thus, in-service measurement of residual current is not an effective method of verifying proper residual current in relays in these circuits. In these cases, the only secondary current method to verify residual current is to force residual current to flow in the relay by bypassing a phase current around the relay. Zero Sequence Current Polarizing In-Service Current Tests Zero sequence current polarizing quantities generally come from current transformers in transformer neutrals or delta windings. Similar to the discussion on residual current verification above, some transformers may have adequate zero sequence current to make in-service measurements. Some transformers may have very low or no zero sequence current under loading conditions. In these cases, secondary circuit installation tests may be solely relied on to verify proper connection of zero sequence currents.


Transformer Neutral Differential (87TN) In-Service Current Tests Transformer neutral differential relay schemes, also called restricted earth fault schemes, may be used on transformers to provide sensitive detection of ground faults on transformer low side windings or leads. A generic illustration of this scheme is shown in the figure below. Testing and verifying residual and neutral currents are correct for electro-mechanical implementations of these schemes can be more challenging than testing and verifying phase currents are correct. In-service testing of the residual, neutral, and operating current circuit portions of an electro-mechanical 87TN relay scheme depends on the presence of zero sequence load current. If circuit loading is high enough and enough imbalance between phase currents is present, a measurable level of neutral and residual current may exist. In this case, residual and neutral currents can be measured and compared to the calculated residual current based on the verified phase currents. In addition, the residual and neutral currents should be 180 degrees out of phase and the operating current can be verified to be zero. These comparisons should be done in a relatively short time period where circuit loading is stable. If no measurable residual current exists, testing the residual circuit portion of an electro-mechanical 87TN relay can be accomplished in the same manner as described in the discussion above titled “Residual Current In-Service Current Tests”. If no measurable neutral current exists, the neutral and operating current circuits cannot be verified via in-service tests. Therefore secondary current continuity checks or primary current tests (see section below) must be completed to verify circuit integrity. In a microprocessor-based relay, the residual current is generally derived from the phase currents and the neutral current is a direct input to the relay. In this case, the residual current circuit still needs to be verified as intact.


Transformer High Side Transformer Low Side

Added Impedance in the Neutral

R87TN

Transformer Neutral Differential

RorX

Primary Current Tests Some entities employ the practice of performing a primary current test (sometimes also called a through-fault test) prior to placing equipment in service. This type of test is typically done on bus or transformer relays and consists of injecting primary current from a test source through the primary equipment and associated current transformers under test. Expected current magnitudes and phase angles are calculated prior to testing and verified during testing. Primary current tests can be three-phase or single-phase. Single-phase tests on transformers can be used to verify proper magnitudes and directions of residual currents, transformer neutral currents, and polarizing currents (if used). Single-phase tests will verify these circuits when in-service tests may not be accomplished (?). These types of tests can be costly and lengthen the time for equipment to return to service. Each entity should determine whether the extra effort to perform these types of tests is justified based on its own circumstances. A high-level illustration of a single-phase primary injection test for a transformer neutral overcurrent is illustrated below for reference.


Transformer High Side

Transformer Low Side

Added Impedance in the Neutral

R87TN

Transformer Neutral Differential

RorX

Test Current Flow

Current in the 87TN is Zero for the external fault test

If ground is placed here, current in the 87TN is non-zero, simulating

an internal fault

Place 3-phase source (120, 208, 480, etc. volts) as required

Test is performed with Transformer High and Low Side disconnecting devices open and tagged out of service.

Exact voltage required is determined by calculation and limitations of measuring instruments.

Expected currents during test are calculated prior to test.

Place a single ground here.Test each phase seperately

Another type of primary test that verifies overall circuit continuity and proper polarity connections is a “DC pulse test” or “kick test”. In this test, the primary side equipment is taken out of service and isolated. Then, a low voltage DC battery (e.g. 15 volts) is applied on the primary side of the circuit under test so a DC current will flow through the primary side of the circuit CT or CTs. When the battery is applied, the primary side DC current results in a short pulse of current on the secondary side of the CT. This pulse of secondary side current can be measured. The direction of the secondary side current and associated voltages are dependent on the polarity of the primary battery connections. The short pulse of secondary side current can be seen, for example, by the movement of a DC analog voltmeter’s pointer. If the DC voltmeter is connected to verify a positive voltage pulse and the meter’s pointer deflects in the negative direction, it is an indication of incorrect wiring of polarity connections in the CT circuit somewhere. This type of test can be done for a wide variety of circuit types and CT connections. A high-level illustration of a DC pulse test for a transformer neutral overcurrent is below for reference.


Transformer High Side

Transformer Low Side

R87TN

DC Pulse or Kick Test

RorX

The Delta Side winding magnetically coupled to the Wye Side phase under test must be shorted to allow current flow. An alternative would be to connect the battery to all three phases on the low side to allow for zero sequence current to circulate in the Delta.

Test 1: There will be minimal deflection of the voltmeter pointer when switch 1 is closed for test 1. There will also be minimal deflection of the voltmeter pointer when switch 1 is opened at the end of 1.

Test 2: There will be positive deflection of the voltmeter pointer when switch 2 is closed for test 2 when all polarities and circuit connections are correct. There will also be a negative deflection of the voltmeter pointer when switch 2 is opened at the end of 2 when connections are correct.

Note: Repeat the tests for all three phases.

Switch 2

Switch 1

VVV

R

inter t 1. lection switch

VV

+

Secondary Current Tests In-service tests and primary current tests are overall functional tests of current circuits. Secondary current tests are performed earlier in the installation process and include continuity tests and tests to verify a single ground in the CT secondary circuit. Although useful they are not in and of themselves sufficient to preclude the performance of in-service and primary service current tests. These tests do not verify overall circuit function to the level of in-service or primary current tests, but a properly performed secondary current tests will identify secondary circuit wiring issues, secondary grounding issues, etc. so they can be addressed prior to overall functional testing. An example of two methods to perform such tests are below.


Aɸ

Cɸ

Bɸ

Test 3: Verify that light bulb is dimly lit or read current to verify it is less than Test 2 due to impedance of CT.

52

Secondary Current Test 1 (Lamping)

Test 2: Verify that light bulb is lit at full brightness or read current to verify no impedance between light bulb and ground.

Test 1: Remove single point ground and verify no other grounds. Replace single point ground in circuit after test.

Repeat continuity tests for B, C, and residual CT circuits.

120V sourceLight Bulb

mpingg))

1Light Bulb

120V source

Open for

Test


Aɸ

Cɸ

Bɸ

52

Secondary Current Test 2 (current injection)

Notes: - Disconnect the CT circuit ground prior to the test as some test kits may have an internal ground that would present a parallel path to test current that could give a false indication of proper circuit flows.- The CT presents a high impedance compared to the relay side of the secondary circuit. Therefore, there is no need to open the circuit during this test.- The primary Circuit Breaker is out of service during this test.

Open for Test

(see notes)Test Kit

(ss )Test

see notes)000.00

OOpen for Test

Measure 1.73 @-150 deg

4 Amps at 120 deg

3 Amps at -120 deg

2 Amps at 0 deg

CT Tests CT tests, like secondary current tests are performed earlier in the installation process and do not verify overall circuit function to the level of in-service or primary current tests. CT tests will verify that the CTs installed have the specified ratio/ratios, specified saturation characteristic, and are installed with proper polarity.


AGENDA 9

Event Analysis Report

Jake Bernhagen, MRO Sr. Systems Protection Engineer and

David Kuyper, MRO Power System Engineer

Action Information

Report Jake Bernhagen and David Kuyper will provide an oral report during the meeting regarding any

Transmission Events that have occurred since the last PRS meeting.


AGENDA 10

Update on SPS Review Team Activities

David Kuyper, MRO Power System Engineer

Action Information

Report David Kuyper will provide an oral report at the meeting.


AGENDA 11

TPL-001-5 Footnote 13


Action Discussion



AGENDA 12

PRS Roundtable Discussions


Action Discussion



AGENDA 13

Upcoming PRS Meeting Dates


Action Discussion



AGENDA 14

Other Business and Adjourn


meeting agenda - midwestreliability.org · john grimm stated there is a full agenda, and there will...

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