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October 17, 2018 Open Phase Condition Public Meeting -NEI Slides
	ML18289A992
Person / Time
Site:	Nuclear Energy Institute
Issue date:	10/17/2018
From:	Geier S; Nuclear Energy Institute
To:	Jessie Quichocho; NRC/NRR/DE/EEOB
	Perkins L
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ML18309A226	List: ML18289A980; ML18289A992;
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NEI / Industry Member Response to NRC Questions on Industry Actions on OPCs NRC Public Meeting - Industry Actions on Open Phase Conditions (OPCs)

October 17, 2018

Agenda

Overview - Frankie Pimentel

NRC Observation Responses:

4 - Surveillance and LCO Requirements in Plant TS Brian Mann (Excel Services)

2 - OPC Protective Action Wesley Kijowski (Duke)

Kazimierz Leja (Exelon)

Robert Carritte (MPR)

3 - UFSAR Update Mitchel Mathews (Exelon)

Overview

NEI / Industry members prepared responses to questions provided by NRC in ML18249A379 - Preliminary Evaluation of OPC Voluntary Industry Initiative (VII)

September 19 Public Meeting provided clarity and understanding on some questions For NRC Observation 1- OPC Detection and Alarm, there were no NRC questions as the detection and alarm design schemes were observed as technically adequate

NEI member representatives will present responses to the NRC observation questions

2- OPC Protective Action Questions Presented by Wesley Kijowski - Duke Kazimierz Leja - Exelon Robert Carritte - MPR

2- OPC - Protective Actions NRC Observations (ML18271A111)

Three of the designs incorporated defense-in-depth features such as redundant channels and coincidence trip logic which will minimize spurious trip of the offsite power system. One licensee used a single channel detection and protection scheme to mitigate the effects of OPCs. In general, all four protection aspects of the design are capable of mitigating an OPC with and without an accident if no failures are assumed in the OPIS system.

The staff is interested in understanding how the OPIS designs consider potential failures, and how the VII criteria will be met during potential failures.

NRC Questions (ML18271A111)

a. What actions are being taken to mitigate the potential consequences resulting from a potential OPIS failure? How do these actions meet the OPC VII criteria?

b. If there was a failure of the OPIS, how would the plant meet the provisions for single failure of the onsite power system to mitigate against DBAs? If so, describe how.

2- OPC - Protective Actions Question 2.a.: What actions are being taken to mitigate the potential consequences resulting from a potential OPIS failure? How do these actions meet the OPC VII criteria?

Answer 2.a.:

OPIS failures:

Fails in non-trip state - does not result in loss of the offsite power circuit or affect functionality of connected equipment.

Fails and spuriously actuates - consequences bounded by the response of the existing protective relaying system to malfunctions that result in spurious protective actions.

Affected source would be isolated and plant responds accordingly (i.e. load transfer).

Actions taken to mitigate potential consequences from a potential OPIS failure:

Operators alerted of OPIS failure / malfunction via Main Control Room (MCR) alarm(s). OPIS are self-checking and capable of providing indication upon failure or malfunction.

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2- OPC - Protective Actions Answer 2.a.(cont.):

Operators implement appropriate measures per procedure

Interim measures similar to those implemented during installation and monitoring of OPIS (i.e. operator rounds, monitoring bus voltages, etc.)

Training completed to identify indications of OPCs (i.e. bus voltages, equipment status, overhead line connections)

Corrective Action Program would be utilized to minimize the time that OPIS is non-functional

Screened and assigned significance level based on site criteria / procedure and addressed appropriately

Expected that issues would be resolved within days to weeks depending on type of failure A non-functional relay would also need to be identified as an Unresolved Maintenance Issue per NERC Standard PRC-005-6 (if applicable) and require the site to demonstrate efforts to correct the issue further ensuring a timely repair.

2- OPC - Protective Actions Answer 2.a.(cont.):

Example OPS Response & Interim Actions - Byron: Annunciator Response Procedure

2- OPC - Protective Actions Answer 2.a.(cont.):

Example OPS Response & Interim Actions - Byron

2- OPC - Protective Actions Answer 2.a.(cont.):

Example Response to a Reactor Trip or SI - Byron (cont.)

In response to a Reactor Trip or SI, the procedure already directs operators to verify power to 4kV ESF Buses in step 3, thereby quickly identifying the open phase (if present) based on available indication in the MCR (voltage, current, equipment status, OPIS alarms)

2- OPC - Protective Actions Answer 2.a.(cont.):

These actions meet the OPC VII criteria since:

The OPIS failures described previously either do not affect offsite power availability or are bounded by the response of the existing protective relaying system to malfunctions.

Per the VII, OPIS failures favor non-trip state to minimize misoperation that could cause spurious separation from an operable off-site GDC 17 source. An OPIS failure, which could cause spurious actuation, results in actions that are bounded by current design and licensing basis (e.g., LOOP).

Interim measures are implemented until OPIS is restored

2- OPC - Protective Actions Question 2.b.: If there was a failure of the OPIS, how would the plant meet the provisions for single failure of the onsite power system to mitigate against DBAs? If so, describe how.

Answer 2.b.:

An OPC, OPIS failure and a DBA are independent events. Simultaneous occurrence of three independent events is not considered credible.

An OPIS failure does not affect the plants ability to mitigate a DBA given a single failure in the onsite power system, since OPIS failures either do not affect offsite power availability (non-trip) or are bounded by the response of the existing protective relaying system to malfunctions (spurious actuation).

OPIS is an enhancement to the electric power system design on the offsite power circuit.

Single failure criterion, as defined in IEEE 279 and IEEE 603, is not applicable to OPIS since these systems do not trip the reactor or actuate an engineered safety feature.

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2- OPC - Protective Actions Answer 2.b.(cont.):

Table 1, which was included in the March 2016 Regulatory Summary Document (ML16091A100), identifies applicable failure modes including single failure criteria in the onsite power system:

2- OPC - Protective Actions Answer 2.b.(cont.):

Scenario #1: An OPC occurs on an offsite power circuit and is isolated by the OPIS which is functional. Loads are transferred to a healthy source and the onsite power system remains operable.

Scenario #2: A single train of the onsite power system is inoperable with the other remaining operable. OPIS and the offsite power system are both functional.

Scenario #3: OPIS is non-functional and unable to isolate an OPC - notification is provided in the MCR of the failure. The affected offsite power circuit is Operable but temporary interim measures are implemented until OPIS is restored. The onsite power system remains operable.

Scenario #4: OPIS malfunctions and spuriously isolates one offsite power circuit.

Loads are transferred to a healthy source and the onsite power system remains operable.

2- OPC - Protective Actions Answer 2.b.(cont.):

The loss-of-single-phase event is not explicitly modeled in the current PRA model of record. Adding it to the PRA would be expected to have the following effect (Table 2).

Table 2:

- Byron Station

QUESTIONS?

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3- UFSAR Update Questions Presented by Mitchel Mathews - Exelon

3- UFSAR Updates Initiative Guidance The Updated Final Safety Analysis Report (UFSAR) must be updated to discuss the design features and analyses related to the effects of, and protection for, any open phase condition design vulnerability. This update would typically be to chapter 8.

NRC Questions What is NEIs expectations for updates to UFSAR with regard to the level of technical content detail and schedule for implementation? What is sufficient detail to reflect the licensing basis for protection against OPCs? Could you provide examples?

Industry Expectations for Level of Detail Expect licensees to update their UFSAR by following the NRC-endorsed guidance for adding new information to the UFSAR and complying with 10 CFR 50.71(e).

3- UFSAR Update Level of Detail Industry Expectations for Level of Detail (cont.)

Specifically, NEI 98-03, Guidelines for Updating Final Safety Analysis Reports, Revision 1, as endorsed by RG 1.181, Content of the Updated Final Safety Analysis Report in Accordance With 10 CFR 50.71(e).

Section 6.2, Level of Detail for FSAR Updates

. . . The description shall be sufficient to permit understanding of the system designs and their relationship to safety evaluations.

As described in 1980 FSAR update rule - The level of detail to be maintained in the UFSAR should be at least the same as originally provided.

Thus, existing UFSAR information of a similar nature may provide a guide for determining the level of detail for new information to be included in UFSAR Updates.

. . . .primary consideration . . . . sufficient to permit understanding of new or modified safety analyses, design bases and facility operation.

Relationship of 10 CFR 50.2 Design Bases and Supporting Design Information to the UFSAR and Licensing Basis 10 CFR 50.2 Commitments Design Bases Supporting Design Information UFSAR Licensing Basis 20

3- UFSAR Update Level of Detail Byron UFSAR Update Example -

Section 8.3.1.1.2.1, Distribution and Normal Offsite Power Sources Breaker 1412 (SAT 142-1 feed breaker to Bus 141) can only be closed manually and is interlocked by breakers 1414, 2412, and 2414 such that at least one of the three must be open. It interlocks the close circuit of breakers 1413, 1414, 2412 and 2414. Automatic trips will occur on a bus undervoltage load shed condition, a SAT fault, a bus fault condition, or upon a loss of phase on the feed to the SAT. 21

3- UFSAR Update Level of Detail UFSAR Update Example (Proposed - Harris)

An open phase protection system with four channels was installed for each of the start-up transformers to isolate the respective start-up transformer in the event of single (one of three) and double (two of three) open phase conductors on the high voltage (230kV) side of the start-up transformer. This includes open phase conditions with and without a ground.

The open phase protection systems ensure that plant structures, systems, and components important to safety do not receive unbalanced power from the offsite source as a result of the postulated open phase conditions. Upon detection of an open phase condition by two channels of the open phase system, the condition will be annunciated in the main control room and the respective start-up transformer will be automatically tripped. If only a single channel detects the open phase or the open phase system detects system trouble an open phase system trouble alarm will be annunciated in the main control room.

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3- UFSAR Update Level of Detail UFSAR Update Example for Level of Detail The impact of open phase conditions on the capability of the [add name of transformers] transformers was evaluated. The conditions analyzed consisted of single (one of three) and double (two of three) open phase conductors on the high voltage

([add voltage rating]) side of the [add name of transformers] transformers. The analysis considered open phase conditions with and without a ground. Open phase detection and isolation systems for the transformers were installed in accordance with the NEI Open Phase Condition Initiative. Upon detection of an open phase condition,

[describe the alarm functions and automatic actions]1 occur.

1 Dependent on a stations modification process, a station may elect to initiate UFSAR updates using a two step approach for alarm functions and then for automatic actions

3- UFSAR Update - Timing Timeframe for Updating the UFSAR

Per VII, licensees are expected to perform their UFSAR updates in conjunction with their installation timelines and as required per the stations modification process.

As discussed in NEI 98-03, Section 6.1, What the Regulations Require, Per 10 CFR 50.71(e)(4), the UFSAR is required to reflect changes up to a maximum of six months prior to the date that the last update was submitted to the NRC.

Licensees are expected to ensure that their UFSAR is updated accordingly.

QUESTIONS?

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4- OPC Surveillance & LCO Requirements in Plant TS Presented by Wesley Kijowski - Duke Kazimierz Leja - Exelon Robert Carritte - MPR

4- Surveillance & LCO Requirements (cont.)

Question 4: What type of periodic tests, calibrations, setpoint verifications or inspections are anticipated to be established, consistent with the VII?

Answer 4:

TS surveillance & LCO requirements are discussed in another presentation

Consistent with the VII, It is anticipated that stations will review Maintenance Rule

& NERC applicability and associated maintenance requirements / frequencies Example: At Byron, the SEL-451 relays have been classified as monitored microprocessor protective relays according to NERC PRC-005-02 criteria and have a maximum maintenance interval of 12 years

If not within NERC scope, maintenance activities will be developed utilizing vendor guidance & PMs currently utilized for similar plant equipment Example: PSStech recommends that the Active Neutral Injection System be tested on an annual basis utilizing the Active Test Function.

PMs controlled via PM program

QUESTIONS?

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Summary Discussion

Next Steps

ML18289A992

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