ML15131A448

Reactor Oversight Process Task Force FAQ Log - April 16, 2015

ML15131A448
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Site:	Prairie Island
Issue date:	05/07/2015
From:	Andrew Waugh NRC/NRR/DIRS/IPAB
To:	Nathan Sanfilippo NRC/NRR/DIRS/IPAB
Andrew Waugh 301-415-5601
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Enclosure 2 Reactor Oversight Process Task Force FAQ Log - April 16, 2015

FAQ Log Entering April 16, 2015 ROPTF Meeting FAQ No. PI Topic Status Plant/Co. Point of Contact 14-08 MS06 Prairie Island Introduced 11/19/2014. Generic Laura Jean Noonan Lockout Discussed 12/11/2014. (Xcel)

Responses to NRC questions Karla Stoedter received at 12/11/2014 (NRC) meeting were discussed in 02/19/2015 online meeting.

Final 03/18/2015 14-10 PP01 Indian Point Introduced 12/11/2014. Plant-Specific Brian Rokes Security Discussed 01/15/2015 and to Indian (Entergy)

Upgrade 02/19/2015. Point 2,3 NRC TBD Final 03/18/2015 15-01 IE04 Perry Scram, Introduced 02/19/2015. Generic David Lockwood October 20, (First Energy)

Discussed 03/18/2015; 2014 proposed change to NEI 99-02 Mark Marshfield was revised 03/24/2015 and (NRC) 04/15/2015 to clarify page 25 of NEI 99-02.

For more information, contact: James Slider, (202) 739-8015, jes@nei.org Page 1 of 1 Revised 04/15/2015

NEI 99-02 FAQ 14-08 Prairie Island MSPI Plant: Prairie Island Nuclear Generating Station (PINGP) Unit 1 Date of Event: June 23, 2014 Submittal Date: November 18, 2014 Licensee

Contact:

Laura Jean Noonan Tel/email: 651-267-6449 / Laura.Jean.Noonan@xenuclear.com NRC

Contact:

Karla Stoedter Tel/email: 651-388-1121 X4219 Performance Indicator:

MS06 - Emergency AC Power Systems Site-Specific FAQ (see Appendix D)? No FAQ to become effective: When approved Question Section NEI 99-02 Guidance needing interpretation (include page and line citation):

Pg F-6 Lines 14-21:

Return to Service: Return to service is the transition from unavailable to available. A train/segment is returned to service when the following conditions are met: clearance tags have been removed, the train/segment has been aligned and prepared for operation, (e.g., valve line-up complete, system filled and vented), further adjustment of associated equipment is not required or expected as a result of the unavailability period, and operators concur that the train/segment is able to perform its expected functions. For standby equipment, automatic functions are aligned or can be promptly restored by an operator consistent with the requirements for crediting operator recovery stated later in this section.

Pg F-27 Lines 14-20:

Emergency power generator failure to load/run: Given that the emergency power generator has successfully started and the output breaker has received a signal to close, a failure of the generator output breaker to close or a failure to run/operate for one hour after breaker closure. The emergency power generator does not have to be fully loaded to count the failure. Failure to load/run also includes failures of the emergency power generator output breaker to re-close following a grid disturbance if the emergency power generator was running paralleled to the grid, provided breaker closure is required by plant design.

Pg F-28 Lines 39-46, Pg F-29 Lines 1-7 Human errors/component trips, inadvertent actuations or unplanned unavailability introduced as part of a test or maintenance activity are not indicative of the reliability of the Page 1 of 4 Recd from NRC 03/31/2015

NEI 99-02 FAQ 14-08 Prairie Island MSPI equipment had the activity not been performed, and should NOT be counted as failures as long as they are immediately revealed and promptly reported to the control room.

This applies to human errors which result in tripping an MSPI component that:

1. Occur while the MSPI train/segment is considered available;

2. Do not result in actual equipment damage;

3. Are immediately revealed through clear and unambiguous indication;

4. Are promptly reported to the control room without delay prior to the performance of corrective actions, and;

5. Are clearly associated with a test or maintenance activity such that the failure sequence would not have occurred and cannot occur if the test or maintenance activity was not being performed.

Pg F-48 Lines 23-26 An EDG is not considered to have failed due to any of the following events:

• spurious operation of a trip that would be bypassed in a loss of offsite power event

• malfunction of equipment that is not required to operate during a loss of offsite power event (e.g., circuitry used to synchronize the EDG with off-site power sources)

Event or circumstances requiring guidance interpretation:

On June 23, 2014, a failed relay associated with a 345kV/161kV transformer (TR10) in the Prairie Island Nuclear Generating Plant (PINGP) switchyard resulted in the load tap changer receiving a signal to move to the lowest tap setting. This created a low voltage condition in the 161kV PINGP bus. As a result Engineered Safety Feature (ESF) Bus 15 was declared inoperable. The other ESF bus, Bus 16, was being energized from a different offsite source and did not experience a low voltage condition. Eventually the 161kV bus voltage dropped to less than 155kV which resulted in an undervoltage condition on Bus 15 and an auto start of Emergency Diesel Generator (EDG) D1 which then powered the loads on Bus 15.

The Control Room operators subsequently paralleled a different offsite source (CT11) with D1 in order to transfer the Bus 15 loads using procedure 1C20.7. This procedure includes a caution against allowing the load on D1 to drop to less than 100 kW to prevent motorizing the generator.

This evolution is a restoration activity that procedurally requires declaring the diesel generator inoperable and unavailable.

D1 subsequently experienced a reverse power condition resulting in a trip and reverse power (86 relay) lockout. The lockout was caused by a reverse-power condition during the supply-source transfer of Bus 15 from D1 to CT11.

The trip of D1 was reported as an MSPI EAC load/run failure in the 2nd quarter of 2014; however, PINGP is seeking to retract the failure.

Page 2 of 4 Recd from NRC 03/31/2015

NEI 99-02 FAQ 14-08 Prairie Island MSPI If licensee and NRC resident/region do not agree on the facts and circumstances, explain:

The NRC Resident agrees with the description of the event. However, it is not clear from NEI 99-02 whether this restoration activity would meet the definition of maintenance, or whether the event constitutes an MSPI failure.

Potentially relevant FAQs: None Response Section Proposed Resolution of FAQ:

The trip and reverse power lockout of D1 does not count as an MSPI failure.

Per the Prairie Island MSPI Basis Document, Revision 15, the MSPI monitored function for the Emergency AC System is To provide emergency AC power to risk-significant equipment during loss of AC power conditions. D1 was fulfilling this function by powering the loads on Bus 15 in response to the undervoltage condition.

The evolution of paralleling an emergency diesel generator to an offsite power source is considered a restoration activity by the site. For D1, this requires declaring the diesel inoperable and unavailable. Operator action is required to parallel to an alternate source, dial in droop on D1, and to open the emergency diesel generator output breaker.

The reverse power logic is a protective feature for when D1 is paralleled to a second power source. Although the reverse power trip and lockout logic are not bypassed during a loss of offsite power event, a valid reverse power condition is not possible when D1 is performing its monitored function.

The lockout condition was not indicative of the reliability of the equipment, and should not be counted as an MSPI failure. No equipment damage occurred. The lockout condition was immediately identified in the control room and corrected prior to D1 being returned to operable status.

If appropriate, provide proposed rewording of guidance for inclusion in next revision:

Pg F-28 beginning on line 39 should be clarified to reflect that events which are caused by human error that are not indicative of the reliability of the equipment should not be counted as failures:

Human errors/component trips, inadvertent actuations or unplanned unavailability which are not indicative of the reliability of the equipment had the activity not been performed, should NOT be counted as failures as long as they are immediately revealed and promptly reported to the control room.

This applies to human errors which result in tripping an MSPI component whether or not the MSPI train/segment is considered available that:

1. Do not result in actual equipment damage;

2. Are immediately revealed through clear and unambiguous indication; Page 3 of 4 Recd from NRC 03/31/2015

NEI 99-02 FAQ 14-08 Prairie Island MSPI

3. Are promptly reported to the control room without delay prior to the performance of corrective actions, and;

4. Are clearly associated with an activity such that the failure sequence would not have occurred and cannot occur if the activity was not being performed.

Unavailability should be counted from the time of the event until the equipment is returned to service, and classified as unplanned unless provisions of Counting Unavailability when Planned and Unplanned Maintenance are Performed in the Same Work Window apply.

Latent failures (failures that existed prior to the maintenance) that are discovered as part of maintenance or test activity are considered failures.

PRA update required to implement this FAQ?

No MSPI Basis Document update required to implement this FAQ?

No NRC Response This FAQ describes an event where during the restoration of offsite power to a safety related bus, a reverse power of an emergency diesel generator inadvertently occurred after paralleling with offsite power. This caused a reverse power lockout of the diesel and a premature trip which the licensee initially reported as an MSPI EAC load/run failure. The licensee has re-evaluated this event and seeks to retract the failure.

Prairie Island MSPI Basis Document, Revision 13, states that [t]he function monitored for the emergency AC power system is the ability of the emergency diesel generators (EDGs) to provide AC power to the class 1E buses upon a loss of off-site power. This function is directly drawn from the guidance of NEI 99-02 Revision 7, Appendix F section 5 system specific guidance for Emergency AC Power Systems (pg. F-49, line 26). As a reverse power lockout during system restoration does not affect the monitored function of the system, it should not count as a failure for MSPI purposes.

The staff has concluded that retracting this failure would be in accordance with the current NEI 99-02 guidance and in keeping with the intent of the MSPI performance indicator.

Page 4 of 4 Recd from NRC 03/31/2015

FAQ 14-10 Indian Point Security Upgrade Plant: _Indian Point___

Date of Event: __NA_____

Submittal Date: __December 11, 2014___

Licensee

Contact:

__Brian Rokes____ Tel/email: _914-254-6674 CRokes@entergy.com NRC

Contact:

__Anthony Dimitriadis Tel/email:(610) 337-6953 Anthony.dimitriadis@nrc.gov________

Performance Indicator: PP01 Site-Specific FAQ (Appendix D)? Yes FAQ requested to become effective: when approved and after completion of the security computer upgrade.

Question Section NEI 99-02 Guidance needing interpretation (include page and line citation): NA Event or circumstances requiring guidance interpretation:

Indian Point Unit 2 and 3 each have their own security computer, independent of the other unit resulting in a different security indicator for each unit. The station currently reports two separate and distinct security performance indicators, one for Unit 2 and one for Unit 3 In early 2015, a new security computer system will be made operational, which will result in a single site wide system. This site-specific FAQ requests guidance on how to best handle that transition when it occurs.

If licensee and NRC resident/region do not agree on the facts and circumstances explain:

NA Potentially relevant existing FAQ numbers: NA Response Section Proposed Resolution of FAQ The site proposes to maintain two separate security indicators, one for Unit 2 and one for Unit 3.

Future Data Once the site security system is integrated, the security performance indicator for both units will be annotated with a licensee comment indicating that the security system has been combined into a site indicator. Entergy will work with INPO to revise the normalization factors to reflect the new combined system. For future data reporting, the performance indicators, although two separate files, will contain identical information, each reflecting current site performance.

Past Data (prior to site security computer integration)

For historical data presentation, Entergy proposes to maintain two separate indicators (one for Unit 2 and one for Unit 3). The indicator for the Units will reflect the performance of the unit specific security system, up to the point where the system was integrated, at which point the performance line will shift to reflect the new station value. A licensee comment will be Page 1 of 2 Recd from NRC 03/31/2015

FAQ 14-10 Indian Point Security Upgrade included on the indicator stating that data included before the integration date reflects a unit specific value, versus a site specific value.

If appropriate, provide proposed rewording of guidance for inclusion in next revision. None PRA update required to implement this FAQ: No MSPI Basis document update required to implement this FAQ? No.

NRC Response This FAQ discusses the treatment of the Protected Area Security Equipment Performance Index performance indicator (PI) for Indian Points transition from two independent security systems to a single integrated system. The NRC staff agrees with the licensees proposal to maintain two separate indicators for Indian Point Unit 2 and 3 with the understanding that once integrated, the reported data will be identical for the two units. The licensee will report the PI data with revised site normalization factors for each unit once the system is installed with the previous quarters values utilizing the individual unit normalization factors. It is understood that once the new system has operated for four quarters, the PI value independently reported for each unit will be identical.

Page 2 of 2 Recd from NRC 03/31/2015

FAQ 15-01 Perry Scram, October 20, 2014 Plant: Perry Date of Event: October 20, 2014 Submittal Date:

Licensee

Contact:

David Lockwood Tel/email: (440)280-5200/ dhlockwood@firstenergycorp.com NRC

Contact:

Mark Marshfield Tel/email: (440) 280-5822/mark.marshfield@nrc.gov Performance Indicator: IE04, Unplanned Scrams With Complications Site-Specific FAQ (see Appendix D) (__) Yes or (X) No FAQ requested to become effective (_X_) when approved or (other date):

Question Section NEI 99-02 Guidance needing interpretation (include page and line citation):

BWR flowchart question: Did an RPS actuation fail to indicate/establish a shutdown rod pattern for a cold clean core. Page 25, lines 3 through 22.

Did an RPS actuation fail to indicate / establish a shutdown rod pattern for a cold clean core?

Withdrawn control rods are required to be inserted to ensure the reactor will remain shutdown under all conditions without boron to ensure the reactor will have the required shutdown margin in a cold, xenon-free state.

Any initial evaluation that calls into question the shutdown condition of the reactor requires this question to be answered Yes. The required entry into the Anticipated Transient without Scram (ATWS) leg of the EOP or required use of Alternate Rod Insertion (ARI) requires this question to be answered Yes. Failure of the rod position indication in conjunction with the loss of full-in-lights on enough rods to question the cold clean core shutdown status would require this question to be answered Yes.

The basis of this step is to determine if additional actions are required by the operators to ensure the plant remains shutdown as a result of the failure of any withdrawn rods to insert (or indicate inserted).

Additional actions, such as boron injection, or other actions to insert control rods to maintain shutdown, pose a complication beyond a normal scram response. This question must be evaluated using the criteria contained in the plant EOP used to verify the insertion of withdrawn control rods.

Appendix H, USwC Basis Document, Section H3.1, page H-17, lines 36 through 44, and page H-18, lines 1 through 12.

The purpose of this question is to verify that the reactor actually tripped and had sufficient indication for operations to verify the trip. As long as a plant uses the EOP questions to verify that the reactor tripped without entering the level/pressure control leg of the EOPs, the response to this question should be No.

Page 1 of 4 Revised 04/15/2015

FAQ 15-01 Perry Scram, October 20, 2014 The generic BWROG EPG/SAG Revision 2 Appendix B statement is offered as an example:

Any control rod that cannot be determined to be inserted to or beyond position [02] (Maximum Subcritical Banked Withdrawal Position)] and it has not been determined that the reactor will remain shutdown under all conditions without boron, enter Level/Power Control.

For example:

Are all control rods inserted to or beyond position 02 (if no then this is a yes for this PI)? Will the reactor remain subcritical under all conditions without boron (if no then this is a Yes for this PI)?

For example:

All rods not fully inserted; and, the reactor will not remain shutdown under all conditions without boron then enter level/pressure control (if yes then this is a Yes for this PI).

Event or circumstances requiring guidance interpretation:

While operating at 100% power, an unplanned automatic reactor scram occurred due to Reactor Pressure Vessel (RPV) Level 3 (178) activation of the Reactor Protection System. An electrical transient occurred impacting Feedwater Level Control. The reactor mode switch was placed in Shutdown in accordance with plant operating procedures.

Prior to the scram, Feedwater was aligned with the Reactor Feed Pump Turbines (RFPT) A & B in automatic Digital Feedwater Three Element (3E) control. The Motor Feedwater Pump (MFP) was in Standby. The RPV Level 3 signal was the result of RFPTs A/B no longer providing adequate feedwater to the RPV due to an electrical transient. The RPV water level continued to lower to Level 2 which resulted in a valid initiation of both Reactor Core Isolation Cooling (RCIC) and High Pressure Core Spray (HPCS) and associated support systems. The RCIC initiation provided a Main Turbine trip signal as expected. The Motor Feed Pump, HPCS, and RCIC all tripped when RPV Level 8 was achieved. EOP-1, RPV Control, was entered by the Unit Supervisor due to RPV Level 2 (130).

When Level 2 was reached ARI was automatically initiated by the Redundant Reactivity Control System as designed. This actuation is based on Level 2 only and occurs regardless of control rod position.

Upon the scram signal, the Full Core Display was indicating both Red and Green LED Lights (Rods Out and In, respectively) where the expected response was all Green LED Lights. The Rod Action Control System (RACS) was utilized to verify that the All Rods In LED was illuminated, and this was verified by multiple operators. The Rod Control Information System was reset utilizing the plant procedure and indication returned to normal, all Green. The erroneous indication was caused by the electrical transient that occurred from the DB1A inverter. Actuation of alternate reactivity controls by the operators was not required.

The RACS is located in a control room back panel outside of the at the controls area of the control room. RACS is a subsystem of Rod Control and Information System. There is two divisions of RACS.

The RACS All Rods In LED will actuate when the full-in limit switch on the position indicating probe (PIP) for all control rods has actuated. There are two limit switches per PIP each providing input to a Page 2 of 4 Revised 04/15/2015

FAQ 15-01 Perry Scram, October 20, 2014 separate division. Operators have received training on using the RACS All Rods In LED to verify a shutdown rod pattern, however this use is not proceduralized.

Perry has determined that this event is not an Unplanned Scram with Complications based on the guidance on page 25 lines 17 through 22, which state:

The basis of this step is to determine if additional actions are required by the operators to ensure the plant remains shutdown as a result of the failure of any withdrawn rods to insert (or indicate inserted).

Additional actions, such as boron injection, or other actions to insert control rods to maintain shutdown, pose a complication beyond a normal scram response. This question must be evaluated using the criteria contained in the plant EOP used to verify the insertion of withdrawn control rods.

The initial evaluation verifying the shutdown condition of the reactor utilizing the RACS indication when the Full Core Display had conflicting information was correct. The operators were able to determine that all rods were inserted and the reactor would remain shutdown under all conditions without boron and entry into the Level/Power Control leg of the EOPs was not required.

Appendix H section H3.1 supports this determination at lines 39-42 on page H-17 which states; The purpose of this question is to verify that the reactor actually tripped and had sufficient indication for operations to verify the trip. As long as a plant uses the EOP questions to verify that the reactor tripped without entering the level/pressure control leg of the EOPs, the response to this question should be No.

Appendix H, Section H4.1, BWR Case Study 1, and Section H4.2, BWR Case Study 2, both indicate that this question is focused on the actual condition of the reactor and whether additional actions are taken to ensure the reactor would remain shutdown under cold clean conditions. In both case studies this question can be answered No as Alternate Rod Insertion was not indicated or required.

BWR Case Study 1 includes, as an example of an acceptable no answer, the following explanation:

While all rods did not fully insert, reactor engineering, using an approved procedure, ran a computer calculation that determined the reactor would remain shutdown under cold clean conditions. In the Perry case, all rods did insert, and observing the All Rods In LED is less complicated than running a computer calculation In the Perry event of October 20, 2014, operator action to initiate ARI was not indicated or required, entry into the Level/Power Control leg of the EOPs was not required and sufficient indication (RACS) was available for the operators to determine that all rods were inserted.

If licensee and NRC resident/region do not agree on the facts and circumstances, explain:

The Resident Inspector Office has contacted NRR and believes that utilizing a back-panel indication (i.e.

RACS, which happens to be located in the control room at Perry but requires entry into a panel to validate indications) is an additional action not required in the immediate actions for the at-the-controls operator (ATC). As such, the requirement for additional personnel actions to validate a clean cold core, utilizing a single status indicating light on only one division of RACS as in this case, does not equate to completing the immediate action step on the At-the-Controls hard card to indicate a cold clean core. On page 25 of Page 3 of 4 Revised 04/15/2015

FAQ 15-01 Perry Scram, October 20, 2014 NEI 99-02, lines 13-15, the flowchart guidance states Failure of the rod position indication in conjunction with the loss of full-in-lights on enough rods to question the cold clean core shutdown status would require this question to be answered Yes. During the October 20, 2014 scram, the ATC was unable to make an initial determination that he had a cold clean core from the indications available to him and requested an additional operator to go back-panel to evaluate the indication in RACS, this demonstrated that the initial evaluation of a cold clean core was indeed indeterminate. With regard to the case studies, ARI was actuated at Perry during this scram because it is automatic on Level 2 which was reached during this scram so by definition it was required. Further, if the control room was at minimum manning, with no one immediately available to go back-panel, the ATC on watch in the control room would take the immediate action to actuate ARI and RPS as required by the hard card and the answer would again be Yes to block 1 of the flowchart for complicated scrams.

Potentially relevant FAQs: None identified.

Response Section Proposed Resolution of FAQ:

Revise the response to the BWR flowchart question: Did an RPS actuation fail to indicate/establish a shutdown rod pattern for a cold clean core. Page 25, lines 3 through 22 to align with Appendix H, USwC Basis Document, Section H3.1, page H-17, lines 39 through 44, and page 18, lines 1 through 12.

Specifically, clarify that a scram with complications results only from entry into the Level/Power Control leg of the EOPs If appropriate, provide proposed rewording of guidance for inclusion in next revision:

We propose the following change to page 25, lines 6-7:

From:

6 Any initial evaluation that calls into question the shutdown condition of the reactor requires this 7 question to be answered Yes.

To:

Any initial evaluation that calls into question the shutdown condition of the reactor and results in additional operator actions intended to place the reactor in a shutdown condition requires this question to be answered Yes regardless of any subsequent determination that the reactor was in a shutdown condition prior to those actions. Utilizing alternative indication to clarify the status of the control rods is not considered to be an additional operator action intended to place the reactor in a shutdown condition and would not count in this indicator.

On page 25 at line 10 delete the sentence which reads Any initial evaluation that calls into question the shutdown condition of the reactor requires this question to be answered Yes.

On page 25 at line 17 revise this sentence to read The basis of this step is to determine if additional actions are required by the operators to ensure the plant remains shutdown as a result of the failure of any withdrawn rods to insert.

PRA update required to implement this FAQ? No MSPI Basis Document update required to implement this FAQ? No Page 4 of 4 Revised 04/15/2015