IR 05000528/2018003

NRC Integrated Inspection Report 05000528/2018003, 05000529/2018003, and 05000530/2018003

ML18318A355
Person / Time
Site:	Palo Verde
Issue date:	11/14/2018
From:	O'Keefe N NRC/RGN-IV/DRP/RPB-D
To:	Bement R Arizona Public Service Co
References
IR 2018003
Download: ML18318A355 (25)

Text

ber 14, 2018

SUBJECT:

PALO VERDE NUCLEAR GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000528/2018003, 05000529/2018003, AND 05000530/2018003

Dear Mr. Bement:

On September 30, 2018, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Palo Verde Nuclear Generating Station, Units 1, 2, and 3. On October 9, 2018, the NRC inspectors discussed the results of this inspection with Mr. Jack Cadogan and other members of your staff. The results of this inspection are documented in the enclosed report.

NRC inspectors documented one finding of very low safety significance (Green) in this report.

This finding did not involve a violation of NRC requirements.

If you disagree with the finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region IV; and the NRC resident inspector at the Palo Verde Nuclear Generating Station. This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely,

/RA Mark Haire Acting for/

Neil OKeefe, Branch Chief Project Branch D Division of Reactor Projects Docket Nos. 50-528, 50-529, 50-530 License Nos. NPF-41, NPF-51, NPF-74 Enclosures:

Inspection Report 05000528/2018003, 05000529/2018003, 05000530/2018003 w/Attachments:

1. Supplemental Information 2. Detailed Risk Evaluation

U.S. NUCLEAR REGULATORY COMMISSION

Inspection Report

Docket Numbers: 05000528, 05000529, 05000530 License Numbers: NPF-41, NPF-51, NPF-74 Report Numbers: 05000528/2018003, 05000529/2018003, and 05000530/2018003 Enterprise Identifier: I-2018-003-0013 Licensee: Arizona Public Service Company Facility: Palo Verde Nuclear Generating Station, Units 1, 2, and 3 Location: 5801 South Wintersburg Road, Tonopah, AZ 85354 Inspection Dates: July 1, 2018 to September 30, 2018 Inspectors: C. Peabody, Senior Resident Inspector D. Reinert, PhD, Resident Inspector D. You, Resident Inspector J. Dixon, Senior Project Engineer I. Anchondo, Reactor Inspector R. Bywater, Project Engineer S. Hedger, Emergency Preparedness Inspector Approved By: Neil OKeefe, Chief Project Branch D Division of Reactor Projects Enclosure

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting baseline inspections at Palo Verde Nuclear Generating Station,

Units 1, 2, and 3 in accordance with the Reactor Oversight Process. The Reactor Oversight Process is the NRCs program for overseeing the safe operation of commercial nuclear power reactors. Refer to https://www.nrc.gov/reactors/operating/oversight.html for more information.

NRC-identified and self-revealed findings, violations, and additional items are summarized in the table below. Licensee-identified non-cited violations are documented in the Inspection Results at the end of this report.

List of Findings and Violations Failure to Maintain Command and Control During a Feedwater Control Valve Malfunction Cornerstone Significance Cross-cutting Aspect Inspection Procedure Initiating Green None 71153 - Follow Up Events FIN 05000530/2018003-01 of Events and NOEDs While reviewing the licensee response to a Unit 3 feedwater pump trip, reactor cutback, reactor trip, and main steam isolation system actuation on June 27, 2018, the inspectors identified that the licensee did not meet the command and control standards in station procedure 40DP-9OP02 Conduct of Operations, Revision 72. Specifically, senior reactor operators in the control room did not effectively coordinate manual main feedwater output adjustments in the control room or operator actions in the field in response to an apparent valve failure with the activities of non-licensed operators locally evaluating the equipment condition in the field. The uncoordinated actions resulted in a significant plant transient.

Additional Tracking Items Type Issue number Title Inspection Status Procedure LER 05000530/2018-001-00 Unit 3 Reactor Trip on Low 71153 Closed Steam Generator Water Level

PLANT STATUS

Unit 1 entered the inspection period at full power. Power was reduced to 40 percent on July 2-6, 2018, to address leakage in the main condenser. Power was reduced again to 2 percent and the turbine generator disconnected to affect repairs to the main generator connection in the switchyard on July 10-12, 2018. Unit 1 remained at or near full power for the remainder of the inspection period.

Unit 2 entered the inspection period at full power. Power was reduced to 80 percent to repair a feedwater heater on September 6-10, 2018. On September 22, 2018, Unit 2 began coasting down towards a planned refueling outage and ended the inspection period at 92 percent power.

Unit 3 entered the inspection period shutdown for an unplanned outage to repair the main feedwater system. Unit 3 restarted on July 1, 2018, and reached full power on July 4, 2018.

Unit 3 operated at or near full power for the remainder of the inspection period.

INSPECTION SCOPES

Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with their attached revision histories are located on the public website at http://www.nrc.gov/

reading-rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared complete when the IP requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection Program - Operations Phase. The inspectors performed plant status activities described in IMC 2515 Appendix D, Plant Status and conducted routine reviews using IP 71152, Problem Identification and Resolution. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel to assess licensee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.

71111.01 - Adverse Weather Protection

External Flooding

The inspectors evaluated readiness to cope with external flooding on July 27, 2018.

71111.04 - Equipment Alignment

Partial Walkdown

The inspectors evaluated system configurations during partial walkdowns of the following systems/trains:

(1) Unit 1 train B motor-driven auxiliary feedwater pump, on August 29, 2018

(2) Unit 1 train A essential spray pond system, on September 24, 2018

(3) Unit 1 train A essential cooling water system, on September 24, 2018

(4) Unit 3 offsite power to Class 1E distribution, on September 28, 2018

71111.05AQ - Fire Protection Annual/Quarterly

Quarterly Inspection

The inspectors evaluated fire protection program implementation in the following selected areas:

(1) Unit 3 lower cable spreading room, Fire Zone 14, on July 19, 2018

(2) Unit 1 motor driven auxiliary feedwater pump room, Fire Zone 73, on August 23, 2018

(3) Unit 3 main control room, Fire Zone 17, on September 11, 2018

(4) Unit 1 battery rooms, Fire Zones 8A, 8B, 9A, and 9B, on September 13, 2018

(5) Unit 1 essential chiller A room, Fire Zone 1, on September 24, 2018

(6) Unit 1 train A essential cooling water equipment rooms, Fire Zones 34A, 43, and 48, on

September 24, 2018 Annual Inspection (1 Sample)

The inspectors evaluated fire brigade performance on July 27, 2018.

71111.06 - Flood Protection Measures

Internal Flooding

The inspectors evaluated internal flooding mitigation protections in:

(1) Unit 1 control element drive mechanism room, on July 24, 2018

(2) Unit 2 control building elevation 74 feet, on September 13, 2018

Cables (2 Samples)

The inspectors evaluated cable submergence protection in:

(1) Cable Vault 3MHAEZV08NKFM07, on September 24, 2018

(2) Cable Vault 3MH3EZV08AKEM10, on September 24, 2018

71111.11 - Licensed Operator Requalification Program and Licensed Operator Performance

Operator Requalification

The inspectors observed and evaluated parts of the annual requalification simulator scenario examination portion performed by a Unit 2 and Unit 3 operating crew on September 11-12, 2018.

The inspectors assessed the performance of the operators and the evaluators critique of their performance.

Operator Performance (1 Sample)

The inspectors observed and evaluated licensed operator performance in Unit 3 during power ascension activities on July 1, 2018.

71111.12 - Maintenance Effectiveness

Routine Maintenance Effectiveness

The inspectors evaluated the effectiveness of routine maintenance activities associated with the following equipment and/or safety significant functions:

(1) Unit 1 charging pump relief valve seat leakage, on July 25, 2018

(2) Units 1, 2, and 3 main turbine control and stop valves overall maintenance effectiveness, on August 6, 2018

(3) Unit 2 control element drive mechanism control system performance criteria evaluation and expert panel review, on August 9, 2018

71111.13 - Maintenance Risk Assessments and Emergent Work Control

===

The inspectors evaluated the risk assessments for the following planned and emergent work activities:

(1) Unit 1 increased risk during planned shutdown cooling isolation valve maintenance, on July 3, 2018

(2) Unit 2 increased risk during planned maintenance on the high pressure safety injection pump A motor concurrent with essential chilled water pump A surveillance testing, on July 12, 2018

(3) Unit 1 diesel super outage B, starting on September 24, 2018

71111.15 - Operability Determinations and Functionality Assessments

The inspectors evaluated the following operability determinations and functionality assessments:

(1) Unit 3 excessive packing leakage from spray pond pump A, on July 23, 2018

(2) Unit 3 steam generator two blowdown sample isolation valves 222 and 223 failure to close, on July 26, 2018

(3) Unit 1 diesel generator A lube oil heater temperature controller malfunction, on July 31, 2018

(4) Unit 3 spent fuel transfer tube housing bellows boric acid leak, on August 2, 2018

(5) Unit 3 RU-1 containment radiation monitor filter with increased iron results, on September 5, 2018

71111.19 - Post Maintenance Testing

The inspectors evaluated the following post maintenance tests:

(1) 40ST-9DG02, Unit 3 diesel generator B functional test after work to replace the control air pressure valve, on August 16, 2018

(2) 32ST-9ZZ34, Unit 1 Class 1E battery charger AC 18 month surveillance test after performing preventative maintenance on the AC battery charger, on August 30, 2018

(3) 73ST-9SI11, Unit 2 low pressure safety injection pump A minimum flow surveillance test after replacement of the pump supply breaker, on September 6, 2018

(4) 40OP-9CH01, Unit 1 charging pump E seal lube pump post maintenance test following corrective maintenance, on September 11, 20118

(5) 40OP-9EC01, Unit 1 essential chiller B functional test following planned maintenance during the super outage window, on September 25, 2018

(6) 40OP-9DG02, Unit 1 diesel generator B functional test following planned maintenance during the super outage window

71111.22 - Surveillance Testing

The inspectors evaluated the following surveillance tests:

Routine===

(1) 74ST-9RC02, Unit 2 reactor coolant system specific activity surveillance test, on September 12, 2018

(2) 73ST-9DG07, 73ST-9DG08, and 40ST-9SF01, Plant review board for changing surveillance frequencies for the diesel generator 24-hour load test/hot restart and control element drive assembly operability checks, on September 13, 2018

(3) 40ST-9DG02, Unit 1 diesel generator B test following work on the over-speed mechanism, on September 28, 2018

In-service (3 Samples)

(1) 73ST-9SP01, Unit 3 essential spray pond pump A flow test, on July 3, 2018

(2) 73ST-9EC01, Unit 2 essential chilled water pump A in-service test, on July 12, 2018

(3) 73ST-9SI11, Unit 3 low pressure safety injection pump A miniflow in-service test, on August 9, 2018

71114.04 - Emergency Action Level and Emergency Plan Changes

===

The inspectors evaluated Palo Verde Nuclear Generating Station Emergency Plan, Revision 61, submitted on June 12, 2018. Associated 10 CFR 50.54(q) emergency plan change process documentation was reviewed as well. The evaluation was performed in-office from July 12-September 18, 2018. This evaluation does not constitute NRC approval.

71114.06 - Drill Evaluation

Emergency Planning Drill===

The inspectors evaluated an emergency planning drill on July 24, 2018.

The inspectors evaluated an emergency planning drill on August 14,

OTHER ACTIVITIES - BASELINE

71151 - Performance Indicator Verification

The inspectors verified licensee performance indicators submittals listed below:

(1) BI01: Reactor Coolant System (RCS) Specific Activity Sample (07/01/2017-06/30/2018)

(2) BI02: RCS Leak Rate Sample (07/01/2017-06/30/2018)

71152 - Problem Identification and Resolution

Annual Follow-up of Selected Issues

The inspectors reviewed the licensees implementation of its corrective action program related to the following issues:

(1) Diesel generator air dryer condensation drain valves failing open

(2) Class 1E 4kV electrical distribution buses continued operation above nominal voltage

71153 - Follow-up of Events and Notices of Enforcement Discretion Licensee Event Reports

The inspectors evaluated the following licensee event reports which can be accessed at https://lersearch.inl.gov/LERSearchCriteria.aspx:

(1) Licensee Event Report 05000530/2018-001, reactor trip on low steam generator level and main steam isolation signal on high steam generator level, on September 17,

INSPECTION RESULTS

Failure to Maintain Command and Control During a Feedwater Control Valve Malfunction Cornerstone Significance Cross-cutting Inspection Aspect Procedure Initiating Green None 71153 - Follow Up Events FIN 05000530/2018003-01 of Events and NOEDs

Introduction:

While reviewing the licensee response to a Unit 3 feedwater pump trip, reactor cutback, reactor trip, and main steam isolation system actuation on June 27, 2018, the inspectors identified that the licensee did not meet the command and control standards outlined in station Procedure 40DP-9OP02 Conduct of Operations, Revision 72.

Specifically, senior reactor operators in the control room did not effectively coordinate manual main feedwater output adjustments in the control room or operator actions in the field in response to an apparent valve failure with the activities of non-licensed operators locally evaluating the equipment condition in the field. These uncoordinated actions resulted in a significant plant transient.

Description:

On June 27, 2018, Unit 3 was operating at 100 percent power. At 5:54 p.m., the steam generator 1 economizer control valve stopped responding to routine incremental demand changes normally imposed by the digital feedwater control system (DFWCS)operating in automatic mode. The DFWCS managed feedwater pump speed and steam generator 2 economizer control valve position to maintain the secondary cooling system at or near steady state for approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />; however, steam generator water level eventually began to rise slowly. At 10:57 p.m., an annunciator alarm alerted control room operators to a DFWCS trouble condition. The operators determined that the cause of the alarm was a 10 percent mismatch between economizer valve position and controller demand.

At 11:02 p.m., the control room supervisor directed a licensed operator to change the DFWCS controller from automatic to manual control with demand and output matched at 43 percent. The licensed operator at the controls dispatched the turbine building upper levels watch stander to investigate the condition of the valve locally via radio, and effectively communicated the situation to the auxiliary operator. The same licensed operator telephoned the auxiliary operator break room minutes later and dispatched all remaining auxiliary operators to the field, but did not provide specific actions or status of the situation, only that the assigned operator already dispatched would need all the help he could get.

From 11:04-11:07 p.m., the operator at the controls attempted unsuccessfully to reduce feedwater flow. Despite reducing controller output manually to 30 percent, the economizer valve did not move, so the crew was unable to establish positive control of the economizer valve position.

Meanwhile, the additional auxiliary operators dispatched to the field arrived and one observed that the economizer trip valve, a support valve that controls air to move the main economizer valve, was leaking air out of its relief port. When the trip valve is tripped, it stops operating air and locks the valve in its current position. This operator was not aware that additional controller output changes were made; however, he recalled recent workarounds from the radwaste operator watch standing position where small air leaks were sometimes blocked to reset air operated valves. The operator reported the air leak to the control room and, without waiting for direction, blocked the relief port with a gloved finger at 11:10 p.m. The trip valve in question had a punctured diaphragm and when the valve port was blocked, the trip valve reset. It then ported air to the economizer valve and the economizer valve rapidly closed to the specified controller output position of 30 percent, resulting in feedwater flow much less than was needed for the existing steam flow. The abrupt feed flow reduction caused one of the main feedwater pumps to trip on high discharge pressure, causing the reactor power cutback system to immediately drop designated control rods and reduce steam demand to 54 percent.

This transient startled the auxiliary operator into removing his finger from the vent port, causing the trip valve to again block air to the economizer valve at 29 percent open. This was still an underfeed condition for 54 percent steam flow, causing steam generator level to drop rapidly. Seventy two seconds later at 11:12 p.m., the reactor tripped on low steam generator level and the operators entered the standard post trip review actions. However, since the economizer valve was locked in position by the trip valve, it did not respond to the reactor trip system signal to automatically close in response to the reduced steam demand. Instead, the valve was now too far open for the significantly reduced steam flow and began to overfeed the steam generator. The reactor operator noted the rising water level while performing the standard post trip actions and reported the condition to the control room supervisor; however, level reached the main steam line isolation signal actuation set point at 11:16 p.m. as the control room supervisor was confirming the report and directing the reactor operator to close the feedwater isolation valve. The main steam line isolation signal isolated the failed economizer when it closed all main steam isolation valves and main feedwater isolation valves. At this point the steam was isolated from the condenser and decay heat was released to the atmosphere through the atmospheric dump valves. Operators were subsequently able to stabilize the plant and restore feed to the steam generators via the safety related motor driven auxiliary feedwater pump.

The licensee determined that the cause of the economizer trip valve diaphragm failure was most likely due to a manufacturing defect. The valve operator had been replaced during the refueling outage two months prior and was considered an infant mortality condition. This part is not safety-related and the diaphragm cannot be inspected without risking damage to the diaphragm.

As part of the event review, the inspectors reviewed the requirements of the licensees Conduct of Operations Procedure 40DP-9OP02, Revision 72. The inspectors concluded that the requirements of Section 4.2, Command and Control, were not met during the event.

The standard set by the procedure in step 4.2.1.1 is that Crew Supervision uses available resources thoughtfully to ensure operators take actions according to priority to mitigate an event. Multiple related expectations in the Conduct of Operations procedure were also unmet, at least in part, during the economizer valve troubleshooting:

4.2.2.1b Ensure crew member understand activities, priorities, and task risk level.

4.2.2.1e Ensure conditions are conducive to individuals maintaining attention to detail, especially when operational risk is high.

4.2.2.2g Perform briefings and updates as necessary to keep the crew informed of changes in scheduled activities or plant conditions to ensure crew alignment.

4.2.2.2m Confirms diagnosis and plant status prior to taking action and re-evaluates action if expected results are not achieved.

Specifically, the inspectors concluded that the coordination both of operators in the control room adjusting the DFWCS in manual and of the auxiliary operators responding to the field to assess the condition of the apparent failure of steam generator number one economizer valve were not coordinated in response to slowly rising steam generator water level condition.

Specifically, licensed control room operators did not effectively diagnose the loss of positive control for the economizer valve position. When the valve was not responsive, the licensed operators did not stop and attempt to determine a proper course of action. Instead the control room operators continued to increase the demand position mismatch with subsequent adjustments. Furthermore, auxiliary operators were dispatched without specific direction; the auxiliary operators were not informed of actions being taken in the control room. As a result the auxiliary operator attempting to reset the trip valve in the field was not aware of the demand mismatch and its implications when deciding his course of action. The combined result of these actions was to quickly turn a slowly rising steam generator water level transient into a significant plant power reduction and eventual plant trip.

The inspectors conducted interviews with the operations crew members involved and found that the briefing of the additional operators that occurred over the telephone was minimal; however, the auxiliary operators and the reactor operators indicated that such a practice was not uncommon when responding to emergent plant conditions. Specifically, when urgent directions for all available hands to respond are given, a less detailed briefing is to be expected. The inspectors determined that the manner in which the second group of operators was dispatched created a sense of urgency in the field that did not exist in the control room. Interviews with control room operators indicated that the steam generator level was rising very slowly and they were methodically considering options.

The interviews with the auxiliary operators also revealed that the action to cover the vent port by the auxiliary operator was based in part on a known work around technique often utilized on less safety-significant air operated valves in the radwaste building. Small air leaks are sometimes plugged temporarily by hand to get an air operated valve to cycle properly. While only one of the four operators dispatched acted upon this experience, all of the operators were familiar with the practice and acknowledged that it was likely a bad practice.

The inspectors also concluded a knowledge gap existed at all levels with regards to the Site-Wide Status Control Program Requirements found in station Procedure 02DP-9OP01, Revision 4. From the interviews, the inspectors found that while all operators could state the requirement to operate plant equipment only with explicit direction from control room operators, the same operators acknowledged that this expectation was not always followed.

During the interviews, none of the operators stated the procedural requirements that list the acceptable methods for auxiliary operators to manipulate equipment in the field, 1) while hanging or removing a clearance approved by the control room, 2) while performing a station procedure assigned to them by the control room, or 3) at the explicit radio or telephone direction of the control room operators. This led the inspectors to review training materials on the Site-Wide Status Control Program and the inspectors found that the training did not require operators to demonstrate a thorough knowledge of the subject. Specifically, the operators only needed to recite the correct procedure number, 02DP-9OP01, to pass the examination. They would not be required to specify the general requirements of the procedure pertaining to their position, whereas other areas of the examination, such as log keeping, required a more detailed response that included not only the procedure number, but also the general requirements of the procedure.

Corrective Action(s): Perform Apparent Cause Evaluation in response to NRC identified finding to determine causes and actions required.

Corrective Action Reference(s): CR 18-15727

Performance Assessment:

Performance Deficiency: Senior reactor operators failed to effectively direct licensed operators in the control room and auxiliary operators in the field to respond to rising steam generator water level. Specifically, the actions of auxiliary operators dispatched to assess the local condition of the steam generator economizer valve were not coordinated with licensed operator activities in the control room to take manual control of the economizer valve controller. The auxiliary operators were not supervised or given specific directions, while the reactor operators in the control room were allowed to make multiple reductions in the controller output signal despite recognizing that the valve was not responding to those output changes. As a result, when one of the operators attempted to reset an air operated valve without prior direction, the slowly changing plant conditions became a significant plant transient.

Screening: The inspectors determined the performance deficiency was more than minor because it adversely affected the human performance attribute of the initiating events cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the error was a direct cause of a main feedwater pump trip, reactor power cutback, reactor trip, and main steam isolation signal actuation.

Significance: The inspectors assessed the significance of the finding using Manual Chapter 0609, Appendix A, Significance Determination Process for Findings At Power, Exhibit 1, Initiating Events Screening Questions, Section B, Transient Initiators. The finding required a regional senior reactor analyst to perform a detailed risk evaluation because the finding caused a reactor trip and a loss of mitigation equipment when the main feedwater and the main condenser were isolated by the main steam isolation signal. The detailed risk evaluation, provided as Attachment 2 to this report, concluded that the finding was of very low safety significance (Green).

Cross-cutting Aspect: The inspectors determined that the causes of the finding did not reflect any of the baseline aspects within the cross cutting areas.

Enforcement:

This finding did not involve a violation of regulatory requirements.

EXIT MEETINGS AND DEBRIEFS

On September 18, 2018, the inspectors communicated the emergency action level and emergency plan changes inspection results telephonically to Ms. C. Shields, Manager, Emergency Preparedness, and other members of the licensee staff. The inspectors verified no proprietary information was retained or documented in this report.

On October 9, 2018, the inspectors presented the quarterly resident inspector inspection results to Mr. Jack Cadogan, Senior Vice President, Site Operations, and other members of the licensee staff. The inspectors verified no proprietary information was retained or documented in this report.

DOCUMENTS REVIEWED

71111.01 - Adverse Weather Protection

Procedures

Number Title Revision

01DP-0AP12 Condition Reporting Process 29

Condition Reports (CRs)

14-0092 13-01216 18-05286

Work Orders (WOs)

4568928 4495600 3634768

Miscellaneous

Number Title Revision

13-A-ZZD-002 Typ. Penetration Seal Details: Conduits 29

PVNGS Updated FSAR 18

PVNGS Design Basis Manual 011

71111.04 - Equipment Alignment

Procedures

Number Title Revision

40ST-9AF08 Auxiliary Feedwater Pump AFB-P01 Monthly Valve Alignment 6

40OP-9SP01 Essential Spray Pond (SP) Train A 57

Condition Reports (CRs)

2898475

Miscellaneous

Number Title Revision/Date

13-MS-A70 Separation/hazards evaluation for the Palo Verde motor January 9, 1997

driven AFW Train B pump room

CRAI 2833456 Condition Report Action Item Resolution

01-M-EWP-001 P & I Diagram Essential Cooling Water System 32

Miscellaneous

Number Title Revision/Date

01-P-EWF-201 Auxiliary Bldg. Isometric Essential Cooling Water System 4

ECWS Pump Loop - Train A

03-E-MAA-002 Unit Single Line Diagram 5

03-E-PBA-002 Single Line Diagram 4.16 KV Class 1E Power System 14

Switchgear 3E-PBB-S04

03-E-PBA-001 Single Line Diagram 4.16 KV Class 1E Power System 14

Switchgear 3E-PBA-S03

ANSI/ANS-51.10-1979 1979

PVNGS Updated FSAR 17

71111.05 - Fire Protection

Calculations

Number Title Revision

13-MC-FP-0803 Combustible Loads - Control Building 16

Condition Reports (CRs)

18-11447

Work Orders (WOs)

29881

Miscellaneous

Number Title Revision

UFSAR Fire Hazards Analysis (Section 9B) 17, 18, 19

VTM-A430-00008 Vendor Technical Manual for Ansul Fire protection Equipment 5

PVNGS Pre-Fire Strategies Manual 26

71111.06 - Flood Protection Measures

Calculations

Number Title Revision

13-MC-ZA-0809 As Built Auxiliary Building Flooding Calculation 7

13-MC-ZA-0810 Flooding Between Adjacent Safety Related Structures 8

13-MC-ZZ-0642 Moderate Energy Crack Evaluation 3

Calculations

Number Title Revision

13-MC-ZJ-0200 As Built Control Building Flooding Calculation 8

Condition Reports (CRs)

18-09076 18-02946

Miscellaneous

Number Title Revision

13-E-ZVU-008 Underground Electrical Duct Layout Plot Plan 43

71111.11 - Licensed Operator Requalification Program and Licensed Operator Performance

Procedures

Number Title Revision

40OP-9ZZ04 Plant Startup Mode 2 to Mode 1 77

Condition Reports (CRs)

18-10686

Work Orders (WOs)

4906612 4900690

71111.12 - Maintenance Effectiveness

Procedures

Number Title Revision

40OP-9MT02 Main Turbine 86

40EP-9EO01 Standard Post Trip Actions 22

Condition Reports (CRs)

16-12272 18-11924 18-12135 18-12587 18-08748

18-11646

Work Orders (WOs)

18-11553-004 16-1272-002 4513908

Miscellaneous

Title

Palo Verde Maintenance Rule Electronic Database (MRule)

71111.13 - Maintenance Risk Assessments and Emergent Work Control

Procedures

Number Title Revision

40DP-9AP21 Protected Equipment 7

2DP-0RS01 Online Integrated Risk 7

Work Orders (WOs)

4877570 4878332 4878560 4881251 4880778

4881262

Miscellaneous

Title Date

Schedulers Evaluation for Palo Verde Unit 1 July 2, 2018

Schedulers Evaluation for Palo Verde Unit 2 July 9-15, 2018

Unit 2 Archived Equipment Out of Service Logs July 9-15, 2018

Unit 2 Archived Control Room Logs July 12, 2018

Unit 1 Archived Control Room Logs September 25, 2018

Schedulers Evaluation for Palo Verde Unit 1 September 25, 2018

71111.15 - Operability Determinations and Functionality Assessments

Procedures

Number Title Revision

40DP-9OPA4 Control Building Watch Station Rounds 117

Condition Reports (CRs)

18-12257 18-12205 18-06482 18-12437 18-06274

14-00265 15-00956 16-18718 18-07443 18-07709

18-11944 18-13785

Work Orders (WOs)

5000511 50115659 4664172

Miscellaneous

Number Title Date

18-10309-002 Level 3 Evaluation Report July 20, 2018

Unit 3 Operator Logs July 24, 2018

Vendor Technical Manual: Bingham Multi-stage Vertical Pumps

71111.19 - Post-Maintenance Testing

Procedures

Number Title Revision

2ST-9ZZ34 Class 1E Battery Charger 18 Month Surveillance Test 14

73ST-9SI11 Low Pressure Safety Injection Pumps Miniflow - Inservice Test 36

40ST-9DG02 Diesel Generator B Test 54

40OP-9CH01 CVCS Normal Operations 80

Condition Reports (CRs)

18-11830 18-02901

Work Orders (WOs)

4869034 4901631 4941821 5031793 5042494

4906529

71111.22 - Surveillance Testing

Procedures

Number Title Revision

73ST-9EC01 Essential Chilled Water Pumps - Inservice Test 28

73ST-9SP01 Essential Spray Pond Pumps - Inservice Test 54

74CH-9ZZ15 Dose Equivalent Xe-133 and Dose Equivalent I-131 8

Determination

74OP-9SS01 Primary Sampling Instructions 43

74ST-9RC02 Reactor Coolant System Specific Activity Surveillance Test 16

73ST-9SI11 Low Pressure Safety Injection Pumps Miniflow - Inservice Test 35

Procedures

Number Title Revision

40ST-9DG02 Diesel Generator B Test 54

Condition Reports (CRs)

18-00410 18-12764 18-12734

Work Orders (WOs)

4878325 4878512 4906610 3687952

Miscellaneous

Number Title

PVN-I-0010 Surveillance Test Risk-Informed Documented Evaluation

PVN-I-0029 Surveillance Test Risk-Informed Documented Evaluation

71114.04 - Emergency Action Level and Emergency Plan Changes

Procedures

Number Title Revision

16DP-0EP22 Emergency Plan Maintenance 12

Condition Reports (CRs)

18-08839 18-12409 18-14491

Miscellaneous

Number Title Date

2-07728-CS/WP PVNGS, Units 1, 2, and 3, and Independent Spent June 12, 2018

Fuel Storage Installation; Docket Nos. 50-528, 50-529,

50-530 and 72-44; License Nos. NPF-41, NPF-51 and

NPF-74; PVNGS Emergency Plan, Revision 61

Evaluation Effectiveness Evaluation Form, Revision 61, to the May 18, 2018

Tracking Number PVNGS Emergency Plan

2018-001E

Screening Tracking Screening Evaluation Form, Emergency Plan Revision May 16, 2018

Number 2018-009S 61

Evaluation 18- Late EP-812 July 26, 2018

08893-01

Miscellaneous

Number Title Date

Evaluation 18- Emergency Preparedness Process Enhancements August 22, 2018

2409-01

71114.06 - Drill Evaluation

Miscellaneous

Number Title Date

1806 ERO GREEN Team Mini Drill July 10, 2018

18078 ERO BLUE Team Mini Drill August 14, 2018

71151 - Performance Indicator Verification

Procedures

Number Title Revision

74CH-9ZZ15 Dose Equivalent Xe-133 and Dose Equivalent I-131 8

Determination

74OP-9SS01 Primary Sampling Instructions 43

74ST-9RC02 Reactor Coolant System Specific Activity Surveillance Test 16

40ST-9RC02 ERFDADS (Preferred) Calculation of RCS Water Inventory 54

71152 - Problem Identification and Resolution

Condition Reports (CRs)

18-11163 18-11224 18-11225 18-08435 18-11262

Work Orders (WOs)

28417 5029579 5029602 4886956 4896679

71153 - Follow-up of Events and Notices of Enforcement Discretion

Procedures

Number Title Revision

01DP-0AP57 Management of Critical and Infrequently Performed 2

Evolutions

2DP-9OP01 Site Wide Status Control Procedure 4

40DP-9OP02 Conduct of Operations 72

Procedures

Number Title Revision

40EP-9EO01 Standard Post Trip Actions 22

40EP-9EO02 Reactor Trip 14

40EP-9EO10 Standard Appendices 106

Condition Reports (CRs)

18-10686

Miscellaneous

Number Title Revision/Date

NNI01C070310 Non-Licensed Operator Initial Training: Area Operator August 29, 2014

Practices

NEI 99-02 Regulatory Assessment Performance Indicator Guideline 7

PV Unit 3 Archived Operator Logs June 27, 2018

PV Unit 3 Archived Operator Logs June 28, 2018

Palo Verde, Unit 3

Main Steam Line Isolation Event

Detailed Risk Evaluation

A regional senior reactor analyst performed a detailed risk evaluation and determined that the

finding associated with the main steam line isolation event was of very low safety significance

(Green).

The analyst performed an initiating event analysis as called for in Section 8.0, Initiating Event

Analyses, of Volume 1, Internal Events, of the RASP Handbook. The licensee provided

Engineering Evaluation 18-10686-021 to document their risk evaluation of the event. In this

evaluation, estimates were made using the licensees Palo Verde risk model and the NRCs

Palo Verde SPAR model. The licensees results from both models were similar after the

licensee made modifications to the SPAR model. The analyst reviewed these modifications and

incorporated changes to the SPAR model when were deemed appropriate.

The analyst chose to run this analysis as a loss of condenser heat sink event since the main

feedwater pumps and ability to dump steam to the condenser had been lost due to the event.

The licensee ran their analysis as a loss of main feedwater event, but the analyst deemed the

loss of condenser heat sink event more characteristic of the actual event.

The licensee in their evaluation suggested that this particular event resulted in extra steam

generator inventory which would allow additional time for operators to diagnose and perform

mitigating actions. The analyst reviewed the Loss of Condenser Heat Sink Event Tree and its

contributing fault trees in the Palo Verde SPAR model, in particular Fault Tree COND,

Secondary Side Cooling Using Condensate System, and its sub-fault tree COND-ALFW,

Operator Failure of Alternate Feedwater, to review the significant risk drivers for this analysis.

Because the performance deficiency would always result in a plant condition where one of the

steam generators would be filled to approximately the 91.5 percent level, the analyst considered

that more time would be available to operators to align the condensate system for feeding

steam generators as the licensee assumed. After discussions with Idaho National Laboratory

about the effect this would have on the SPAR model, the analyst modified the SPAR model

accordingly. The licensee performed a case-specific thermal hydraulic analysis using MAAP to

support their engineering evaluation which demonstrated that 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of steam generator

inventory were available to reach plant conditions where the condensate system would be

feeding the steam generators. The analyst reviewed this calculation, plant procedures, and

applicable operator training records. This review led the analyst to set basic event CDS-XHE-

XM-60MINS, Control Room Operators Fail to Depressurize Steam Generators and Supply

Alternate Feed Water in 1 Hour, to FALSE and to perform a revised SPAR-H analysis for basic

event CDS-XHE-XM-2HRS, Control Room Operators Fail to Depressurize Steam Generators

and Supply Alternate Feed Water in 2 Hours. The analyst considered the Available Time and

Stress performance shaping factors as the significant performance drivers. For the Available

Time performance shaping factor, the analyst applied the guidance in Section 3.1, Available

Time, of INL/EXT-10-18533, SPAR-H Step-by-Step Guidance, Revision 2, to apportion the

available time between diagnosis and action and considered nominal time was available for

action and extra time was available for diagnosis. For the Stress performance shaping factor,

the analyst considered stress was high for both diagnosis and action. These assumptions

yielded an estimate of the case-specific failure probability of this basic event of 4.40E-3. This

parameter estimate was slightly higher than the value of 4.0E-3 that the licensee used in their

SPAR-H analysis.

Additionally, the analyst reviewed the input of basic event AFW-TNK-FC-CTE01, Condensate

Storage Tank Catastrophic Failure, in the SPAR model after noting discussion by the licensee

in their evaluation. In the current SPAR model, the value for basic event AFW-TNK-FC-CTE01

is obtained from using the value for component failure mode TNK-FC, Tank Rupture, form the

2015 update to the NUREG/CR-6928, Industry-Average Performance for Components and

Initiating Events at

U.S. Commercial Nuclear Power Plants, which was 6.26E-6 for a 24-hour

mission time. In reviewing the source data and conferring with Idaho National Laboratory, the

analyst learned that this value estimates failure for all tanks, including both pressurized and

unpressurized. The analyst noted that component failure mode TNK-UNPRESS-LIQ-ELL,

Unpressurized Liquid Tank Small Leakage External Leakage (Large), was more appropriate as

the licensee had suggested in their evaluation. This mode carried a parameter estimate of

4.32E-7 failure probability for a 24-hour mission time, which the analyst used in place of basic

event AFW-TNK-FC-CTE01. The analyst ran sensitivities in the model for cases where there

was up to small external leakage of up to 50 gallons per minute and condensate storage tank

makeup was needed, but these sensitivities demonstrated no significant increase in risk when

applied and the analyst did not incorporate small leakage with makeup into the model.

In reviewing the risk significant results, the analyst noted that two basic events which were

present in the results which were not typical events seen in other plant SPAR models. These

events were ACP-ICC-FC-ESFA, Spurious Electrical Protection on Train A Engineered Safety

Features Bus Locks Out All Power Sources (PSA), and ACP-ICC-FC-ESFB and Spurious

Electrical Protection on Train B Engineered Safety Features Bus Locks Out All Power Sources

(PSA). The analyst noted that the failure probability of 1.70E-3 of these events was derived

from data from a 1989 Westinghouse Savannah River Site parameter report. After consulting

with Idaho National Laboratory, the analyst mapped the failure probability for these two basic

events to template event ZT-BAC-LP, AC Bus Fails to Operate, which uses a parameter

estimate failure probability of 2.29E-5 which incorporates data from the 2015 update of

NUREG/CR-6928. The analyst assumed that the mapping of these basic events to the template

event yielded a more accurate representation of the true failure probability of this type of failure.

These modifications resulted in a change in core damage frequency of 8.4E-7/year for the

finding. Because the result was close to the Green-White threshold for the Significance

Determination Process, the analyst ran an uncertainties analysis on the results of the SPAR

model in SAPHIR

E. Of the 5000 cases ran in a Monte Carlo analysis, approximately 80 percent

of the results were less than 1.0E-6 giving confidence that the finding was of very low safety

significance (Green). This final result was higher than the licensees estimate of approximately

4.0E-7 from their engineering evaluation primarily because the SPAR results included additional

risk from the probability of a consequential loss of offsite power due to the reactor trip where the

licensees analysis did not. Losses of condenser heat sink events comprised the most dominant

core damage sequences. The offsite electrical power and emergency feed water systems

remained available for mitigation of the dominant sequences. The analyst ran the Palo Verde

SPAR model, Revision 8.55, on SAPHIRE, Version 8.1.8, to calculate the conditional core

damage probability using a cutset truncation of 1.0E-12.

The analyst assumed that external events would be an insignificant contributor to the increase

in core damage frequency because the probability of any external event coinciding with the

main steam line isolation event would be extremely low. As a result, only the increase in core

damage frequency from the initiating event was used in the final estimate.

After reviewing Manual Chapter 0609, Appendix H, Containment Integrity Significance

Determination Process, the analyst determined that main steam line isolation and loss of main

feedwater sequences were not significant contributors to large early release frequency and

screened the finding to Green for large early release frequency.

ML18318A355

SUNSI Review: ADAMS: Non-Publicly Available Non-Sensitive Keyword:

By: JDixon Yes No Publicly Available Sensitive

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NAME CPeabody DReinert DYou TFarnholtz GWerner VGaddy

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DATE 11/5/2018 11/2/2018 11/5/2018 11/06/2018 11/06/2018 11/07/18

OFFICE C:DRS/PS2 C:DRP/D

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SIGNATURE HJG MSH for

DATE 11/06/18 11/14/18