IR 05000528/2018003
| 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
November 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
Enclosure U.S. NUCLEAR REGULATORY COMMISSION
Inspection Report
Docket Numbers:
05000528, 05000529, 05000530
License Numbers:
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
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 Events Green FIN 05000530/2018003-01 None 71153 - Follow Up 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 Procedure Status LER 05000530/2018-001-00 Unit 3 Reactor Trip on Low Steam Generator Water Level 71153 Closed
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.
REACTOR SAFETY
71111.01 - Adverse Weather Protection
External Flooding (1 Sample)
The inspectors evaluated readiness to cope with external flooding on July 27, 2018.
71111.04 - Equipment Alignment
Partial Walkdown (4 Samples)
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 (6 Samples)
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 (2 Samples)
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 (1 Sample)
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 (3 Samples)
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 (2 Samples)
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 (2 Samples)
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 Aspect Inspection Procedure Initiating Events
Green FIN 05000530/2018003-01
None 71153 - Follow Up 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
Condition Reporting Process
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
PVNGS Design Basis Manual
011
71111.04 - Equipment Alignment
Procedures
Number
Title
Revision
Auxiliary Feedwater Pump AFB-P01 Monthly Valve Alignment
Essential Spray Pond (SP) Train A
Condition Reports (CRs)
2898475
Miscellaneous
Number
Title
Revision/Date
13-MS-A70
Separation/hazards evaluation for the Palo Verde motor
driven AFW Train B pump room
January 9, 1997
CRAI 2833456
Condition Report Action Item Resolution
01-M-EWP-001
P & I Diagram Essential Cooling Water System
Miscellaneous
Number
Title
Revision/Date
01-P-EWF-201
Auxiliary Bldg. Isometric Essential Cooling Water System
ECWS Pump Loop - Train A
03-E-MAA-002
Unit Single Line Diagram
03-E-PBA-002
Single Line Diagram 4.16 KV Class 1E Power System
Switchgear 3E-PBB-S04
03-E-PBA-001
Single Line Diagram 4.16 KV Class 1E Power System
Switchgear 3E-PBA-S03
ANSI/ANS-51.10-1979
1979Property "ANSI code" (as page type) with input value "ANSI/ANS-51.10-1979</br></br>1979" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process.
71111.05 - Fire Protection
Calculations
Number
Title
Revision
13-MC-FP-0803
Combustible Loads - Control Building
Condition Reports (CRs)
18-11447
Work Orders (WOs)
29881
Miscellaneous
Number
Title
Revision
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
71111.06 - Flood Protection Measures
Calculations
Number
Title
Revision
13-MC-ZA-0809
As Built Auxiliary Building Flooding Calculation
13-MC-ZA-0810
Flooding Between Adjacent Safety Related Structures
13-MC-ZZ-0642
Moderate Energy Crack Evaluation
Calculations
Number
Title
Revision
13-MC-ZJ-0200
As Built Control Building Flooding Calculation
Condition Reports (CRs)
18-09076
18-02946
Miscellaneous
Number
Title
Revision
13-E-ZVU-008
Underground Electrical Duct Layout Plot Plan
71111.11 - Licensed Operator Requalification Program and Licensed Operator Performance
Procedures
Number
Title
Revision
Plant Startup Mode 2 to Mode 1
Condition Reports (CRs)
18-10686
Work Orders (WOs)
4906612
4900690
71111.12 - Maintenance Effectiveness
Procedures
Number
Title
Revision
Standard Post Trip Actions
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
Protected Equipment
Online Integrated Risk
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
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
Class 1E Battery Charger 18 Month Surveillance Test
Low Pressure Safety Injection Pumps Miniflow - Inservice Test
Diesel Generator B Test
CVCS Normal Operations
Condition Reports (CRs)
18-11830
18-02901
Work Orders (WOs)
4869034
4901631
4941821
5031793
5042494
4906529
71111.22 - Surveillance Testing
Procedures
Number
Title
Revision
Essential Chilled Water Pumps - Inservice Test
Essential Spray Pond Pumps - Inservice Test
Dose Equivalent Xe-133 and Dose Equivalent I-131
Determination
Primary Sampling Instructions
Reactor Coolant System Specific Activity Surveillance Test
Low Pressure Safety Injection Pumps Miniflow - Inservice Test
Procedures
Number
Title
Revision
Diesel Generator B Test
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
Emergency Plan Maintenance
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
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
June 12, 2018
Evaluation
Tracking Number
2018-001E
Effectiveness Evaluation Form, Revision 61, to the
May 18, 2018
Screening Tracking
Number 2018-009S
Screening Evaluation Form, Emergency Plan Revision
May 16, 2018
Evaluation 18-
08893-01
Late EP-812
July 26, 2018
Miscellaneous
Number
Title
Date
Evaluation 18-
2409-01
Emergency Preparedness Process Enhancements
August 22, 2018
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
Dose Equivalent Xe-133 and Dose Equivalent I-131
Determination
Primary Sampling Instructions
Reactor Coolant System Specific Activity Surveillance Test
ERFDADS (Preferred) Calculation of RCS Water Inventory
71152 - Problem Identification and Resolution
Condition Reports (CRs)
18-11163
18-11224
18-11225
18-08435
18-11262
Work Orders (WOs)
28417
29579
29602
4886956
4896679
71153 - Follow-up of Events and Notices of Enforcement Discretion
Procedures
Number
Title
Revision
Management of Critical and Infrequently Performed
Evolutions
Site Wide Status Control Procedure
Conduct of Operations
Procedures
Number
Title
Revision
Standard Post Trip Actions
Standard Appendices
106
Condition Reports (CRs)
18-10686
Miscellaneous
Number
Title
Revision/Date
NNI01C070310 Non-Licensed Operator Initial Training: Area Operator
Practices
August 29, 2014
Regulatory Assessment Performance Indicator Guideline
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
- 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.
SUNSI Review:
ADAMS:
Non-Publicly Available
Non-Sensitive
Keyword:
By: JDixon
Yes No
Publicly Available
Sensitive
OFFICE
DRP/SRI
DRP/RI
DRP/RI
C:DRS/EB1
C:DRS/EB2
C:DRS/OB
NAME
CPeabody
DReinert
DYou
TFarnholtz
GWerner
VGaddy
SIGNATURE
DRR
DDY
TRF
GEW
vgg
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
NAME
HGepford
NOkeefe
SIGNATURE
HJG
MSH for
DATE
11/06/18
11/14/18