IR 05000445/2018003

NRC Integrated Inspection Report 05000445/2018003 and 05000446/2018003

ML18304A318
Person / Time
Site:	Comanche Peak
Issue date:	10/31/2018
From:	Mark Haire NRC/RGN-IV/DRP
To:	Peters K Vistra Operations Company
References
IR 2018003
Download: ML18304A318 (18)

Text

ber 31, 2018

SUBJECT:

COMANCHE PEAK NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000445/2018003 AND 05000446/2018003

Dear Mr. Peters:

On September 30, 2018, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Comanche Peak Nuclear Power Plant, Units 1 and 2. On October 11, 2018, the NRC inspectors discussed the results of this inspection with Mr. Tom McCool, Site Vice President, and other members of your staff. The results of this inspection are documented in the enclosed report.

NRC inspectors documented two findings of very low safety significance (Green) in this report.

Both of these findings involved violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violations or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement; and the NRC resident inspector at the Comanche Peak Nuclear Power Plant. 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 S. Haire, Chief Project Branch A Division of Reactor Projects Docket Nos. 50-445 and 50-446 License Nos. NPF-87 and NPF-89 Enclosure:

Inspection Report 05000445/2018003 and 05000446/2018003 w/ Attachments:

1. Documents Reviewed 2. Detailed Risk Evaluation

U.S. NUCLEAR REGULATORY COMMISSION

Inspection Report

Docket Number(s): 05000445 and 05000446 License Number(s): NPF-87 and NPF-89 Report Number(s): 05000445/2018003 and 05000446/2018003 Enterprise Identifier: I-2018-003-0011 Licensee: Vistra Operations Company, LLC Facility: Comanche Peak Nuclear Power Plant, Units 1 and 2 Location: Glen Rose, Texas Inspection Dates: July 1, 2018 to September 30, 2018 Inspectors: J. Josey, Senior Resident Inspector R. Kumana, Resident Inspector H. Freeman, Senior Reactor Inspector Approved By: Mark S. Haire Chief, Project Branch A Division of Reactor Projects Enclosure

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting an integrated inspection at Comanche Peak Nuclear Power Plant,

Units 1 and 2, 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 the Ability to Withstand a Station Blackout Cornerstone Significance Cross-cutting Inspection Aspect Procedure Mitigating Green None 71152 -

Systems NCV 05000445/2018003-01; Problem 05000446/2018003-01 Identification Closed and Resolution The inspectors identified a Green, non-cited violation of 10 CFR Part 50.63 for the licensees failure to maintain the ability to withstand and recover from a station blackout. Specifically, the licensees approved coping analysis for each unit required the availability of equipment on the non-blacked-out unit, and the licensee failed to maintain the required equipment available.

The licensee entered this violation into their corrective action program as condition report CR-2017-011090.

Failure to Establish Adequate Procedural Guidance for Processing Technical Changes Performed by a Vendor on Installed Plant Equipment Cornerstone Significance Cross-cutting Report Aspect Section Mitigating Green None 71152 -

Systems NCV 05000445/2018003-02; Problem 5000446/2018003-02 Identification Closed and Resolution The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, associated with the licensees failure to establish an adequate procedure for controlling and processing vendor documents and vendor technical information. This resulted in the licensees failure to properly evaluate changes made by vendors to plant equipment. Specifically, the licensee allowed vendors to make physical changes to a component cooling water pump shaft and main steam isolation valve actuators without evaluating these changes. The licensee entered this issue into the corrective action program as Condition Reports CR-2018-004485 and CR-2018-004605.

Additional Tracking Items Type Issue number Title Inspection Status Procedure VIO 05000445/2017010-01; Failure to Update Final 92702 Closed 05000446/2017010-01 Safety Analysis Report Section 8.3.1.1.11

PLANT STATUS

Unit 1 operated at or near rated thermal power for the entire inspection period.

Unit 2 began the inspection period at rated thermal power. On August 13, 2018, the unit tripped automatically due to a failure on the turbine generator voltage regulator. The unit was restarted on August 15, 2018. The unit was returned to rated thermal power on August 17, 2018, and remained at or near rated thermal 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

71111.01Adverse Weather Protection Seasonal Extreme Weather

The inspectors evaluated readiness for seasonal extreme weather conditions prior to the onset of seasonal hot temperatures.

71111.04Equipment Alignment Partial Walkdown

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

(1) Unit 1 batteries 1ED1 and 1ED3 on July 26, 2018

(2) Unit 2 residual heat removal pump 2-02 on September 5, 2018

(3) Unit 2 turbine driven auxiliary feedwater pump on September 12, 2018

(4) Unit 2 instrument air system on September 14, 2018

Complete Walkdown (1 Sample)

The inspectors evaluated system configurations during a complete walkdown of the uninterruptible power supply (UPS) heating ventilation and air conditioning system on September 25, 2018.

71111.05AQFire Protection Annual/Quarterly Quarterly Inspection

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

(1) Fire zone EQ149, UPS Chiller X-01 on September 17, 2018

(2) Fire zone ER150, UPS Chiller X-02 on September 17, 2018

(3) Fire zone EH52 and EH53, train A UPS rooms on September 21, 2018

(4) Fire zone EC50 and EC51, train B UPS rooms on September 21, 2018

71111.06Flood Protection Measures Internal Flooding

The inspectors evaluated internal flooding mitigation protections in the UPS chiller rooms on August 29, 2018.

71111.11Licensed Operator Requalification Program and Licensed Operator Performance Operator Requalification

The inspectors observed and evaluated a crew during an evaluated simulator scenario on

===September 5, 2018.

Operator Performance (1 Sample)===

The inspectors observed and evaluated Unit 2 control room operators during post trip response on August 13, 2018, and Unit 2 startup activities on August 15, 2018.

71111.12Maintenance Effectiveness Routine Maintenance Effectiveness

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

(1) Units 1 and 2 UPS chillers on August 22, 2018

71111.13Maintenance Risk Assessments and Emergent Work Control

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

(1) Unit 2, repair of containment pressure relief valve on July 9, 2018

(2) Unit 2, trip and repair of emergency diesel generator 2-02 on August 22, 2018

(3) Units 1 and 2, breach of control room envelope on August 24, 2018

(4) Units 1 and 2, repair of auxiliary feedwater pump flow control valves on August 28, 2018

(5) Units 1 and 2, measurement of silt level in station service water intake bay on July 25, 2018

71111.15Operability Determinations and Functionality Assessments

The inspectors evaluated the following operability determinations and functionality assessments:

(1) Unit 2, containment isolation valve leakage, on July 9 , 2018

(2) Unit 1, failure of battery cell on battery 1ED2, on July 2, 2018

(3) Units 1 and 2, inadequate procedure for makeup to component cooling water system, on July 16, 2018

(4) Unit 2, safety injection accumulator 2-01 high pressure, on July 26, 2018

(5) Unit 1, incorrect fuses removed from 480V bus 1EB1, on September 24, 2018

71111.18Plant Modifications

The inspectors evaluated the following temporary or permanent modifications:

(1) Removal of cell 27 from battery 1ED2 after the cell was discovered cracked on July 2, 2018

71111.19Post Maintenance Testing

The inspectors evaluated the following post maintenance tests:

(1) Unit 2, containment pressure relief valve 2-HV-5549 following repair, on July 19, 2018

(2) Unit 1, battery 1ED2 following installation of cell jumper, on July 27, 2018

(3) Unit 2, reactor trip breaker following replacement of auxiliary switches, on August 16, 2018

(4) Unit 2, steam generator feedwater leading edge flow monitor following probe replacement, on August 20, 2018

(5) Unit 2, diesel generator 2-02 following replacement of master drive, on August 27, 2018

(6) Unit 1, drip pot drain isolation valve 1-LV-2373 following repair, on August 29, 2018

(7) Unit 1, battery charger 1ED1-1 following card replacement, on September 26, 2018

71111.22Surveillance Testing The inspectors evaluated the following surveillance tests: Routine

(1) Unit 1, OPT-447A, train A reactor trip breaker test, on August 1, 2018

(2) Units 1 and 2, OPT-220, fire pump X-06 test, on August 30, 2018

(3) Unit 1, OPT-206A, turbine driven auxiliary feedwater pump test, on September 7, 2018

In-service (2 Samples)

(1) Unit 2, OPT-837, 2-HV-5545, air particulate, iodine and gas detector sample isolation valve leak test, on July 10, 2018

(2) Unit 1, OPT-208A, component cooling water pump 1-01 discharge valve test, on August 29, 2018

71114.06Drill Evaluation Drill/Training Evolution

The inspectors evaluated an emergency preparedness drill on July 11,

OTHER ACTIVITIES - BASELINE

71151Performance Indicator Verification

The inspectors verified licensee performance indicators submittals listed below:

(1) MS06: Emergency AC Power Systems (07/01/2017-06/30/2018)

(2) MS07: High Pressure Injection Systems (07/01/2017-06/30/2018)

(3) MS08: Heat Removal Systems (07/01/2017-06/30/2018)

71152Problem 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) Failure to meet station blackout coping requirements during adjacent unit refueling outages

(2) Failure to perform a 50.59 evaluation for a vendor change to a component cooling water pump

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

The inspectors evaluated a Unit 2 reactor trip and licensees performance on August 13,

OTHER ACTIVITIES

- TEMPORARY INSTRUCTIONS, INFREQUENT AND ABNORMAL 92702Follow-up on Traditional Enforcement Actions Including Violations, Deviations, Confirmatory Action Letters, Confirmatory Orders, and Alternative Dispute Resolution Confirmatory Orders The inspectors reviewed the licensees response to Notice of Violation (NOV)05000445/2017010-01; 05000446/2017010-01 and determined that the reason, corrective actions taken and planned to address recurrence, and the date when full compliance will be achieved for this violation are adequately addressed and captured on the docket.

INSPECTION RESULTS

Failure to Maintain the Ability to Withstand a Station Blackout Cornerstone Significance Cross-cutting Inspection Aspect Procedure Mitigating Green None

71152 - Systems NCV 05000445/2018003-01; Problem

05000446/2018003-01 Identification Closed and Resolution The inspectors identified a Green, non-cited violation of 10 CFR Part 50.63 for the licensees failure to maintain the ability to withstand and recover from a station blackout. Specifically, the licensees approved coping analysis for each unit required the availability of equipment on the non-blacked-out unit, and the licensee failed to maintain the required equipment available.

Description:

During the inspectors review of the outage schedule for Unit 1 refueling outage 1RF19, the inspectors noted that the licensee planned to remove both diesel generators from service while Unit 1 was defueled. The inspectors asked the licensee whether they would be able to comply with their station blackout coping analysis for Unit 2 with both Unit 1 diesel generators out of service. The licensee revised their outage schedule to ensure one diesel generator would be available while the inspectors continued to inspect the issue.

The inspectors determined that the licensees coping analysis for station blackout assumed the ability to cope for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> without AC power to the blackout unit by crediting one onsite AC source from the non-blacked-out unit supplying power to shared equipment. This was approved by the NRC because the station blackout rule (10 CFR 50.63) applies to each unit individually. The coping analysis assumes that the non-blacked-out unit has one diesel generator available to mitigate the concurrent loss of offsite power and unit trip on the non-blacked-out unit, provide ventilation and air conditioning to the common control room and uninterruptible power supply (UPS) rooms, and provide power to shared onsite communication systems. In order for the strategy documented in the analysis to succeed, the licensee requires the non-blacked-out unit to be able to start and run one emergency diesel generator, one station service water pump, one control room air conditioning unit, one UPS supply fan, and one component cooling water pump. Subsequently, the licensee credited an additional fan coil unit in each UPS room for cooling, assuming one fan coil unit and one safety chiller would start and run. These loads normally automatically start on a loss of voltage to the associated safety bus.

In 1999, the licensee planned for both Unit 1 diesel generators and both Unit 1 component cooling water pumps to be out of service concurrently during refueling outage 1RF07. The licensee identified the impact of this activity to the station blackout coping analysis, but assumed the activity could be performed as long as actions were taken to mitigate the risk of a station blackout on the operating unit. Following that outage, the licensee incorporated the decision to perform maintenance by disabling the ability to cope with a station blackout into the Final Safety Analysis Report and implemented this strategy during multiple subsequent refueling outages on both units.

The inspectors determined that the licensee had, on multiple occasions, removed equipment from service that was necessary to allow the operating unit to withstand and recover from a station blackout. The inspectors determined that this practice was not correct and was a violation of the station blackout rule (10 CFR 50.63). The inspectors determined that the licensees decision to take this equipment out of service during outages was made in 1999 and was not reflective of present performance.

Corrective Action(s): The licensee entered this violation into their corrective action program.

Corrective Action Reference: CR-2017-011090

Performance Assessment:

Performance Deficiency: The licensees failure to maintain the ability to implement their approved station blackout coping strategy was a performance deficiency.

Screening: The inspectors determined the performance deficiency was more than minor because it is associated with the configuration control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees failure to ensure equipment relied upon to implement their approved station blackout coping analysis was available resulted in multiple periods of time where the station blackout coping analysis could not be met.

Significance: The inspectors assessed the significance of the finding using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Inspection Manual Chapter 0609, Appendix A, Significance Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, and determined the finding required a detailed risk evaluation because the finding represented a loss of system and/or function.

A region-based senior reactor analyst performed a detailed risk evaluation and determined that the finding was of very low safety significance (Green) based on a bounding estimate of the increase in core damage frequency of 3.5E-9 per year. The bounding estimate was based on an exposure time of 138 hours0.0016 days <br />0.0383 hours <br />2.281746e-4 weeks <br />5.2509e-5 months <br /> (i.e., the longest time the vulnerability existed during prior refueling outages), and initiating event and Class 1E electrical system failure probabilities obtained from the current Standardized Plant Analysis Risk (SPAR) model for Comanche Peak. Losses of offsite power comprised the most dominant core damage sequences. (Additional details regarding the evaluation are contained in the attachment to this report.)

Cross-cutting Aspect: The finding was not assigned a cross-cutting aspect because the finding was not indicative of present performance.

Enforcement:

Violation: Title 10 CFR 50.63 Loss of All Alternating Current Power, requires, in part, that each light-water-cooled nuclear power plant licensed to operate under this part must be able to withstand for a specified duration and recover from a station blackout as defined in § 50.2, and that the capability for coping with a station blackout of specified duration shall be determined by an appropriate coping analysis. In the coping analysis approved by the agency in NUREG-0797 Supplement 26 for Units 1 and 2, the licensee credits the availability of an emergency diesel generator in the non-blacked-out unit for the operation of selected systems necessary to cope with a station blackout.

Contrary to the above, from approximately 1999 until 2017, the licensee failed to maintain the ability of each unit to withstand and recover from a station blackout during outages of the adjacent unit. Specifically, the licensee, on multiple occasions, removed both diesel generators from service on the non-blacked-out unit resulting in an inability to implement the approved coping analysis.

Enforcement Action: This violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy.

Failure to Establish Adequate Procedural Guidance for Processing Technical Changes Performed by A Vendor on Installed Plant Equipment Cornerstone Significance Cross-cutting Report Aspect Section Mitigating Green None

71152 - Systems NCV 05000445/2018003-02; Problem

5000446/2018003-02 Identification Closed and Resolution The inspectors identified a Green, NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, associated with the licensees failure to establish an adequate procedure for controlling and processing vendor documents and vendor technical information. This resulted in the licensees failure to properly evaluate changes made by vendors to plant equipment. Specifically, the licensee allowed vendors to make physical changes to a component cooling water pump shaft and main steam isolation valve actuators without evaluating these changes.

Description:

While reviewing vendor refurbishment records supplied to the licensee for a component cooling water pump shaft and main steam isolation valve actuators, the inspectors noted that the vendors had performed physical changes to these components during refurbishment. (These records were from activities that occurred in 2002.) The inspectors noted that the licensees paperwork did not contain documentation of how these changes were evaluated for adverse impacts since these items were subsequently installed in the facility.

The inspectors asked the licensee for the documents that evaluated these changes. The licensee informed the inspectors that there were no evaluations performed at the time. The inspectors questioned this and were told by the licensee that station procedure STA-206, Review of Vendor Documents and Vendor Technical Manuals, Revision 20 (procedure in effect at the time), did not require a review because these changes were maintenance activities and therefore did not require evaluation.

The inspectors determined that this guidance was not correct and resulted in the licensee allowing vendors to make unevaluated physical changes to installed plant equipment.

Specifically, the licensee implemented guidance contained in EPRI/NSAC-125, Guidelines for 10 CFR 50.59 Safety Evaluations, in STA-206, Revision 20, when the determination was made in 2002 that the changes to the components were maintenance activities, and therefore did not require an evaluation. However, the guidance in NSAC-125 has never been reviewed and endorsed by the NRC; rather, NEI 96-07, Guidelines for 10 CFR 50.59 Implementation, Revision 1, had been reviewed and endorsed by the NRC in Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiments (issued in late 1999 and late 2000, respectively). The endorsed guidance in NEI 96-07 specifically noted that for those situations where a plant component is not restored to its original condition following completion of maintenance activities (which may have been controlled by the requirements of 10 CFR 50.65(a)(4) [i.e., the Maintenance Rule]), the requirements of 10 CFR 50.59 (including the completion of an evaluation for adverse impact) would be applied to the permanent change to the plant component.

The inspectors determined that these issues occurred in 2002 and the procedure guidance that allowed the licensee to incorrectly control vendor information has since been revised in 2010; therefore this was not reflective of present performance.

Corrective Action(s): The licensee performed operability determinations that established a reasonable expectation of operability pending development of additional corrective actions.

Corrective Action References: CR-2018-004485 and CR-2018-004605

Performance Assessment:

Performance Deficiency: The licensees failure to establish adequate procedural guidance for processing technical changes performed by a vendor on installed plant equipment was a performance deficiency.

Screening: The inspectors determined the performance deficiency was more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee allowed vendors to make physical changes to a component cooling water pump shaft and main steam isolation valve actuators without evaluating these changes.

Significance: The inspectors assessed the significance of the finding using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, dated October 7, 2016, and Inspection Manual Chapter 0609, Appendix A, Significance Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined the finding was of very low safety significance (Green)because:

(1) it was not a design deficiency;

(2) it did not represent a loss of system and/or function;

(3) it did not represent an actual loss of function of at least a single train for longer than its technical specification allowed outage time; and

(4) it did not result in the loss of a high safety significant non-technical specification train.

Cross-cutting Aspect: The finding was not assigned a cross-cutting aspect because the finding was not indicative of current performance.

Enforcement:

Violation: Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, and drawings.

Contrary to the above, from 2002 until 2010, activities affecting quality that were not prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances. Specifically, Station Procedure STA-206, Review of Vendor Documents and Vendor Technical Manuals, Revision 20, provided inadequate guidance for processing technical changes performed by a vendor on installed plant equipment.

Enforcement Action: This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy.

EXIT MEETINGS AND DEBRIEFS

On October 11, 2018, the inspectors presented the quarterly resident inspection results to Mr. Tom McCool, and other members of the licensee staff. The inspectors verified no proprietary information was retained or documented in this report.

DOCUMENTS REVIEWED

71152Problem Identification and Resolution

Condition Reports

CR-2017-011090 TR-2017-011125 CR-2018-004485 CR-2018-004605

CR-2018-001530 CR-2018-001532 CR-2018-003476 CR-2018-000941

Procedures

Number Title Revision

STA-206 Review of Vendor Documents and Vendor Technical 20

Manuals

Miscellaneous

Documents Revision

Number Title or Date

DBD-EE-043 118V AC Uninterruptible Power System 14

DBD-ME-026 Station Blackout 12

TXX-92447 Response to Station Blackout (SBO) Rule October 1, 1992

LDCR SA-2000- Update/Clarify SBO Coping as Described on Pages 2 October 25,

049 Through 6 2000

DBD-ME-313 Uninterruptible Power Supply HVAC System 12

TXX-96475 Additional Information for License Amendment 96-004 October 1, 1996

Uninterruptible Power Supplies (UPS) HVAC System

Addition of Fan Coil Units to Technical Specifications

Engineering

Reports Number Title Revision

ER-ME-011 Unit 1 & Unit 2 Station Blackout Assessment 2

Calculations

Number Title Revision

3-D-2-027 Temperature Transient Study for Station Blackout 0

RXE-LA-CPX/0-099 Station Blackout Coping Analysis for CPSES Units 1& 2 at 0

3634 MW

3-D-2-025 UPS Room Temperature Transients During Sta. Blkot & 0

FSSD

ME-CA-0313-4079 UPS Inverter Rooms Temperature Transient following Station 2

Blackout with one Room Cooler in Operation

2702 Follow-up on Traditional Enforcement Actions Including Violations, Deviations,

Confirmatory Action Letters, Confirmatory Orders, and Alternative Dispute Resolution

Confirmatory Orders

Miscellaneous

Documents

Number Title Date

CP-201800120 Comanche Peak Nuclear Power Plant Docket March 22, 2018

TXX-18012 Nos. 05000445 and 05000446 Reply to a Notice of

Violation

Comanche Peak Station Blackout Issue

NCV 05000445/2018003-01; 05000446/2018003-01

Detailed Risk Evaluation

A region-based senior reactor analyst performed a detailed risk evaluation and determined that

the finding was of very low safety significance (Green) by determining a bounding estimate of

the increase in core damage frequency of 3.5E-9/year.

To establish this bounding estimate the analyst assumed:

• The exposure time was 138 hours0.0016 days <br />0.0383 hours <br />2.281746e-4 weeks <br />5.2509e-5 months <br /> based on the longest time the vulnerability was in

place.

• The initiating event frequency for losses of offsite power was 3.24E-2 per year. This

frequency was obtained from the current Comanche Peak SPAR model. This includes

losses of offsite power from grid-related, plant-centered, switchyard-centered, and

weather-related causes.

• Losses of offsite power from external events (e.g., tornados, earthquakes) occurred at

very low frequencies and were insignificant contributors to the increase in core damage

frequency.

• The probability of a loss of emergency diesel generator electrical output to its respective

electrical bus was:

o Emergency Diesel 1 to Bus 1EA1: 7.13E-2

o Emergency Diesel 2 to Bus 1EA2: 7.14E-2

These values were obtained by solving sub-fault trees ACP-1EA1-3 and ACP-1EA2-5 in

the current Comanche Peak SPAR model.

• The probability of a fault on either bus 1EA1 or bus 1EA2 was 2.29E-5. This value was

obtained from the current Comanche Peak SPAR model.

• All mitigating equipment would fail as a result of the performance deficiency yielding a

conditional core damage probability of 1.0. This assumption was conservative as

complete failure of all mitigating equipment was not realistically expected.

A detailed estimate of the increase in large early release frequency was not performed because

the increase in core damage frequency was so low that even if the containment failed

completely, the maximum increase in large early release frequency would have been 3.5E-

9/year (Green). Losses of offsite power comprised the most dominant core damage sequences.

Recovery of the emergency diesel generators was available for mitigation of the dominant

sequences. The analyst solved fault trees and obtained data from the Comanche Peak SPAR

model, Revision 8.55, on SAPHIRE, Version 8.1.8, using a cutset truncation of 1.0E-12.

ML18304A318

SUNSI Review ADAMS Non-Sensitive Publicly Available Keyword:

By: MSH Yes No Sensitive Non-Publicly Available NRC-002

OFFICE SRI:DRP/A RI:DRP/A SPE:DRP/A BC:EB1 BC:EB2 BC:OB

NAME JJosey RKumana RAlexander TFarnholtz GWerner VGaddy

SIGNATURE JEJ RJK RDA TRF GEW vgg

DATE 10/29/2018 10/22/2018 10/29/2018 10/22/2018 10/29/2018 10/23/18

OFFICE BC:PSB2 TL-IPAT BC:DRP/A

NAME HGepford GMiller MHaire

SIGNATURE hjg GBM MSH

DATE 10/22/18 10/22/18 10/31/2018