IR 05000498/2017002

NRC Integrated Inspection Report 05000498/2017002 and 05000499/2017002

ML17227A276
Person / Time
Site:	South Texas
Issue date:	08/14/2017
From:	Nick Taylor NRC/RGN-IV/DRP/RPB-B
To:	Gerry Powell South Texas
NICK TAYLOR
References
IR 2017002
Download: ML17227A276 (50)

Text

August 14, 2017

SUBJECT:

SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000498/2017002 AND 05000499/2017002

Dear Mr. Powell:

On June 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your South Texas Project Electric Generating Station, Units 1 and 2, facility. On July 6, 2017, the NRC inspectors discussed the results of this inspection with you and other members of your staff. The results of this inspection are documented in the enclosed report.

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

All 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.a 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 South Texas Project Electric Generating Station, Units 1 and 2, facility.

If you disagree with a cross-cutting aspect assignment 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 South Texas Project Electric Generating Station, Units 1 and 2, facility.

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION IV

1600 E. LAMAR BLVD ARLINGTON, TX 76011-4511 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 T. Pruett for/

Nicholas H. Taylor, Branch Chief Project Branch B Division of Reactor Projects Docket Nos. 50-498 and 50-499 License Nos. NPF-76 and NPF-80 Enclosure: Inspection Report 05000498/2017002 and 05000499/2017002 w/ Attachments:

1. Supplemental Information 2. Information Request for Inservice Inspection Activities

SUNSI Review:

ADAMS:

Non-Publicly Available Non-Sensitive Keyword:

By:NHT/dll Yes No Publicly Available Sensitive NRC-002 OFFICE SRI:DRP/B RI:DRP/B C:DRS/EB1 C:DRS/EB2 C:DRS/OB C:DRS/PSB2 NAME ASanchez NHernandez TFarnholtz GWerner VGaddy HGepford SIGNATURE

/RA/

/RA/

/RA/

/RA/

/RA/

/RA/

DATE 8/3/17 08/02/2017 07/31/2017 08/02/17 8/2/17 8/4/2017 OFFICE C:DRS/IPAT BC:DRP/B DRP/D NAME THipschman NTaylor TPruett SIGNATURE

/RA/HFreeman for

/RA/

/RA/

DATE 08/01/2017 8/3/17 8/14/17

Enclosure U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket:

05000498, 05000499 License:

NPF-76, NPF-80 Report:

05000498/2017002 and 05000499/2017002 Licensee:

STP Nuclear Operating Company Facility:

South Texas Project Electric Generating Station, Units 1 and 2 Location:

FM 521 - 8 miles west of Wadsworth Wadsworth, Texas 77483 Dates:

April 1 through June 30, 2017 Inspectors:

A. Sanchez, Senior Resident Inspector N. Hernandez, Resident Inspector I. Anchondo, Reactor Inspector J. Braisted, Reactor Inspector W. Cullum, Reactor Inspector N. Okonkwo, Reactor Inspector C. Smith, Reactor Inspector, Lead Approved By: Nicholas H. Taylor, Chief, Project Branch B Division of Reactor Projects

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SUMMARY

IR 05000498/2017002, 05000499/2017002; 04/01/2017 - 06/30/2017; South Texas Project

Electric Generating Station, Units 1 and 2; Refueling and Other Outage Activities, and Problem Identification and Resolution

The inspection activities described in this report were performed between April 1 and June 30 2017, by the resident inspectors at the South Texas Project and inspectors from the NRCs Region IV office. Three findings of very low safety significance (Green) are documented in this report. All of these findings involved a violation of NRC requirements. The significance of inspection findings is indicated by their color (i.e., Green, greater than Green, White, Yellow, or Red), determined using Inspection Manual Chapter 0609, Significance Determination Process, dated April 29, 2015. Their cross-cutting aspects are determined using Inspection Manual Chapter 0310, Aspects within the Cross-Cutting Areas, dated December 4, 2014.

Violations of NRC requirements are dispositioned in accordance with the NRC Enforcement Policy. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, dated July 2016.

Cornerstone: Initiating Events

Green.

The inspectors documented a self-revealed, non-cited violation of Technical Specification 6.8.1.a, Regulatory Guide 1.33, Revision 2, February 1978, Appendix A,

Section 9.d.(4). Specifically, inadequate written work instructions to remove the reactor vessel head vent rig and install a breathable foreign material exclusion cover resulted in installing a blind flange and a loss of reactor coolant system water while at lowered inventory. The licensee developed proper instructions and the blind flange was promptly removed to restore the vent path for the reactor vessel head. Reactor coolant system inventory was restored. This issue was entered into the licensees corrective action program as Condition Report 2017-13155.

The failure of the licensee to provide appropriate written work instructions to install a breathable foreign material exclusion cover following the removal of the reactor vessel head vent rig was a performance deficiency. The performance deficiency is more than minor because it was associated with the configuration control attribute of the Initiating Events Cornerstone and adversely affected the 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 licensee installed a blind flange, instead of a breathable foreign material exclusion cover on the reactor vessel head vent piping, which resulted in an inadvertent loss of reactor coolant during lowered inventory operations. Using Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, dated May 9, 2014, Attachment 1, Exhibit 2, Initiating Events Screening Questions, the finding was determined to be of very low safety significance (Green) because the finding would not have resulted in a loss of decay heat removal if undetected for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, AND was determined to be self-limiting because level would have only lowered to the point at which it would have vented to the pressurizer and not lowered to the point of challenging decay heat removal function. The inspectors determined that the finding had a cross-cutting aspect in the area of human performance associated with work management. The licensee failed to implement an adequate process to execute work activities such that nuclear safety is the overriding priority. Specifically, contractors were supplied generic work instructions to remove the reactor coolant system head vent rig which resulted in a loss of reactor coolant system inventory [H.5]. (Section 1R20)

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Cornerstone: Mitigating Systems

Green.

The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, for failure to establish adequate procedures for the control of high-energy line break barriers. Specifically, on July 21, 2016, the inspectors identified that Procedure 0PGP03-ZA-0514, Controlled System or Barrier Impairment, Revision 14, did not have any guidance on the control of barriers used for high-energy line breaks, despite the fact that the auxiliary feedwater pump room watertight doors are credited in the safety analyses for protection against such breaks. After discussing the acceptability of having both doors open simultaneously, the licensee shut the watertight door to auxiliary feedwater pump room for train A, and entered this condition into the licensees corrective action program as Condition Report 2016-9006.

The failure to prescribe procedures for the control of high-energy line break doors was a performance deficiency. This finding was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically,

Procedure 0PGP03-ZA-0514, Controlled System or Barrier Impairment, Revision 14, did not provide adequate procedures for the control of hazard barriers, which called the operability of the train A auxiliary feedwater system into question. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the issue screened as having very low safety significance (Green)because it was a design or qualification deficiency that did not represent a loss of operability or functionality; did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of non-technical specification equipment; and did not screen as potentially risk significant due to seismic, flooding, or severe weather. The NRC determined that this finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance. Specifically, the auxiliary feedwater pump evaluation was performed in 2000; therefore, the performance deficiency occurred outside of the nominal 3-year period for present performance. (Section 4OA2.1)

Green.

The inspectors identified a non-cited violation of 10 CFR 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, for the failure to provide adequate written instructions for performing preventative maintenance to ensure the emergency diesel generator building access flood panels remain capable of performing their safety function.

Specifically, the preventative maintenance work order model number 61046 was not adequate to detect degraded seal conditions, which were revealed during the flooding event on March 17, 2017. This issue was entered into the licensees corrective action program as Condition Report 2017-12897. The licensee assembled a panel of individuals who were familiar with the design, and individuals responsible for the maintenance of these access panels and is still considering options to prevent future leakage.

The failure to provide adequate written instructions for performing preventative maintenance to ensure diesel generator building access flood panels remain capable of performing their safety function was a performance deficiency. Specifically, preventative maintenance work order model number 61046 was not adequate to detect degraded seal conditions, which were revealed during the flooding event on March 17, 2017. The performance deficiency is

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more than minor, and therefore a finding, because it is associated with the protection against external factors attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to identify degrading flood barriers could result in emergency diesel generator inoperability or failure during a design basis flooding event. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) For Findings At-Power, dated July 1, 2012, Exhibit 2, Mitigating System Screening Questions, the finding was determined to of very low safety significance (Green). Specifically, the finding was not a deficiency affecting the design or qualification of a mitigating structure, system, and component; did not represent a loss of system and/or function; did not represent an actual loss of function of at least a single train for greater than its technical specification allowed outage time; and did not represent an actual loss of function of one or more than non-technical specification trains of equipment designated as high-risk significance for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance. Specifically, the emergency diesel generator access panels had not allowed water intrusion due to flooding within the last 3 years and, therefore, the licensee did not have a recent opportunity to understand that the preventative maintenance work order instructions were inadequate. (Section 4OA2.2)

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PLANT STATUS

Unit 1 began the inspection period defueled in Refueling Outage 1RE20. On April 29, 2017, the main generator breaker was closed ending 1RE20. Unit 1 achieved 100 percent power on May 2, 2017, and remained at 100 percent for the remainder of the inspection period.

Unit 2 began the inspection period at 100 percent power. On April 28, 2017, power was reduced to 77 percent due to unexpected condenser fouling issues. Following condenser cleaning, Unit 2 returned to 100 percent power on April 29, 2017, and remained there for the remainder of the inspection period.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Summer Readiness for Offsite and Alternate AC Power Systems

a. Inspection Scope

On June 27, 2017, the inspectors completed an inspection of the stations off-site and alternate-ac power systems. The inspectors inspected the material condition of these systems, including transformers and other switchyard equipment to verify that plant features and procedures were appropriate for operation and continued availability of off-site and alternate-ac power systems. The inspectors reviewed outstanding work orders and open condition reports for these systems. The inspectors walked down the switchyard to observe the material condition of equipment providing off-site power sources.

The inspectors verified that the licensees procedures included appropriate measures to monitor and maintain availability and reliability of the off-site and alternate-ac power systems.

These activities constituted one sample of summer readiness of off-site and alternate-ac power systems, as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

.2 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

On June 30, 2017, the inspectors completed an inspection of the stations readiness for seasonal extreme weather conditions. The inspectors reviewed the licensees adverse weather procedures for hurricane season and evaluated the licensees implementation of these procedures. The inspectors verified that prior to hurricane season, the licensee

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had corrected weather-related equipment deficiencies identified during the previous hurricane season.

The inspectors selected two risk-significant systems that were required to be protected from hurricane season:

• Unit 1 and Unit 2 345 kV switchyard

• Unit 1 and Unit 2 essential cooling water pond The inspectors reviewed the licensees procedures and design information to ensure the systems would remain functional when challenged by adverse weather. The inspectors verified that operator actions described in the licensees procedures were adequate to maintain readiness of these systems. The inspectors walked down portions of these systems to verify the physical condition to ensure readiness for the hurricane season.

These activities constituted one sample of readiness for seasonal adverse weather, as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Partial Walk-Down

a. Inspection Scope

The inspectors performed partial system walk-downs of the following risk-significant systems:

• May 15, 2017, Unit 2, train B high head safety injection while train C high head safety injection was out of service for planned maintenance

• May 30, 2017, Unit 1, train B spent fuel pool cooling system while train A spent fuel pool cooling system was out of service for planned maintenance

• June 1, 2017, Unit 2, train A essential cooling water while train B essential cooling water was out of service for planned maintenance

• June 13, 2017, Unit 2, train C emergency diesel generator during elevated risk for emergent maintenance on train A electrical auxiliary building ventilation

• June 19, 2017, Unit 1, train C component cooling water while train A component cooling water was out of service for planned maintenance The inspectors reviewed the licensees procedures and system design information to determine the correct lineup for the systems. They visually verified that critical portions of the systems and trains were correctly aligned for the existing plant configuration.

These activities constituted five partial system walk-down samples, as defined in Inspection Procedure 71111.04.

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b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Inspection

a. Inspection Scope

The inspectors evaluated the licensees fire protection program for operational status and material condition. The inspectors focused their inspection on five plant areas important to safety:

• May 9, 2017, Unit 2, mechanical auxiliary building volume control tank and valve room, Fire Area 03, Fire Zone Z119

• May 11, 2017, Unit 2, train B mechanical auxiliary building component cooling water pump and chiller room, Fire Area 29, Fire Zone Z140

• May 31, 2017, Unit 2, mechanical auxiliary building, fuel handling building, room 101, Fire Area 35, Fire Zone Z310

• June 20, 2017, Unit 1, fuel handling building train A emergency core cooling pump room, Fire Area 35, Fire Zone Z307

• June 30, 2017, Unit 1, fuel handling building, spent fuel pool cooling pump rooms, Fire Area 35, Fire Zones Z319, and Z320 For each area, the inspectors evaluated the fire plan against defined hazards and defense-in-depth features in the licensees fire protection program. The inspectors evaluated control of transient combustibles and ignition sources, fire detection and suppression systems, manual firefighting equipment and capability, passive fire protection features, and compensatory measures for degraded conditions.

These activities constituted five quarterly inspection samples, as defined in Inspection Procedure 71111.05.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

The activities described in subsections 1 through 4 below constitute completion of one inservice inspection sample, as defined in Inspection Procedure 71111.08.

.1 Non-destructive Examination Activities and Welding Activities

a. Inspection Scope

The inspectors directly observed the following nondestructive examinations:

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SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Main Steam Snubber No. MS-1002-HL5006 Visual (VT-1)

Reactor Coolant Elbow-to-Pipe (3-RC-1015-NSS 3)

Ultrasonic Reactor Coolant Reducer-to-Elbow (3-RC-1015-NSS 9) Ultrasonic Reactor Coolant Pipe-to-Reducer (6-RC-1015-NSS 13)

Ultrasonic Reactor Coolant Elbow-to-Elbow (3-RC-1015-NSS 10)

Ultrasonic Reactor Coolant Pipe-to-Elbow (3-RC-1015-NSS 14)

Ultrasonic Reactor Coolant Elbow-to-Pipe (3-RC-1015-NSS 15)

Ultrasonic Reactor Coolant Elbow-to-Pipe (3-RC-1015-NSS 19)

Ultrasonic

During the review and observation of each examination, the inspectors observed whether activities were performed in accordance with the ASME Code requirements and applicable procedures. The inspectors also reviewed the qualifications of all nondestructive examination technicians performing the inspections to determine whether they were current.

The inspectors directly observed a portion of the following welding activities:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Main Steam Pipe-to-Valve (Weld No. HFW0150)

Shielded Metal Arc Welding The inspectors reviewed records for the following welding activities:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant Seal Cap-to-Valve Body (Weld No. C99)

Gas Tungsten Arc Welding The inspectors reviewed whether the welding procedure specifications and the welders had been properly qualified in accordance with ASME Code,Section IX requirements.

The inspectors also determined whether essential variables were identified, recorded in the procedure qualification record, and formed the bases for qualification of the welding procedure specifications.

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a. Findings

No findings were identified.

.2 Vessel Upper Head Penetration Inspection Activities

No vessel upper head penetration inspection activities were scheduled for the South Texas Project, Unit 1 Refueling Outage 1RE20.

.3 Boric Acid Corrosion Control Inspection Activities

a. Inspection Scope

The inspectors reviewed the licensees implementation of its boric acid corrosion control program for monitoring degradation of those systems that could be adversely affected by boric acid corrosion. The inspectors reviewed the documentation associated with the licensees boric acid corrosion control walk-down as specified in Procedure 0PGP03-ZE-0133, Boric Acid Corrosion Control Program, Revision 10. The inspectors reviewed whether the visual inspections emphasized locations where boric acid leaks could cause degradation of safety significant components, and whether engineering evaluations used corrosion rates applicable to the affected components and properly assessed the effects of corrosion induced wastage on structural or pressure boundary integrity. The inspectors observed whether corrective actions taken were consistent with the ASME Code and 10 CFR Part 50, Appendix B requirements.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

No steam generator tube inspection activities were scheduled for the South Texas Project, Unit 1 Outage 1RE20.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed 17 condition reports which dealt with inservice inspection activities and found the corrective actions for inservice inspection issues were appropriate. From this review, the inspectors concluded that the licensee has an appropriate threshold for entering inservice inspection issues into the corrective action program and has procedures that direct a root cause evaluation when necessary. The licensee also has an effective program for applying industry inservice inspection operating experience. Specific documents reviewed during this inspection are listed in the attachment.

b. Findings

No findings were identified.

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1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Review of Licensed Operator Requalification

a. Inspection Scope

On June 12, 2017, the inspectors observed simulator training for an operating crew. The inspectors assessed the performance of the operators and the evaluators critique of their performance.

These activities constituted completion of one quarterly licensed operator requalification program sample, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.2 Review of Licensed Operator Performance

a. Inspection Scope

On June 15 and June 20, 2017, the inspectors observed the performance of on-shift licensed operators in the Unit 2 main control room. On June 15, 2017, the plant was in a period of heightened risk due to emergent failure of the train A electrical auxiliary building heating, ventilation, and air conditioning, which placed the unit in a red risk configuration (greater than 1.0E-6 incremental core damage probability). On June 20, 2017, the plant was in a period of heightened risk due to an emergent failure of automatic control of steam generator C main feedwater regulating valve.

In addition, the inspectors assessed the operators adherence to plant procedures, including the conduct of operations and other operations department policies.

These activities constituted completion of one quarterly licensed operator performance sample, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Routine Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed one instance of degraded performance or condition of safety-significant structures, systems, and components (SSCs):

• June 29, 2017, Unit 1, steam generator blowdown containment isolation valve that failed to shut following a main feedwater and main steam isolation.

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The inspectors reviewed the extent of condition of possible common cause SSC failures and evaluated the adequacy of the licensees corrective actions. The inspectors reviewed the licensees work practices to evaluate whether these may have played a role in the degradation of the SSCs. The inspectors assessed the licensees characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance Rule), and verified that the licensee was appropriately tracking degraded performance and conditions in accordance with the Maintenance Rule.

These activities constituted completion of one maintenance effectiveness sample, as defined in Inspection Procedure 71111.12.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors observed portions of two emergent work activities that had the potential to affect the functional capability of mitigating systems:

• Week of May 15, 2017, Unit 1, failure of train A sequencer while train D steam generator power-operated relief valve and the train D auxiliary feedwater pump were out of service

• Week of June 12, 2017, Unit 2, failure of train A electrical auxiliary building heating, ventilation, and air conditioning main area supply fan motor

The inspectors verified that the licensee appropriately developed and followed a work plan for these activities. The inspectors verified that the licensee took precautions to minimize the impact of the work activities on unaffected SSCs.

These activities constituted completion of two emergent work control inspection samples, as defined in Inspection Procedure 71111.13.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed three operability determinations that the licensee performed for degraded or nonconforming SSCs:

• June 2, 2017, Unit 2, operability determination for auxiliary feedwater cross connect, FV-7516, failing to open

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• June 29, 2017, Unit 1, train B operability determination of auxiliary feedwater due to broken grease supply to room fan 11B motor bearings

• June 30, 2017, Unit 1, reactor coolant system and reactor fuel operability evaluation due to possible foreign material from damaged fuel bundle event during Refueling Outage 1RE20

The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded SSC to be operable, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability of the degraded SSC.

On May 20, 2017, the inspectors reviewed operator actions taken or planned to compensate for degraded or nonconforming conditions for Unit 1. The inspectors verified that the licensee effectively managed these operator workarounds to prevent adverse effects on the function of mitigating systems and to minimize their impact on the operators ability to implement abnormal and emergency operating procedures.

These activities constituted completion of four operability and functionality review samples, as defined in Inspection Procedure 71111.15.

b. Findings

No findings were identified.

1R17 Evaluations of Changes, Tests, and Experiments

a. Inspection Scope

The inspectors reviewed five evaluations performed pursuant to 10 CFR 50.59, to determine whether the evaluations were adequate and that prior NRC approval was obtained as appropriate. The inspectors also reviewed 22 screenings and/or applicability determinations where licensee personnel had determined that a 10 CFR 50.59 evaluation was not necessary. The inspectors reviewed these documents to:

• Verify that evaluations were performed in accordance with 10 CFR 50.59 when changes, tests, or experiments were made

• Verify that the licensee has appropriately concluded that the change, test, or experiment can be accomplished without obtaining a license amendment

• Verify that safety issues related to the changes, tests, or experiments have been resolved

• Verify that the licensees conclusions were correct and consistent with 10 CFR 50.59 for the changes, tests, or experiments that the licensee determined that evaluations were not required

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The inspectors used, in part, Nuclear Energy Institute (NEI) 96-07, Guidelines for 10 CFR 50.59 Implementation, Revision 1, to determine acceptability of the completed evaluations and screenings. The NEI document was endorsed by the NRC in Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiments, dated November 2000. The list of evaluations, screenings, and/or applicability determinations reviewed by the inspectors is included as an attachment to this report.

This inspection consisted of 27 samples of evaluations, screenings, and/or applicability determinations, as defined in Inspection Procedure 71111.17-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed six post-maintenance testing activities that affected risk-significant SSCs:

• April 25, 2017, Unit 1, train D auxiliary feedwater pump operability test following maintenance to correct governor low oil level

• May 9, 2017, Unit 2, train B essential chilled water pump operability test following planned maintenance

• May 9, 2017, Unit 1, train C control room envelope heating, ventilation, and air conditioning following supply fan motor replacement

• May 15, 2017, Unit 2, train C high head safety injection pump following motor endplay adjustment

• June 9-10, 2017, Unit 1, train C emergency diesel generator testing following push rod replacements

• June 17, 2017, Unit 2, train A electrical auxiliary building heating, ventilation, and air conditioning following motor rewind

The inspectors reviewed licensing-and design-basis documents for the SSCs and the maintenance and post-maintenance test procedures. The inspectors observed the performance of the post-maintenance tests to verify that the licensee performed the tests in accordance with approved procedures, satisfied the established acceptance criteria, and restored the operability of the affected SSCs.

These activities constituted completion of six post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19.

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b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

During the stations Refueling Outage 1RE20, that concluded on April 29, 2017, the inspectors evaluated the licensees outage activities. The inspectors verified that the licensee considered risk in developing and implementing the outage plan, appropriately managed personnel fatigue, and developed mitigation strategies for losses of key safety functions. This verification included the following:

• Verification that the licensee maintained defense-in-depth during outage activities

• Observation and review of fuel handling activities

• Monitoring of heat-up and startup activities

These activities constituted completion of one refueling outage sample, as defined in Inspection Procedure 71111.20.

b. Findings

Introduction.

The inspectors documented a Green, self-revealed, non-cited violation of Technical Specification 6.8.1.a, Regulatory Guide 1.33, Revision 2, February 1978, Appendix A, Section 9.d.(4). Specifically, inadequate written work instructions to remove the reactor vessel head vent rig and install a breathable foreign material exclusion (FME)cover resulted in installing a blind flange and a loss of reactor coolant system (RCS)water while at lowered inventory.

Description.

On March 21, 2017, Unit 1 was in Mode 5 and at lowered RCS inventory in the band of 373 to 379, which is just below the reactor vessel head flange. The RCS time-to-boil was at 16 minutes with an RCS temperature at 110 degrees Fahrenheit.

Following RCS drain down to lowered inventory, contractors were instructed to remove the reactor vessel head vent rig and install a breathable FME cover on the head vent piping. The contractors were given instruction0 for the activity in a high-level discussion as a part of the beginning of shift brief for the refueling group. The assigned contractors reviewed the work instructions and went into containment to perform the activity. At 10:29 a.m., the refueling logbook noted that the head vent rig removal was complete.

In the control room, operators were monitoring RCS level via the RCS sight glass and controlling inventory through chemical volume and control system letdown and charging.

In this condition, there was only one RCS level indication and the control room was in a heightened level of awareness for work activities that could affect RCS inventory. There were also no alarms for leakage or inventory control issues. Throughout the morning and into the afternoon, the reactor operators noted the volume control tank (VCT) level increasing, but attributed the increase to gas coming out of solution in the steam generator U-tubes which displaced water. Over several hours, operators lowered VCT level 10 percent by diverting RCS inventory to the recycle hold-up tank and were

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considering a second diversion because VCT level had again increased by 10 percent.

The VCT was an available indication that was readily detectable by the operations staff.

At 3:15 p.m., the refueling mechanical maintenance supervisor recognized, through paperwork review and discussion with the contractors, that a blind flange had been installed on the reactor vessel vent piping instead of the breathable FME cover. The supervisor instructed the contractors to remove the blind flange and install the breathable FME cover. The nuclear steam supply system manager informed the control room that the reactor head vent path was inadvertently isolated and was being removed.

Operations decided to raise the indicated RCS level to the top of the operating band (379). At 4:50 p.m., the contractors removed the blind flange and installed the breathable FME cover. Upon removal of the blind flange, operators observed a 3.5 inch drop in RCS level as indicated on the RCS sight glass.

The licensee conducted an investigation into the event. The blind flange installed on the reactor vessel head vent piping resulted in localized pressurization in the reactor head due to non-condensable gases coming out of solution with no vent path. As the gas was collected in the head, it displaced RCS inventory, which resulted in the VCT level increase. The estimated number of gallons that were removed from the RCS, over the 6-hour duration that the blind flange was installed, was approximately 3500 gallons. The licensee determined that the contractors followed the written work instructions per preventative maintenance work order model 64344 to remove the reactor vessel head vent rig and installed the blind flange. The written work instructions provided in preventative maintenance work order model 64344 did not describe the installation of the breathable FME cover, which was the goal of the work activity, and therefore were not adequate.

With the reactor in a lowered inventory condition, the licensee was strictly controlling the number of distractions to the control room, ensuring that there were no work activities that might challenge RCS cooling and inventory control, and communicating activities that might challenge the RCS cooling and inventory to the control room. The inspectors interviewed the operator who was responsible for the primary plant, and determined that the operators were not aware that the reactor vessel head vent rig was in the process of being removed. The operators should have been aware of the activity and possible plant response to this work. This information should have led the operators to question their indications and diagnose the inventory control event in a more timely manner.

The licensee performed an evaluation and determined that it would have taken several days in this condition for reactor vessel level to reach mid-loop condition. This condition would be self-limiting because any pressure in the reactor vessel itself would vent out to the pressurizer if the reactor vessel level would have reached the top of the RCS hot leg.

The inspectors have reviewed the licensees evaluation and did not identify any concerns during the review.

Analysis.

The failure of the licensee to provide appropriate written work instructions to install a breathable FME cover following the removal of the reactor vessel head vent rig was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it was associated with the configuration control attribute of the Initiating Events Cornerstone and adversely affected the 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 licensee

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installed a blind flange, instead of a breathable FME cover on the reactor vessel head vent piping, which resulted in an inadvertent loss of reactor coolant during lowered inventory operations. Using Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, dated May 9, 2014, Attachment 1, Exhibit 2, Initiating Events Screening Questions, the finding was determined to be of very low safety significance (Green) because the finding would not have resulted in a loss of decay heat removal if undetected for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, AND was determined to be self-limiting because level would have only lowered to the point at which it would have vented to pressurizer and not lowered to the point of challenging decay heat removal function. The inspectors determined that the finding had a cross-cutting aspect in the area of human performance associated with work management. The licensee failed to implement an adequate process to execute work activities such that nuclear safety is the overriding priority. Specifically, contractors were supplied generic work instructions to remove the RCS head vent rig which resulted in a loss of RCS inventory [H.5].

Enforcement.

Technical Specification 6.8.1.a requires, in part, that procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2. Section 9.d(4) of Regulatory Guide 1.33, Revision 2, requires that Procedures that could be categorized as either maintenance or operating procedure should be developed for draining and refilling the reactor vessel. Contrary to the above, on March 21, 2017, the licensee did not establish and implement adequate procedures for draining and refilling the reactor vessel. Specifically, written work order instructions in preventative maintenance work order model 64344 errantly instructed workers to remove the reactor vessel head vent rig and install a blind flange, which resulted in a 3500 gallon loss of RCS inventory. The finding was entered into the licensees corrective action program as Condition Report 2017-13155. Because this finding is of very low safety significance and has been entered into the licensees corrective action program, this violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy:

NCV 05000498/2017002-01, Failure to Establish Procedures to Remove Reactor Vessel Head Vent Rig Results In Loss of Reactor Coolant System Inventory.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed six risk-significant surveillance tests and reviewed test results to verify that these tests adequately demonstrated that the SSCs were capable of performing their safety functions:

In-service tests:

• May 3, 2017, Unit 1, train B essential chilled water pump 11B

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Containment isolation valve surveillance tests:

• April 15, 2017, Unit 1, local leak rate test of M-89 fuel transfer tube containment penetration

Other surveillance tests:

• April 11, 2017, Unit 1, train A standby diesel generator loss-of-offsite power surveillance test

• April 26, 2017, Unit 1, low power physics testing

• May 10, 2017, Unit 2, train B emergency diesel generator surveillance test

• June 10, 2017, Unit 2, control rod operability testing

The inspectors verified that these tests met technical specification requirements, that the licensee performed the tests in accordance with their procedures, and that the results of the test satisfied appropriate acceptance criteria. The inspectors verified that the licensee restored the operability of the affected SSCs following testing.

These activities constituted completion of six surveillance testing inspection samples, as defined in Inspection Procedure 71111.22.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors observed an emergency preparedness drill on June 21, 2017, to verify the adequacy and capability of the licensees assessment of drill performance. The inspectors reviewed the drill scenario, observed the drill from the simulator, technical support center, the emergency operations facility, and attended the post-drill critique.

The inspectors verified that the licensees emergency classifications, off-site notifications, and protective action recommendations were appropriate and timely. The inspectors verified that any emergency preparedness weaknesses were appropriately identified by the licensee in the post-drill critique and entered into the corrective action program for resolution.

These activities constituted completion of one emergency preparedness drill observation sample, as defined in Inspection Procedure 71114.06.

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b. Findings

No findings were identified.

.2 Training Evolution Observation

a. Inspection Scope

On June 13, 2017, the inspectors observed simulator-based licensed operator requalification training that included implementation of the licensees emergency plan.

The inspectors verified that the licensees emergency classifications, off-site notifications, and protective action recommendations were appropriate and timely. The inspectors verified that any emergency preparedness weaknesses were appropriately identified by the evaluators and entered into the corrective action program for resolution.

These activities constituted completion of one training observation sample, as defined in Inspection Procedure 71114.06.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Security

4OA1 Performance Indicator Verification

.1 Safety System Functional Failures (MS05)

a. Inspection Scope

For the period of May 2016 through May 2017, the inspectors reviewed licensee event reports, maintenance rule evaluations, and other records that could indicate whether safety system functional failures had occurred. The inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, and NUREG-1022, Event Reporting Guidelines:

10 CFR 50.72 and 50.73, Revision 3, to determine the accuracy of the data reported.

These activities constituted verification of the safety system functional failures performance indicator for Unit 2 only, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

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.2 Reactor Coolant System Specific Activity (BI01)

a. Inspection Scope

The inspectors reviewed the licensees reactor coolant system chemistry sample analyses for the period of May 2016 through May 2017 to verify the accuracy and completeness of the reported data. The inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted verification of the reactor coolant system specific activity performance indicator for Unit 2 only, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.3 Reactor Coolant System Identified Leakage (BI02)

a. Inspection Scope

The inspectors reviewed the licensees records of reactor coolant system identified leakage for the period of May 2016 through May 2017 to verify the accuracy and completeness of the reported data. The inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted verification of the reactor coolant system leakage performance indicator for Unit 2 only, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

a. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review

a. Inspection Scope

Throughout the inspection period, the inspectors performed daily reviews of items entered into the licensees corrective action program and periodically attended the licensees condition report screening meetings. The inspectors verified that licensee personnel were identifying problems at an appropriate threshold and entering these problems into the corrective action program for resolution. The inspectors verified that the licensee developed and implemented corrective actions commensurate with the significance of the problems identified. The inspectors also reviewed the licensees

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problem identification and resolution activities during the performance of the other inspection activities documented in this report.

b. Findings

No findings were identified.

.2 Semiannual Trend Review

a. Inspection Scope

The inspectors reviewed the licensees corrective action program, performance indicators, system health reports, and other documentation to identify trends that might indicate the existence of a more significant safety issue. The inspectors verified that the licensee was taking corrective actions to address identified adverse trends.

The inspectors reviewed a series of secondary side plant issues from January through June 2017 that impacted plant operations, as follows:

• Unit 1 Circulating water pump shaft shear

• Unit 1 open loop leak and pipe break (resulted in rapid plant shutdown)

• Unit 1 open loop pump #11 high motor vibration (which eventually required pump swap and challenged the open loop pipe leak)

• Unit 2 Unexpected condenser fouling (clams) that resulted in down powering the plant greater than 20 percent)

• Unexpected grass intrusion in the essential cooling water pond that challenged safety-related cooling from ultimate heat sink on both units

• Damaged and degraded circulating water components (traveling screens and level indicators) that were in need of emergent repair and impacted full power operation for both units These activities constituted completion of one semiannual trend review sample, as defined in Inspection Procedure 71152.

b.

Observations and Assessments The inspectors review of the trend identified above produced the following observations and comments:

• The licensee is aware of the trend of secondary side issues and events that have threatened stable plant operations for both Units. The licensee has initiated Condition Report 2017-15461, to evaluate the apparent trend, as well as Condition Report 2017-17879, to document a mid-cycle self-assessment performance gap that operations and engineering have failed to perform aggregate reviews to identify changes in potential vulnerabilities, which have resulted in down powers, train unavailability, and chemistry action levels. The

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licensee developed corrective actions and preventative maintenance activities to address the equipment reliability issues. The actions were prioritized and binned into two areas: needing to be performed prior to summer and those actions for long term. The inspectors determined that the licensee is aware of the trend and is developing corrective actions to resolve. The inspectors will continue to evaluate the effectiveness of the corrective actions.

c. Findings

No findings were identified.

.3 Annual Follow-up of Selected Issues

a. Inspection Scope

The inspectors selected two issues for an in-depth follow-up:

• On July 21, 2016, inspectors identified that operations and maintenance personnel opened a high-energy line barrier protecting train A auxiliary feedwater during maintenance and testing of the train D turbine driven auxiliary feedwater pump, and questioned the operability of train A auxiliary feedwater system.

The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews and compensatory actions. The inspectors verified that the licensee appropriately prioritized the corrective actions and corrective actions planned to be taken appeared to be adequate to correct the condition.

• On March 17, 2017, the Unit 1 emergency diesel generator access flood panels failed to prevent water intrusion into all three diesel bays following a break of the Unit 1 open loop piping.

The inspectors assessed the licensees problem identification threshold and extent of condition reviews. The inspectors verified that the licensee appropriately prioritized the planned corrective actions and that these actions appeared to be adequate to correct the condition.

These activities constituted completion of two annual follow-up samples, as defined in Inspection Procedure 71152.

.1 Failure to Establish Procedures for Control of High-Energy Line Break (HELB) Barriers

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for failure to establish adequate procedures for the control of HELB barriers.

Description.

On July 21, 2016, the NRC inspectors observed maintenance activities that included an in-service pump test on the Unit 2, train D steam-driven auxiliary feedwater pump. Each of the four auxiliary feedwater pumps (trains A, B, C, and D) are housed in

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their own respective rooms that are secured by watertight doors that are credited for HELB event mitigation. The inspectors noted that the maintenance was limited to the train D pump, however, the station personnel propped open the train A door because the temperature in the train A room was much lower. The train D room houses the steam-driven auxiliary feedwater pump, which operates at a much higher temperature than the motor-driven auxiliary feedwater pumps in train A, B, and C rooms. It was discovered that it was common practice to prop open the adjacent door during the summer months or when a cooler environment was desired. The NRC inspectors questioned whether this configuration was accounted for in a 10 CFR 50.65 risk evaluation, or if it affected the operability of the train A auxiliary feedwater pump that would require technical specification actions to be taken.

The licensee presented the inspectors with an engineering evaluation that considered this condition, CREE-00-9281-1, performed in year 2000. The purpose of CREE-00-9281-1 was to determine the reportability requirements of 10 CFR 50.73, because two of the doors in the auxiliary feedwater pump rooms had been found open.

CREE-00-9281-1 stated, in part, that because of the 2 watertight doors being open, the effect of the main steam line break will be seen in both train A, train D, and the common corridor area. Therefore, there is the potential for losing both the A and D trains.

Additionally, it stated that, for a feedwater line break... part of the water would blow down to the auxiliary feedwater pump room[which] would cause both auxiliary feedwater pump rooms to be flooded and render 2 auxiliary feedwater pumps inoperable due to the effects of feedwater line break. The evaluation concluded that with two auxiliary feedwater pump doors open, and an active single failure, the one remaining auxiliary feedwater pump would meet the system safety function. As a result, in July 2016, engineering and operations staff believed that the evaluation, CREE-00-9281-1, allowed more than one door open without affecting operability or requiring technical specification actions. However, the purpose of the previous evaluation was to determination if an event report was required for loss of safety function of the auxiliary feedwater pumps, not to evaluate if the operability of the auxiliary feedwater pumps was affected or increased risk management requirements were required due to this condition.

The licensees procedure for the control of plant barriers against hazards, such as fire protection, flooding, and security is 0PGP03-ZA-0514, Controlled System or Barrier Impairment, Revision 14. This procedure details steps to ensure the control room shift manager is notified of all unanticipated impairments and how fire protection impairments, flooding protection impairments, and security impairments are controlled. However, the procedure does not have any guidance on the control of barriers used for HELB, despite the fact that the watertight doors are credited in the safety analyses for protection against such breaks.

The NRC issued Regulatory Information Summary (RIS) 2001-09, Control of Hazard Barriers, to inform addressees that recent changes to the Maintenance Rule 10 CFR 50.65, Requirements for monitoring the effectiveness of maintenance at nuclear power plants, have a bearing on plant hazard barriers. RIS 2001-09 states, in part, that prior to removing a hazard barrier for maintenance purposes (either to facilitate plant maintenance or to perform maintenance on the barrier), the risk associated with the maintenance activity must be controlled and managed in accordance with paragraph 50.65(a)(4) of the maintenance rule. The resultant risk management actions may impose time limits for barrier removal. In addition, other considerations, such as the

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administrative provisions for controlling fire barriers and the plant technical specifications (TS) may place limitations on continued reactor operation with a hazard barrier removed.

For example, an auxiliary feedwater (AFW) pump that is credited with mitigating a HELB event would be rendered inoperable if a barrier that is credited with protecting the AFW pump from the effects of the postulated HELB event is removed to allow maintenance to be performed in the AFW pump room. The licensee can maintain or restore operability of the AFW system by implementing compensatory measures to provide equivalent protection or by removing the hazard (i.e., isolating and depressurizing high-energy piping sections that pose the threat).

On July 21, 2016, the licensee simultaneously opened auxiliary feedwater doors for train A and train D and failed to evaluate the effects of removing the hazard barrier in accordance with the Maintenance Rule. In addition, the licensee failed to evaluate the operability of the train A auxiliary feedwater system with the door open that provided protection from HELB. Once the inspectors raised the concern, the control room immediately declared both auxiliary feedwater trains inoperable and took action to closed the train A auxiliary feedwater room door to regain operability. Condition Report 2016-9006 was written to document the issue. The licensee took corrective action to modify Procedure 0PGP03-ZA-0514, Controlled System or Barrier Impairment, Revision 16, to prohibit two auxiliary feedwater pump room doors from being open at the same time.

Analysis.

The failure to prescribe procedures for the control of HELB doors was a performance deficiency. This finding was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, Procedure 0PGP03-ZA-0514, Controlled System or Barrier Impairment, Revision 14, did not provide adequate procedures for the control of hazard barriers, which called the operability of the train A auxiliary feedwater system into question. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the issue screened as having very low safety significance (Green) because it was a design or qualification deficiency that did not represent a loss of operability or functionality; did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of non-technical specification equipment; and did not screen as potentially risk significant due to seismic, flooding, or severe weather. The NRC determined that this finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance. Specifically, the auxiliary feedwater pump evaluation was performed in 2000; therefore, the performance deficiency occurred outside of the nominal 3-year period for present performance.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by procedures of a type appropriate to the circumstance. Contrary to the above, prior to January 24, 2017, the procedure for controlling barriers to internal and external hazards, an activity affecting quality, was not appropriate to the circumstance. Specifically, Procedure 0PGP03-ZA-0514, Controlled System or Barrier Impairment, Revision 14, did not state that the doors for each of the respective auxiliary feedwater pumps

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provide the safety-related functions for HELB mitigation and were required to either be latched shut or have compensatory actions in place in the event they are open.

This finding was entered into the licensees corrective action program as Condition Report 2016-9006. Because this finding was of very low safety significance and has been entered into the licensees corrective action program, this violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy:

NCV 05000498/2017002-02; 05000499/2017002-02, Failure to Establish Procedures for Control of High-Energy Line Break Barriers.

.2 Failure To Establish Adequate Procedures To Ensure Emergency Diesel Generator

Access Flood Panels Would Meet Their Safety Function

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to provide adequate written instructions for performing preventative maintenance to ensure the emergency diesel generator (EDG) building access flood panels remain capable of performing their safety function. Specifically, the preventative maintenance work order model number 61046 was not adequate to detect degraded seal conditions, which were revealed during the flooding event on March 17, 2017.

Description.

On March 17, 2017, the Unit 1 open loop cooling supply pipe ruptured releasing approximately 4.5 million gallons of main cooling reservoir water. The rupture resulted in the rapid shutdown of the reactor and caused localized flooding inside the protected area. The main function of the open loop cooling is to cool heat loads in the turbine building; it is not a safety-related system. Flooding occurred mainly on the south side of the protected area and in several low-lying areas, including EDG access (maintenance) panels. The licensee performed a site wide walk-down and discovered water intrusion into all three EDG equipment bays in Unit 1. The inspectors performed an independent walk-down of the site and identified the same water intrusion conditions.

The licensee entered the condition in the corrective action program as Condition Report 2017-12897. Operations initially declared the EDGs operable because the amount of water that entered the EDG equipment bays would not have affected any equipment that affected operability of the EDGs.

The EDG building contains three trains of emergency electrical power, i.e., three EDGs.

Each EDG can be accessed for maintenance through one of four interlocked concrete flood panels. Each panel is approximately 32,000 pounds, four feet wide, two feet deep and twenty-one feet tall. The seal between the panels and with the EDG building is comprised of a thick neoprene gasket and bolted together with approximately 70 to 90 pounds of torque. Since the neoprene is susceptible to ultraviolet damage from the sun, another sealant is used to cover all sealing areas around all panels to protect the neoprene. The licensee also applies a third type of sealant at the bottom of the panels and up each panel for approximately five feet as an extra measure to protect the sealing areas from the environment due to being in a low-lying area. During the normal 5-year EDG maintenance activity, one access panel is removed to allow easy access of people and equipment while the EDG train is devitalized. Upon restoration, the seal for that one panel is completely replaced and tested. The post-maintenance test consists of building a sandbag dam outside all four panels, flooding the panels to a level of one foot above the bottom seal, and check for leaks after 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The upper part of the seal is tested by spraying water (fire water hose and system are normally used) with a pressure of at least 15 psi. In both tests, the acceptance criteria is that there is no leakage through the

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panels. The inspectors noted that the most recent performance of the post-maintenance test in each EDG was March 2015, November 2014, and June 2014 for trains A, B, and C, respectively, during which all three sets of flooding panels passed the post-maintenance test. Additionally, the inspectors noted that the most recent performance of the visual inspection for each EDG panel was May, June, and August 2015, respectively, during which no discrepancies were noted, despite the fact that the flooding seals were in fact degraded.

The EDG flood panels are designed for a design basis flood resulting from the failure of the main cooling reservoir and, per the UFSAR Section 3.4.1.1, External Flood Protection Measures for Seismic Category I Structures, are watertight and designed for hydrostatic forces due to that event. In this design basis flooding event, the maximum water height on the flood panels would be approximately 18.5 feet. In 2014, the licensee performed a CREE 14-20431-22, to determine the maximum water inleakage to accumulate 4 inches of water and challenge EDG operability. The result was approximately 1.5 gpm. The actual event on March 17, 2017, flooded the panels up to two feet and all three trains of EDGs experienced water intrusion, but did not approach the 1.5 gpm limit for operability. The inspectors determined that conservative assumptions in CREE 14-20431-22, such as an assumption that the maximum flood height was sustained for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, likely resulted in an overly conservative allowable leak rate through the panels. Based on the inspectors review of the engineering evaluation, and the observed leak rate through the panels, the inspectors determined that the current inleakage in a design basis event was unlikely to challenge the operability of the EDGs.

On March 29, 2017, the inspectors met with engineering and licensing to discuss the water intrusion event. The inspectors questioned the licensees determination that all three EDGs remained operable, based in part on engineerings initial input into the operability evaluation in Condition Report 2017-12897. The inspectors noted similar concerns during a 2014 inspection activity, during which some water intrusion caused the licensee to declare train A and C EDGs to be operable but degraded as documented in Condition Report 2014-20431. On April 3, 2017, operations declared the EDGs operable but degraded. The inspectors further asked why the access panels were allowing water intrusion after several years when the panels had passed the visual inspections and post-maintenance tests and no maintenance had been performed in the interim. The licensee took the inspector questions for further research.

On June 29, 2017, the licensee began to evaluate methods to prevent water intrusion through the access panels. The licensee assembled a panel of individuals who were familiar with the design and individuals responsible for the maintenance of these access panels, and is still considering options to prevent future leakage.

Analysis.

The failure to provide adequate written instructions for performing preventative maintenance to ensure diesel generator building access flood panels remain capable of performing their safety function was a performance deficiency. Specifically, preventative maintenance work order model number 61046 was not adequate to detect degraded seal conditions, which were revealed during the flooding event on March 17, 2017. The performance deficiency is more than minor, and therefore a finding, because it is associated with the protection against external factors attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent

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undesirable consequences. Specifically, the failure to identify degrading flood barriers could result in EDG inoperability or failure during a design basis flooding event. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) For Findings At-Power, dated July 1, 2012, Exhibit 2, Mitigating System Screening Questions, the finding was determined to of very low safety significance (Green). Specifically, the finding was not a deficiency affecting the design or qualification of a mitigating SSC; did not represent a loss of system and/or function; did not represent an actual loss of function of at least a single train for greater than its technical specification allowed outage time; and did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high-risk significance for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance. Specifically, the EDG access panels had not allowed water intrusion due to flooding within the last 3 years and, therefore, the licensee did not have a recent opportunity to understand that the preventative maintenance work order instructions were inadequate.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by procedures of a type appropriate to the circumstance. Contrary to the above, prior to March 17, 2017, the procedure for inspecting the EDG access panel sealing areas, an activity affecting quality, was not appropriate to the circumstance. Specifically, work instructions in preventative maintenance work order model number 61059 instructed only visual inspections of the EDG access panel sealing areas. On March 17, 2017, following an open loop cooling pipe break, the visual inspection proved to be inadequate to detect access panel sealing issues as water was discovered leaking into all three EDG bays. The issue was entered into the licensees corrective action program as Condition Report 2017-12897. Because the finding is of very low safety significance (Green) and has been entered into the licensees corrective action program, this violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000498/2017002-03; 05000499/2017002-03, Failure To Establish Adequate Procedures To Ensure Emergency Diesel Generator Access Flood Panels Would Meet Their Safety Function.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On April 3, 2017, regional inspectors presented the inservice inspection results to Mr. G. Powell, Executive Vice President and Chief Nuclear Officer, and other members of the licensee staff.

The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

On June 8, 2017, regional inspectors presented the 10 CFR 50.59 inspection results to Mr. J. Connolly, Site Vice President, and other members of the licensees staff. The licensee acknowledged the results as presented. While some proprietary information was reviewed during this inspection, no proprietary information was included in this report.

On July 6, 2017, resident inspectors presented the inspection results to Mr. G. Powell, Executive Vice President and Chief Nuclear Officer, and other members of the licensee staff.

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The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Aguilera, Manager, Plant Protection/Emergency Response

J. Berrio, Manager, Operations, Production Support & Programs

C. Bowman, Manager, Nuclear Support

W. Brost, Engineer III

A. Capristo, Executive Vice President and Chief Administrative Officer

F. Comeaux, Engineer, Design Engineering

J. Connolly, Site Vice President

R. Dunn Jr., Manager, Nuclear Fuel and Analysis

B. Eller, Manager Communications & External Affairs

R. Engen, Manager, Design Engineering

S. Flaherty, Manager Staff Support & Owner Liaison

M. Foster, Supervisor, Operations Support

T. Frawley, Manager, Corporate Projects

W. Fulton, Spec Staff Engineer, Licensing

C. Gann, Manager, Employee Concerns Program

R. Gibbs, Manager, Operations Division, Unit Operations

R. Gonzales, Senior Licensing Engineer

J. Heil, Engineer Consult

G. Hildebrandt, Manager, Training

Q. Huynh, Engineer, Design Engineering

G. Janak, Operations Training Manager

B. Jefferson, Director, Operations

M. Kistler, Senior Spec Engineer, Licensing

D. Koehl, President and CEO

B. Lane, Manager, Operations Division, Integrated Work Management & Outage

E. Lantz, Engineer III

J. Lovejoy, Manager, I&C Maintenance

E. Matejceck, Manager, Mechanical Maintenance

R. McNeil, Manager, Maintenance Engineering

J. Mertink, Manager, Nuclear Oversight

B. Migl, Supervisor Testing & Programs

J. Milliff, Manager, Security

M. Murray, Manager, Regulatory Affairs

R. Niemann, ANII

M. Page, General Manager, Engineering

C. Pence, Manager, Chemistry

L. Peter, General Manager, Projects

G. Powell, Executive Vice President and Chief Nuclear Officer

K. Regis, Engineer, Design Engineering

D. Rencurrel, Senior Vice President, Operations

R. Richardson, Engineer Spec. Consult

S. Rosales, Engineer, Design Engineering

M. Ruvalcaba, Manager, Strategic Projects

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R. Savage, Engineer, Licensing Consult Specialist

R. Scarborough, Manager, Operations Training Mentor

M. Schaefer, Plant General Manager

G. Schinzel, Supervisor, Design Engineering

W. Schulz, Engineer, Design Engineering

S. Shojaei, Engineer Consult Testing & Programs

L. Spiess, Supervisor Testing & Programs Engineering

R. Stastny, Maintenance Manager

L. Sterling, Supervisor, Licensing

C. Stone, Manager, Health Physics

D. Tran, Engineer, Design Engineering

J. Von Suskil, Owner Rep - NRG South Texas LP

K. Wallis, Manager, Systems/Testing and Programs Engineering

D. Wiegand, Spec Engineering Quality Consult

C. Younger, Supervisor Testing & Programs Engineering

D. Zink, Supervising Engineering Specialist

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000498/2017002-01 NCV Failure to Establish Procedures to Remove Reactor Vessel Head Vent Rig Results In Loss of Reactor Coolant System Inventory (Section 1R20)

05000498/2017002-02

05000499/2017002-02 NCV Failure to Establish Procedures for Control of High-Energy Line Break Barriers (Section 4OA2.1)

05000498/2017002-03

05000499/2017002-03 NCV Failure To Establish Adequate Procedures To Ensure Emergency Diesel Generator Access Flood Panels Would Meet Their Safety Function (Section 4OA2.2)