Semantic search

On November 12, 2017 at 2119, a Control Room board walkdown discovered that both of the Unit 2 Containment Spray Pump control switches had been left in pull-out, when operators transitioned Unit 2 from Mode 5 to Mode 4. With the control switches in pull-out, the pumps would not automatically start as required. Technical Specification (Tech Specs) 3.0.3 was entered as a result of not complying with Technical Specification 3.6.5, Containment Spray and Cooling systems, which required both trains of Containment Spray to be Operable while in Mode 4. This event is reportable under 10 CFR 50.73(a)(2)(i)(B), Condition Prohibited by Technical Specification and 10 CFR 50.73(a)(2)(v)(D), Event or Condition that Could Have Prevented Fulfillment of a Safety Function.

The root cause determined that Surveillance Procedure SP 2099, Unit 2 Main Steam Isolation Valve Logic Test, was not adequately designed to account for outage schedule variation. Contributing causes included that the Unit 2 Startup to Mode 4 procedure does not contain adequate process barriers such that plant configuration meets Technical Specification requirements for Mode 4 entry. Operations personnel failed to uphold standards for panel walkdown requirements.

Corrective actions include revising SP 2099, Unit 2 Main Steam Isolation Valve Logic Test to include steps to reposition Containment Spray Switches to the "as found" configuration and revise Unit 2 start-up procedure to add additional HOLD to have the Shift Manager perform Control Board Walkdown to verify equipment required in Mode 4 is aligned and Operable.

Develop and implement an operations improvement plan specifically targeted to improve Operator standards in the performance of Control Board Walkdowns.

On August 23. 2017. Watts Bar Nuclear Plant (WBN) identified that procedures 1-E-1 and 2-E-1, Loss of Reactor or Secondary Coolant, contained steps to manually open 1-FCV-67-458 in the event of a Train A or B power failure.

Opening 1-FCV-67-458 would result in the crosstie of Essential Raw Cooling Water (ERCW) Headers 2A and 1B, which would lead to providing flow to equipment not operating due to the loss of a train of power. On October 6. 2017.

it was determined that for certain time periods, if a design basis accident had occurred on Unit 2 with a loss of offsite power concurrent with a train failure and with 1-FCV-67-458 opened, inadequate ERCW flow would have been available to remove decay heat after transfer to cold leg recirculation. This condition only affected operability of ERCW Train A. This is reportable as a condition prohibited by Technical Specification 3.7.8.

The issue associated with this incorrect procedural step to cross-tie the ERCW trains in 1-E-1 and 2-E-1 was addressed as part of actions to resolve an ERCW design and procedure issue documented in Licensee Event Report (LER) 390-2017-009. This report, while related, identifies an issue that was not addressed in the prior LER. The cause was determined to be the incorrect application of a cross tie requirement associated with 10 CFR 50 Appendix R. Corrective action will be to include engineering in the review of procedures affected by complex design changes.

NRC FORM 355 ;:;4-217' APPROVED BY OMB: NO. 3150-0104 EXPIRES: 03/31/2020 comments regarding burden estimate to the Information Services Branch (T-2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. or by e-mail to NEOB-10202. (3150-0104), Office of Management and Budget. Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number. the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

On August 22, 2017 at 2321 hours central daylight time, Grand Gulf Nuclear Station entered Technical Specification (TS) conditions for three Limiting Condition for Operations (LCOs) not met due to Residual Heat Removal 'A' (RHR A) being declared inoperable. Entergy Operations Inc. (Entergy) made the decision to shut down the plant based on the results of troubleshooting performed on the RHR A pump. The A RHR pump TS differential pressure was out of specification (low) and could not be returned to acceptable limits.

Grand Gulf Nuclear Station initiated plant shutdown required by Technical Specifications 3.5.1, 3.6.1.7, and 3.6.2.3 at 1200 hours CDT on August 29, 2017, due to expected restoration of RHR A exceeding the completion time of 7 days prior to restoring Operability. The shutdown was completed and entry into MODE 3 occurred at 2217 hours CDT on August 29, 2017. The cause is under investigation and this LER will be supplemented upon completion of the causal analysis. Corrective Actions included the replacement of the A RHR pump and the successful retesting of the. A RHR pump and restoration of the pump to operable status. This condition is reportable as a completion of a plant shutdown required by the TS.

(4-2017) 366A U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

(See NUREG-1022, R.3 for instruction and guidance for completing this form htio://www.nrcoovireadino-rm/dcc-collectionenureosistafffsr1022;r31 APPROVED BY OMB: NO. 3150-0104 EXPIRES: 3/31/2020 Reported lessons learned are incorporated into the licensing process and fed back to Industry. Send comments regarding burden estimate to the Information Services Branch (T-2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Grand Gulf Nuclear Station, Unit 1 05000 416

3. LER NUMBER

Description On August 22, 2017 at 2321 hours central daylight time (CDT), Grand Gulf Nuclear Station entered Technical Specification (TS) conditions for three Limiting Condition for Operations (LCOs) not met due to Residual Heat Removal (BO) 'A' (RHR A) being declared inoperable.

LCOs not met:

1) TS 3.5.1 for one low pressure ECCS injection/spray subsystem.

2) TS 3.6.1.7 for one RHR containment spray subsystem, and 3) TS 3.6.2.3 for one RHR suppression pool cooling subsystem.

Entergy Operations Inc. (Entergy) made the decision to shut down the plant based on the results of troubleshooting performed on the RHR A pump. Grand Gulf Nuclear Station initiated plant shutdown required by Technical Specifications 3.5.1, 3.6.1.7, and 3.6.2.3 at 1200 hours CDT on August 29, 2017, due to expected restoration of RHR A exceeding the TS completion time of 7 days prior to restoring Operability. The shutdown was completed and entry into MODE 3 occurred at 2217 hours CDT on August 29, 2017.

REPORTABILITY

Entergy completed Event Notification 52936 notifying the Nuclear Regulatory Commission of the commencement of a plant shutdown in accordance with 10CFR50.72(b)(2)(i), due to the anticipated inability to complete the required A RHR Pump repairs prior to exceeding the TS LCO time limits.

The completion of the shutdown reported in Event Notification 52936 is reportable in accordance with 10CFR50.73(a)(2)(i)(A), the completion of any nuclear plant shutdown required by the plant's Technical Specifications. LCOs not met:

1) TS 3.5.1 for one low pressure ECCS (BO) injection/spray subsystem.

2) TS 3.6.1.7 for one RHR containment spray subsystem, and 3) TS 3.6.2.3 for one RHR suppression pool cooling subsystem.

CAUSE

The A RHR pump TS differential pressure was out of specification (low) and could not be returned to acceptable limits prior to exceeding the 7 day limiting condition for operation time.

The A RHR pump was shipped to a vendor for the determination of the cause of the A RHR pump being out of specification limits. This causal analysis is not anticipated to be completed prior to the 60 day report time for this licensee event report (LER). This LER will be supplemented upon completion of the causal analysis.

CORRECTIVE ACTIONS

Replacement of the A RHR pump.

Successful retesting of the A RHR pump and restoration of the pump to operable status.

NRC FORM

(4-2017) 366A U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

(See NUREG-1022, R.3 for instruction and guidance for competing thIs.form httplAvww.nrc.dovireadino-rm(doc-coRectionsinurectsistaff/sr1022/r3/) APPROVED BY OMB: NO. 3150-0104 EXPIRES: 3/31/2020 Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the Information Services Branch (T-2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information colIection does not display a currently valid OMB con:rol number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

05000 416

SAFETY SIGNIFICANCE

The event posed no threat to the health and safety of the general public or to nuclear safety as safety-systems performed as designed. No Technical Specification safety limits were violated.

Industrial safety was not challenged, and there was no potential or actual radiological release during the event.

PREVIOUS SIMILAR OCCURRENCES

Removal Pump The causes and corrective actions associated with these previous similar events was reviewed and it is believed that the corrective actions could not have prevented the cause of this event.

On April 14, 2017 at 13:57 while attempting to transfer the 2C 4 Kilovolt (kV) vital bus from 24 Station Power Transformer (SPT) to 23 SPT, the 24 SPT infeed breaker opened properly but 23 SPT infeed breaker failed to close.

The 23 SPT infeed breaker failing to close as expected resulted in de-energization of the 2C 4kV vital bus and subsequent start and loading of the 2C Emergency Diesel Generator (EDG) to power the bus.

This report is being made in accordance with 10CFR50.73 (a)(2)(iv)(A), "Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B)," for this event actuation of the 2C EDG.

Notification of this event was provided via ENS report 52681 NS'C, FORM 366 I04-20

• 17:1

On November 21, 2016, as a result of investigating an increased level rise in the Waste Hold-Up. Tank (WHUT), Operators identified a corresponding rise in containment sump level. A containment entry was made to investigate the source of the sump level rise and determined the source was a through wall leak in a Service Water (SW) supply pipe elbow to the 24 Fan Cooler Unit (FCU). The leak constituted a breach of a closed system within containment. Technical Specification (TS) 3.6.1 (Containment) was entered and containment declared inoperable. TS 3.6.6 (Containment Spray and Fan Cooler System) was entered when the 24 FCU was secured and SW to the 24 FCU was isolated. Inspections identified a through wall leak on .a SW supply pipe elbow to one of the 24 FCU water boxes.

The leak is on a 3 inch carbon steel epoxy-lined elbow.

The pipe fitting is in an ASME ISI Code Class 3, nuclear safety related piping system.

The direct cause was failure of the interior coating allowing brackish river water to corrode the carbon steel fitting. The root cause was the maintenance coating procedure requirements for post-coating inspections were inadequate. Key corrective actions included removal of the defective elbow and weld repair, recoating and re-installation.

Maintenance procedure 0-SYS-409-GEN will be revised to mandate detailed inspections and/or testing of surface preparation and applied coatings to ensure proper coverage and adhesion. The event had no effect on public health and safety.

NO:

Indian Point 2 05000-247

On September 13, 2016, and September 14, 2016, during plant walk downs by Engineering and the NRC Senior Resident inspector, pressurized fire protection piping in the Service Water Intake Structure was found to not be shielded against a Moderate Energy Line Break (MELB), resulting in inoperability of one train of Service Water for both units.

During extent of condition walk downs conducted on October 6, 2016, October 10, 2016, November 17, 2016, December 5, 2016, and December 22, 2016, additional piping in the Unit 1 and Unit 2 Safeguards and Auxiliary Buildings was found to not be shielded against a MELB, resulting in inoperability of one train of various.safety related equipment for both units. The most likely cause of this event was the methodology used to conduct the initial MELB walk downs was flawed and allowed some MELB threats to be missed.

Corrective actions include shielding the affected piping, performing a 100 percent walk down of rooms containing MELB piping identified for shielding, and revising the systems interaction program maintenance procedure. I All times in this report are approximate and Central Time unless noted otherwise.

On November 3, 2016, as a result of a containment sump pump alarm, operations obtained from Chemistry a sample which indicated a Service Water (SW) leak due to abnormal chlorides levels.

Technical Specification (TS) 3.6.1 (Containment) was entered and containment declared inoperable.

Inspections identified a through wall leak on the 31 SW Fan Cooler Unit (FCU) from FCU coil 3 which - feeds a SW return line header. TS 3.6.6 (Containment Spay and Fan Cooler System) was entered when the 31 FCU was secured and SW to the 31 FCU was isolated. TS 3.6.1, Condition A was exited after the 31 FCU was secured and SW was isolated to the 31 FCU.

The leak is at a 3 inch butt-welded joint that is ISI Class 3, nuclear safety related.

Leak rate estimate was 0.16 gpm. The direct cause was a leak in a SW pipe due to a through-wall flaw as a result of corrosion.

The root cause is indeterminate. The specific. cause for the pipe joint defect requires the component to be removed and a metallurgical failure analysis performed. Corrective actions included installation of a leak limiting clamp. The clamp is being monitored daily and UT monitoring will be performed every 90 days until the pipe is repaired. The pipe will be replaced in the next refueling outage in 2017.

The affected pipe will be analyzed after removal. The event had no effect on public health and safety.

Indian Point 3 05000-286 APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/31/2018 comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to Note: The Energy Industry Identification System Codes are identified within the brackets ().

DESCRIPTION OF EVENT

On November 3, 2016, while at 100 percent reactor power, operations received a "Vapor Containment (VC) Sump Pump Running," alarm at approximately 00:27 hours, following a VC sump pump out. In accordance with actions of 3-ARP-009, a check of the Unit Log identified that the last sump pump out was on October 30, 2016. Receipt of this alarm was earlier than expected and a possible indicator of a leak. VC radiation monitors R-11 and R-12 (IL), VC Humidity (1,7), and Fan Cooler Unit (FCU) Weir Levels WI were normal. As a result of the early VC Sump Pump Running alarm (FQA), operations requested Chemistry to obtain a sample of the VC pump out line. Results of the sample showed approximately 149 ppm chlorides, indicating a possible Service Water (SW) (BI) leak due to abnormal chloride levels. Operations entered Technical Specification (TS) 3.6.1 (Containment), Condition A (Containment Inoperable) at 03:00 hours, due to the possibility of a loss of containment (NH) integrity. At 3:19 hours, the 31 FCU (FCU) was secured due to suspected SW FCU coil leakage and entered TS 3.6.6 (Containment Spray System and Containment Fan Cooler System), Condition C (One Containment FCU Train Inoperable). At 3:19 hours, a Safety Function Determination was performed which concluded there had been a loss of safety function and VC became inoperable when indications of a possible SW leak was identified for the 31 FCU. At 3:44 hours, TS 3.6.1, Condition A was exited after the 31 FCU was secured and SW was isolated to the 31 FCU. The leak was recorded in Indian Point Energy Center (IPEC) corrective action program (CAP) as CR-IP3-2016-03607. An 8 hour non-emergency event notification (#52344) was made under 10 CFR 50.72(b) (3)(v) for a loss of safety function.

The SW System (SWS) (BI) is designed to supply cooling water from the Hudson River to various heat loads in both the primary and secondary portions of the plant. The design ensures a continuous flow of cooling water to those systems and components necessary for plant safety during normal operation and under abnormal or accident conditions. The SWS consists of two separate, 100% capacity, safety related cooling water headers. Each header is supplied by 3 pumps to include pump strainers, with SWS heat loads designated as either essential or non-essential.

The essential SWS heat loads are those which must be supplied with cooling water immediately in the event of a Loss of Cooling Accident (LOCA) and/or Loss of Offsite Power (LOOP). The essential SWS heat loads can be cooled by any two of the three SW pumps on the essential header. Either of the two SWS headers can be aligned to supply the essential heat loads or the non-essential SWS heat loads.

A VC entry was performed and inspections identified leak indications at the 31 FCU on the 3rd coil feeding the SW return line fPSP1. To confirm the specific leak location, scaffolding was erected and insulation was removed. A through wall leak was identified on the 31 SW Fan Cooler Unit (FCU) at weld B-297, in branch line C from FCU coil 3. This is one of the 3 inch SW return branch lines from the 31 FCU cooling coils which feeds a 10 inch SW return line header 12b upstream of containment penetration Mb. Line 12b is the SW system return piping from the 31 FCU back to the river.

comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to 2016 - 001 - 00 The piping for the 3 inch cooling coil return line is 904L stainless steel (SS) with a nominal pipe wall thickness for Schedule 40 pipe (0.216 inches). Leak rate estimate was 0.16 gpm. The leak is at a 3 inch butt-welded joint between a 904L stainless steel elbow (PSF) and pipe IPSP1 located on approximately the 76 foot elevation in containment. The piping leak is in a moderate energy ASME ISI Code Class 3, nuclear safety related piping system. 904L SS material is susceptible to the development of corrosion pits. Pin hole leaks and weld defects in this piping have previously occurred and have been evaluated. The evaluation concluded the 904L piping does not have a general corrosion problem.. Current analysis for SW pipe failures are postulated to be limited to small through-wall leakage flaws as opposed to guillotine breaks. There is no evidence of leakage at any other location on this weld or elsewhere on the piping adjacent to it.

Code Class 3 piping systems are addressed in ASME Code Case N-513-3. This Code Case provides the requirements for demonstrating structural integrity and therefore operability of a flawed pipe section. Characterization of the weld condition was performed by conducting an ultrasonic examination (UT) on November 4, 2016. The weld was examined circumferentially in a 1/5 inch by '1 inch grid pattern and by using a bulls-eye grid pattern in '4 inch increments. These UT, (Non Destructive Examinations) NDE results were documented in an NDE report. However, due to physical obstructions presented by the FCU enclosure, two circumferential grid rows on the backside of the weld could not be reached. Due to the leak location on the bottom side of the pipe on the side opposite from the FCU enclosure, the bulls-eye grid was not obstructed, and all required readings were taken. As a result of limited access, the UT examination of weld B297 resulted in completion of only approximately 70 percent of the circumference of the weld. The remaining 30 percent (approximately 3 inches) was unable to be inspected due to space constraints between the weld and the adjacent FCU plenum wall. ASME Code Case N-513-3 requires the flaw geometry to be characterized by volumetric inspection methods or by physical measurement. It mandates that the full pipe circumference at the flaw location be inspected to characterize the length and depth of all flaws in the pipe section.

Since a full volumetric examination could not be completed, the Code Case requirements could not be met. An immediate on-line weld repair of the defect was not considered feasible due to restrictions preventing 360 degree access, time required for work prep, and the potential for excessive sump filtration loading. As such, an NRC Relief Request to deviate from the 10CFR50.55a ASME Code requirements, specifically full compliance with ASME CC-N-513-3 was required. Therefore, pursuant to 10CFR50.55a(z)(2) Entergy requested relief by letter NL-16-133 (Request IP3-ISI- RR-10, Alternative to the Full Circumferential Inspection Requirement of Code Case N- 513-3), dated November 7, 2016. The NRC approved the relief request which concluded the inability to obtain full circumference readings does not adversely impact the ability to fully characterize the weld condition vs the code case requirements.

comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to The approval of the relief request allowed Entergy to re-establish SW to the FCU to verify that leakage limits are met using a qualified clamp over the pinhole leak.

The leakage will be inspected daily in accordance with the Code Case requirements.

SW piping to the 31 FCU must be isolated when an allowable leakage is exceeded. The qualified clamp is an engineered clam-shell type clamp comprised on an outer metal jacket and rubber gasket. The clamp is classified as a temporary modification. The clamp will withstand post-accident containment pressure, temperature and environment, is located away from potential missiles and, pipe whip effects, is dedicated for safety-related use, and is rigidly attached to Seismic Category 1 piping. The clamp over the defect will return the system to its original containment integrity configuration and allow the 31 FCU to remain operable.

The defect in the SW return pipe from the 31 FCU was evaluated with respect to TS 5.5.15 (Containment Leak Rate Testing Program), and the Appendix J Leakage program.

TS 5.5.15 requires that the SW in-leakage into containment must be limited to less than 0.36 gpm per FCU when pressurized equal to or greater than 1.1Pa. This limit protects the internal recirculation pumps from flooding during the 12 month period of post-accident recirculation. TS 5.5.15 also implements the leakage rate testing of the containment as required by 10CFR50, Appendix J. The maximum leakage to assure that the post-accident containment leakage remains within allowable limits is 0.023 gpm. This limit is based upon an evaluation to calculate the amount of SW which can leak through this pinhole under normal system operating conditions to ensure that 10CFR50 appendix J containment leakage limits are not exceeded under any mode of operation including accident conditions. The leak does not impinge upon any safety related equipment. As a result, no damage from the leakage is expected to occur.

Based on UT measured readings from the NDE Report, a new calculation was generated (IP-CALC-16-00079 FCU 31 Leak) per the ASME CC-N-513-3 requirements. The minimum required thickness for the elbow containing the weld B297 is 0.073 inches. The minimum measured thickness was 0.117 inches. The maximum allowable axial flaw size is 4.11 inches and the maximum allowable circumferential flaw size is 3.65 inches.

The existing flaw is characterized as approximately 0.50 inches by 0.50 inches, and the uninspected arc length (approximately 3 inches) of the pipe circumference is less than the allowable circumferential flaw length. Therefore, if the entirety of the uninspected portion of the pipe were to be considered a flaw, the pipe would still retain its structural integrity as evaluated in the new calculation. The pinhole flaw is opposite the uninspected portion and the flaw sizes of the two areas are independent and not additive. Based on this information, the pipe is structurally adequate for service consistent with the requirements of ASME Code Case N-513-3. The remaining service life was calculated to be 3.3 years, which is beyond the next scheduled refueling outage in the spring 2017 when a permanent repair will be made.

An extent of condition review determined the Code Case requires five similar and susceptible locations in the SW system to be volumetrically examined. NDEs were performed on November 5, 2016, on five 31 FCU SW pipe welds and recorded in NDE reports. All five weld locations were found to be structurally acceptable and documented in CR-IP3-2016-03607, corrective action (CA-6). The additional inspections confirm the integrity of the SW piping inspected since all UT data measurements were above the 87.5 percent of pipe nominal wall thickness. Also, there was no evidence of additional leakage at any other place in the 31 FCU 3 inch return line or at any other location in the other four FCU return lines. Unit 2 does not apply as it does not have similar 904L SS FCU supply or return lines.

comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to

CAUSE OF EVENT

The direct cause was a SW leak associated with the 31 FCU at weld B297 in branch line C from coil 3 feeding the 10 inch SW return line 12b. The leak was from a through-wall pinhole flaw at a butt-welded joint between a 904L SS elbow and pipe in containment. The likely degradation mechanism leading to the leak was corrosion. The pipe with the flaw resulted in containment out leakage in excess of 10CFR50, Appendix J limits. The root cause is indeterminate. The specific cause for the pipe joint defect requires the component to be removed and a metallurgical failure analysis performed.

CORRECTIVE ACTIONS

The following corrective actions have been or will be performed under the Corrective Action Program (CAP) to address the causes of this event:

• A leak-limiting engineered clam-shell type clamp was applied to the pipe flaw.

• The clamp is being monitored daily by a special operator log for any signs of increased leakage. The maximum allowed leakage rate past the clamp is 0.023 gpm.

• UT monitoring will be performed every 90 days until the pipe is repaired.

• The pipe/elbow will be replaced in the next refueling outage (RO) in the spring 2017.

• The removed pipe/elbow will be inspected and a metallurgical analysis performed by an independent vendor to determine the specific cause.

• A volumetric inspection of a sample of 3 inch 904L SS butt-welds at the 32, 33, 34, and 35 FCUs will be performed in the spring 2017 RO.

• The Generic Letter 89-13 Program will be revised to include a requirement to conduct a definitive number of 904L weld volumetric inspections each pre-outage interval.

• This LER will be updated after engineering review of the metallurgical analysis and revision as necessary of the cause analysis.

EVENT ANALYSIS

The event is reportable under 10 CFR 50.73(a)(2)(v)(C). The licensee shall report any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to (C) Control the release of radioactive material. This condition meets the reporting criteria because TS 3.6.1 Containment Operability was not met.

comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to The pipe flaw leakage was approximately 0.16 gpm which was greater than the calculated 10 CFR 50, Appendix J allowable leak rate of 0.023 gpm. TS 3.6.1 (Containment) requires the containment to be operable in Modes 1-4. TS Surveillance Requirement (SR) 3.6.1.1 requires visual examinations and leakage rate testing in accordance with the containment Leakage Rate Testing Program specified in TS 5.5.15.

SR 3.6.1.1 leakage rate requirements comply with 10 CFR 50, Appendix J, Option B. As SW is required in an accident, the SW to the FCU would not be isolated in DBA and the piping credited as a closed system inside containment for containment integrity.

Consequently, defects discovered within the FCU SW piping may adversely affect containment integrity and the ability to control releases of radioactive material.

The condition also meets the reporting criteria of 10 CFR 50.73(a) (2)(i)(B). The licensee shall report any operation or condition which was prohibited by the plant's TS. During the previous period of operation for an unknown period of time the SW pipe contained a through wall leak that did not meet code requirements. This previously unrecognized condition required entry into TS 3.7.9 and corrective actions implemented to return the pipe to operable. Failure to comply with the TS LCO and perform required actions is a TS prohibited condition.

PAST SIMILAR EVENTS

A review of the past three years of Licensee Event Reports (LERs) for events that involved containment integrity due to flawed piping credited as a closed system inside containment. No applicable LERs were identified. There was one LER, LER-2014- 002 reporting a Technical Specification prohibited condition for a flaw discovered on a SW pipe connected to the Component Cooling Water Heat Exchanger. This LER is not similar as the impacted piping is outside containment and not credited as a closed system for containment integrity.

SAFETY SIGNIFICANCE

This condition had no effect on the health and safety of the public.

There were no actual safety consequences for the event because there were no accidents or events during the degraded condition.

There were no significant potential safety consequences of this event. The leakage from the affected SW pipe was within the capability of the SW system to provide adequate SW flow to SW loads. The degraded piping was on the discharge of the FCU therefore any failure would not prevent the SW cooling function. Current analysis for SW pipe failures are postulated to be limited to small through-wall leakage flaws as SW is defined as a moderate energy fluid system. The SW leak would eventually drain to the containment sump. The containment sumps have pumps with sufficient capacity to remove excessive leakage and instrumentation to alert operators to a degraded condition.

comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to The containment consists of the concrete reactor building, its steel liner, and the penetrations through the structure. The containment building is designed to contain radioactive material that might be released from the reactor following a design basis accident (DBA). The containment building steel liner and its penetrations establish the leakage limiting boundary of the containment. Maintaining the containment operable limits the leakage of fission product radioactivity from the containment to the environment. The DBA analysis assumes that the containment is operable such that, for the DBAs involving release of fission product radioactivity, release to the environment is controlled by the rate of containment leakage.

The containment was designed with an allowable leakage rate of 0.1 percent of containment air weight per day. Containment isolation valves form a part of the containment pressure boundary. Two barriers in series are provided for each penetration so that no single credible failure or malfunction of an active component can result in a loss of isolation or leakage that exceeds limits assumed in the safety analysis. One of these barriers may be a closed system such as the SW piping for the FCUs. The only time containment integrity can be affected is post accident when the FCUs safety function is being performed and SW pressure for the FCU cooling piping and coils fall below peak accident pressure. Mitigation of radiation release by the degraded SW pipe pathway can be by use of radiation monitors R-16A and R-16B which monitor containment fan cooling water for radiation indicative of a leak from the containment atmosphere into the cooling water. If radiation is detected, each FCU heat exchanger can be individually sampled to determine the leaking unit. The SW for the 31 FCU can be isolated to prevent radioactive effluent releases. During the time the FCU SW piping was degraded there was no leakage out of containment.

A risk assessment was performed to determine the overall probability of a core damage event which could cause a loss 'of containment integrity due to a SW to FCU leak assuming it would take 5 days to detect a SW leak to a FCU. The risk result was 7.8E-8 which is considered negligible in terms of both core damage and large early release.

Indian Point 3 05000-286

On May 25, 2016, during evaluation of protection for Technical Specification (TS) equipment from the damaging effects of tornadoes, Braidwood identified non-conforming conditions in the plant design such that specific TS equipment on both units was considered to not be adequately protected from tornado missiles.

On May 25, 2016 at 1415 Operations declared the affected equipment inoperable, implemented Enforcement Guidance Memorandum (EGM) 15-002, "Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance" and the required compensatory measures, and then declared the affected equipment operable but non-conforming.

The cause of this issue was a lack of clarity and changing requirements during the original licensing of the plants which led to inadequate understanding of the original NRC regulatory guidance.

The corrective actions planned are to complete the EGM 60-day comprehensive compensatory measures to demonstrate a discernable change from its pre-discovery actions, to modify the refueling water storage tank hatches to eliminate the tornado missile vulnerability, and to obtain and implement a license amendment for an analytical solution dispositioning tornado generated missile nonconforming conditions.

On March 28, 2016, Operators did not receive the expected results from a relay while performing the 1B train Emergency Core Cooling System (ECCS) Cold Leg Recirculation interlock test. Investigation found the breaker for the residual heat removal pump's loop suction valve incorrectly positioned open. ECCS 1B was declared inoperable. Subsequently, the breaker was closed after it was verified not to have been tripped open.

The last manipulation of this breaker was determined to have been during the coordination for pressure boundary valve testing and standby readiness alignment during the previous refueling cycle (December 2015). A past Operability Evaluation concluded the breaker being open led to a condition prohibited by Technical Specifications, and also a condition that could have prevented the fulfillment of a safety function for Unit 1 ECCS while the 1A emergency diesel generator was inoperable for greater than four hours during this time period. This event was determined to be reportable on April 26, 2016.

The cause of this event is that the test procedure for pressure boundary valve testing did not contain specific procedural guidance for establishing a suction source for the 1B train residual heat removal (RHR) pump. The test procedure required coordination with another procedure to ensure the breaker for the 1B train RHR pump loop suction valve was returned to the closed position. Corrective actions include procedural revisions to these procedures.

On April 2, 2016, Unit 1 entered MODE 4 from MODE 5 without satisfying all of Technical Specification 3.6.6, Containment Spray and Cooling System Limiting Conditions for Operation (LCO) as required by LCO Applicability 3.0.4.

LCO Applicability 3.0.4 does not permit entry into a MODE of applicability when an LCO is not met, unless the associated actions to be entered permit continued operation in the MODE for an unlimited time or after performance of an acceptable risk assessment and the appropriate risk management actions have been established. After entering MODE 4, it was discovered that components were not operable, contrary to LCO 3.0.4.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(i)(B) for operation or condition prohibited by technical specifications.

On February 8, 2016 at approximately 0147 hours, during a surveillance test, control room indications identified that 3B Emergency Containment Cooler (ECC) fan tripped. Troubleshooting found the control power fuse for the fan's power supply breaker was loose in its fuse holder. Investigation revealed that the fuse holder clips had been widened during work activities associated with the installation of the new breaker during the prior Unit 3 refueling and maintenance outage. The most probable cause of the loose fuse was improper insertion.

The installation procedure did not validate fuse holder gap, fuse alignment, and fuse tightness after its last removal and insertion prior to placing the new breaker in service. Inadequate contact during the surveillance test caused the fan trip. The 3B ECC would not have reliably met its safety function mission time and so was determined to be inoperable for approximately 72 days exceeding the 72 hour Technical Specification allowed outage time. In addition, on several occasions during the 72-day period one of the other two ECCs was inoperable concurrently for testing. Corrective actions include: 1) The fuse holder clips were adjusted to provide a tight fit. 2) A review determined additional similar breakers will be inspected for fuse tightness. 3) Future installation and preventive maintenance of similar breakers will check for fuse tightness and correct if necessary. Safety significance is considered low based on a risk assessment showing - Incremental Conditional Core Damage Probability and Incremental Conditional Large Early Release Probability are below the NRC acceptance criteria for minimal risk impact.

On June 22, 2015, at 1406, control room operators were notified by chemistry personnel that the Salem Unit 1 Containment Spray Additive Tank Sodium Hydroxide (NaOH) concentration was less than the minimum concentration by weight as required by Technical Specification (TS). Salem entered TS Action Statement 3.6.2.2.a for low NaOH concentration in the Containment Spray Additive Tank. On June 23, 2015 at 1908, NaOH concentration was returned to its minimum required TS value and the plant exited TS 3.6.2.2.a.

This report is made in accordance with 10 CFR 50. 73(a)(2)(i)(B) for "Any operation or condition which was prohibited by the plant's Technical Specifications ... " and 10 CFR 50.73(a)(2)(v) for "Any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to: ... (C) Control the release of radioactive material; or (D) Mitigate the consequences of an accident.

During design basis reconstitution of the Containment Spray (CS) system, it was discovered that the CS piping inside containment and the containment liner have higher stresses during a postulated Main Steam Line Break (MSLB) or Loss of Coolant Accident (LOCA) than previously analyzed. The preliminary analysis concluded that both CS piping trains inside containment and the containment liner failed to meet the operability requirements of American Society of Mechanical Engineers (ASME) Section III Appendix F without implementing compensatory measures.

A cause analysis was performed and determined that thermal expansion was never considered for the containment riser supports. This is a flaw in the original design of the CS header and rings inside containment.

An operability evaluation was completed in support of plant operation. The operability evaluation conclude that the piping and pipe supports of the CS System as well as the Containment liner are capable of performing their intended safety functions per the operability criteria of ASME BPVC Section III Appendix F following modifications completed under Engineering Change (EC) 65926. Additional evaluation determined that only one pipe support exceeded the code allowable stresses. Final corrective action to fully qualify the CS system will be completed under the stations corrective action program.

On February 11, 2015, with the Davis-Besse Nuclear Power Station operating in Mode 1 at approximately 100 percent full power, during a Nuclear Regulatory Commission (NRC) Component Design Basis Inspection, it was identified the seismic Borated Water Storage Tank (BWST) had been aligned in the past to the non- seismic Spent Fuel Pool (SFP) system for purification. This rendered the BWST inoperable for periods of time longer than allowed per Technical Specification 3.5.4 while the plant was operating in Modes 1 through 4.

Since initial plant design, the BWST had been aligned to the non-seismic SFP system at various times for purification of the BWST contents.

The cause of this event was that regulatory requirements for the separation of seismically qualified and non- qualified systems, structures, and components were not adequately incorporated into design basis documents and the Updated Safety Analysis Report. Administrative controls were established to restrict the alignments that could affect the operability of the BWST. All corrective actions have been completed. The condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition which was prohibited by the plant's Technical Specifications and 10 CFR 50.73(a)(2)(v)(D) as an event or condition that could have prevented the fulfillment of the safety function systems needed to mitigate the consequences of an accident.

On January 8, 2015, the Refueling Water Storage Tank (RWST) level sensing instrumentation lines (LT-920 and LIC-921) were discovered frozen resulting in inoperable low-low level alarms in the Control Room. Entered Technical Specification (TS) 3.5.4 (RWST) Condition C due to both RWST low-low level alarms disabled in the CR.

TS Condition C requires at least one channel of RWST low-low level to be restored to operable in one hour. Actions initiated to return one RWST level channel to operable..

Entered TS 3.5.4 Condition D (Required Action and associated Completion Time not met) D.1 be in. Mode 3 in 6 hours and D.2 be in Mode 4 in 12 hours. Commenced unit shutdown per TS for inoperable RWST level alarms. Repairs and calibrations completed returning the RWST level alarms to operable. TS 3.5.4 exited and power ascension commenced. Loss . of-both LT alarms is a safety system functional failure as the alarms are credited for operator manual switchover for recirculation. Direct cause was failure of the RWST instrument level alarm strip heater to maintain the temperature in the instrument enclosure. - Due to the failure of the heat trace circuit EHT34-1 strip heater to . function combined with a period of severe cold weather resulted in the sensing lines for the RWST.to freeze. The apparent cause was a high resistance electrical connection at the strip heater wire lug due to thermal cycling and age. Corrective actions included _repair of ring lug to strip heater and calibration of level instrumentation.

Maintenance procedure 0-ELC-419-EHT will be revised to include inspection/repair of -. strip heater and ring lug connections within instrument enclosures. An action request (AR) will be initiated for a new model Work Order/PM to inspect strip heater connections and-operation. The event had no significant effect on public health and safety.

At 1933 on May 16, 2014 while in MODE 3, Millstone Power Station Unit 2 (MPS2) exceeded the Limiting Condition for Operation (LCO) of plant Technical Specification (TS) 3.6.2.1 'Containment Spray System' Action a.1 for an inoperable containment spray pump. The 'A' containment spray (CS) pump was declared inoperable at 0018 on May 17, 2014, the date of discovery, following completion of surveillance testing to determine the presence of gas voids.

However, the gas was introduced earlier during the refueling outage and the TS LCO went into effect upon first entry into MODE 3 greater than 1750 psia on May 13, 2014, at 1933. TS 3.6.2.1 Action a.1 requires that the pump be restored to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours and reduce pressurizer pressure to less than 1750 psia within the following 6 hours. MPS2 had been in a MODE where the CS system was required to be OPERABLE for 70.5 hours prior to completion of the testing. The gases were successfully removed by venting and the system was restored to OPERABLE status at 1221 on May 17, 2014.

This condition is being reported as any operation or condition which was prohibited by the plant's technical specifications in accordance with 10 CFR 50.73 (a)(2)(i)(B). The condition was caused by not adequately venting the CS system and delays in communicating the surveillance results, combined with a need to schedule performance of the surveillance testing earlier in a refueling outage. Corrective actions planned will improve scheduling of the testing and will result in more timely communications of the results from completed testing.

On March 7, 2014 at 0929 hours, TS 3.8.1, "AC Sources - Operating" was violated as a result of maintenance activities on DG 1A to replace a connecting rod bearing that was found to have rotated from its normal horizontal position. Catawba had previously requested a NOED on March 6, 2014 in anticipation of exceeding the applicable TS 3.8.1 Required Action Completion Time. The NOED was subsequently granted by the NRC on that same day. This event is therefore reportable under 10 CFR 50.73(a)(2)(i)(B) as an operation or condition which was prohibited by the plant's TS. The affected bearing was proactively replaced, leading to the need for the NOED. The most probable cause of the rotation of the affected bearing is inadequate procedural control of lubricating oil temperature prior to starting an engine following extended periods of maintenance. Corrective actions taken in response to this event include revisions to plant procedures governing DG maintenance and operation. It was subsequently determined that the affected DG 1A bearing would have been able to perform its specified safety function in the as-found condition. During the period that DG 1A was inoperable while the affected bearing was being replaced, DG 1B was operable.

Therefore, this event had no adverse effect upon the health and safety of the public.

At 0027 on May 5, 2013, the safety injection/refueling water (SIRW) tank was declared inoperable in accordance with the operational decision-making issue (ODMI) process. Water leakage from the tank had exceeded the pre-established limit of the ODMI process that directed the tank be declared inoperable.

Leakage from the tank was quantified at approximately ninety gallons per day. Technical Specification (TS) 3.5.4.B requires restoration of an inoperable SIRW tank within one hour. If the tank is not returned to an operable status within one hour, TS 3.5.4.0 requires the plant be placed in Mode 3 within six hours and in Mode 5 within the subsequent thirty-six hours.

Due to the inability to repair the leak within the required one-hour time frame, a plant shutdown was initiated at approximately 0100 hours on May 5, 2013. The plant entered Mode 3 at 0457 hours on May 5, 2013. At 2358 hours on May 5, 2013, the plant entered Mode 5 to execute repairs.

Testing identified an approximate 3/16-inch through-wall crack in a nozzle reinforcing collar to floor plate weld of the tank. Follow-up analysis determined there was significant lack of fusion in the weld that resulted in the failure of the weld and subsequent water leakage. The welder that fabricated the weld did not ensure adequate fusion at the weld root.

The entire SIRW tank floor was replaced with the exception of an annulus ring around the perimeter.

Several initiatives were implemented to preclude potential weld issues during the fabrication of the new tank floor, including welder proficiency training on revised welding techniques and utilization of several types of weld testing methods.

This LER reports the failure of components caused by a defect in ARD66OUR control relays reported by Westinghouse, pursuant to 10 CFR 21, on April 8, 2013. The defect resulted in the failure of five normally energized control relays at PVNGS in two different systems in Unit 1 and two different systems in Unit 2.

The relays were used in normally energized applications which are de-energized to position associated components to support the related safety function. The relays failed to change state when de-energized during testing.

The five failed relays were replaced. The cause was a change in the manufacturing process that occurred in May 2008. The defect was exhibited only on relays that failed in the manner described in the Westinghouse Part 21 report. An extensive testing program was completed to identify and replace ARD66OUR relays installed at PVNGS that exhibited the described failure mode. Westinghouse has modified the ARD66OUR relay plastic molding process to preclude this described failure mode. LER 05000529 / 2009-002-00 reported ARD66OUR relay failures that exhibited a similar failure mode.