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 Report dateSiteEvent description
05000286/LER-2016-00121 December 2017Indian Point

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

05000286/LER-2017-00420 December 2017Indian Point

On November 3, 2017, at 2022 hours, with reactor power at 100 percent, Indian Point Unit 3 experienced an automatic reactor trip on a turbine trip, which was in response to a main generator trip. The main generator trip was initiated by actuation of the Generator Protection System due to a main generator loss of field.

All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The Auxiliary Feedwater System (AFWS) automatically started as expected on steam generator low level to provide feedwater flow to the steam generators. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The direct cause of the loss of main generator field was a failed Thyristor Firing Module drawer which affected proper operation of the redundant Thyristor Firing Module drawer. The root cause was determined to be that the Automatic Voltage Regulator (AVR) Firing Module power supplies have a latent design vulnerability where shared common output nodes are not isolated after a failure. A plant modification is proposed that will eliminate the condition by electrically isolating the AVR Firing Module power supplies upon failure.

This event had no effect on the public health and safety. The event was reported to the Nuclear Regulatory Commission (NRC) on November 3, 2017 under 10 CFR 50.72(b)(2)(iv)(B) and 50.72(b)(3)(iv)(A) as an event that resulted in the automatic actuation of the Reactor Protection System when the reactor is critical and a valid actuation of the AFWS.

05000286/LER-2017-00329 August 2017Indian Point Unit 3
Indian Point

Technical Specification 3.7.6. A pinhole sized through wall leak was discovered on the downstream side of CD-123, the 32 Auxiliary Boiler Feed Pump Bearing Cooling Relief Valve, which was unisolable to the Condensate Storage Tank.

The pinhole leak was identified following the performance of 3PT-Q120B, 32 Auxiliary Boiler Feed Pump Functional Test. All Operability and Acceptance Criteria of 3PT-Q120B were sat. The relief valve was removed from the system and sent to a vendor for evaluation. After the vendor evaluation, it was determined that the valve pinhole area leak was due to a casting defect.

This event was determined to be reportable as a Loss of Safety Function pursuant to10 CFR 50.72(b)(3)(v)(B) - Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to remove residual heat.

RC FORM 366 (04-2017)

05000247/LER-2017-00323 August 2017Indian Point Unit 2
Indian Point

' On June 27, 2017, during reactor startup, power was raised from Mode 3 to Mode 2 and above the P-6 (Intermediate Range Neutron Flux) interlock with the P-6 Switches in the wrong position. With P-6 inoperable this was a violation of the requirement of Technical Specification (TS) Limiting Condition of Operation (LCO) 3.3.1 and resulted in a 60 Day Licensee Event Report (LER). LCO 3.3.1, Table 3.3.1-1, Item 17 states that the Intermediate Range Neutron Flux, P-6 shall be operable.

On June 27, 2017, during performance of 2-PT-V63A, Reactor Protection System (RPS) Logic Train 'A' Partial Functional Test, Instrumentation and Control (I&C) Technicians left two Intermediate Range P-6 switches in the wrong position, which resulted in an unplanned entry into'LCO 3.3.1, due to inoperable RPS instrumentation. This inoperable RPS instrumentation resulted in a TS LCO 3.3.1 violation when reactor power was raised from Mode 3 to Mode 2.

05000247/LER-2017-00222 August 2017Indian Point

On March 6, 2017, Instrumentation and Control (I&C) maintenance had a scheduled activity to calibrate the 22 Steam Generator (SG) Auxiliary Feedwater (AFW) flow indicator (FI-1201). The tag-out was applied by Operations at 0748 hours on the two flow transmitter root stop valves. l&C personnel began to calibrate FI-1201 at approximately 1000 hours. The calibration Procedure requires isolation of the high and low isolation valves and opening of the equalizing valve to allow venting of any pressure going to the transmitter. The calibration was performed and all as-found readings were within acceptance range. The test equipment was removed. The transmitter restoration was completed with the exception of filling and venting the transmitter FI-1201 and placing it back in service. Due to the root valves being tagged out, the source of water was isolated preventing proper filling and venting of the transmitter. The l&C supervisor discussed the restoration 'of the transmitter with the Operations shift manager, and it was agreed that Operations would complete restoration of the transmitter when the tag-out was removed. The l&C supervisor noted this and marked NA for the steps to return the transmitter back in service. This is a common practice when performing transmitter calibrations as a part of larger work windows because the tag-out must first be removed for a source of water to be available for restoration. However, the l&C supervisor did not obtain the Shift Manager's initials, which is required by Procedure.

ConSequently, Operations did not restore the transmitter to service, resulting in FI-1201 remaining inoperable for greater than the Technical Specification 3.3.3 allowed completion time of 30 days. It should be noted that in spite of inoperability of FI-1201, since FI-1201 is indication only, there was no actual loss or degradation of water flow to the steam generators at any time and thus had no impact on SG heat removal capability.

05000247/LER-2017-00122 August 2017Indian Point

On June 26, 2017, Operations commenced a downpower from 100 percent to 93 percent reactor power to support performance of the Main Turbine Stop and Control Valve Test. With reactor power at 94 percent, the 22 Main Boiler Feed Pump Turbine (MBFPT) speed control trouble alarm annunciated coincident with pump speed swings of 800 revolutions per minute (rpm). The operators ceased the downpower and placed the 22 Main Boiler Feedwater Pump (MBFP) in Manual speed control to control the rpm swings. This was unsuccessful, and the rpm swings continued. The 22 MBFPT low pressure (LP) governor valves were observed to be cycling from full-closed to full-open. The decision was made to take local pneumatic control of the 22 MBFP to stabilize pump speed. Two minutes after establishing local pneumatic control, the LP governor valves went to full closed. With the rapid reduction in 22 MBFP speed, the pump was no longer delivering feedwater flow to the SGs. An automatic main turbine runback signal should have been generated on a low speed signal; however, there was no turbine runback actuation. In response, the operators commenced a manual runback to reduce main turbine load, but the decreasing SG levels reached 15 percent, and at 1531 hours a manual reactor trip was initiated.

All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The direct cause of the reactor trip was that the shoulder screws used on the 22 MBFPT LP governor valve servomotor linkage had backed out and detached. This caused the LP governor valves to fail closed, shutting off the turbine steam supply. This event had no effect on the public health and safety. The event was reported to the Nuclear Regulatory Commission (NRC) on June 26, 2017 under 10 CFR 50.72(b)(2)(iv)(B), 50.72(b)(2)(xi), and 50.72(b)(3)(iv)(A).

05000286/LER-2017-0029 August 2017Docket Number
Indian Point

On June 11, 2017, while at 100 percent reactor power, Operations placed Chemical and Volume Control System (CVCS) Demineralizer Diversion Valve CH-TCV-149 in DIVERT to allow the 32 Mixed Bed Demineralizer to be removed from service and align the 31 Mixed Bed Demineralizer for service. Within about two minutes after returning CH-TCV-149 to AUTO, which placed the 31 Mixed Bed Demineralizer in service, Letdown Backpressure Control Valve CH-PCV-135 demand had gone to 0 percent (full open demand) while letdown backpressure had increased, reaching 302 psig.

Operations was alerted to a leak that had developed on 32 Mixed Bed Demineralizer Inlet Isolation Valve CH-352. In an effort to isolate the leak, CH-TCV-149 was placed in DIVERT. Due to the elevated pressure at CH-TCV-149 with CH-PCV- 135 fully open, placing CH-TCV-149 in DIVERT coupled with the elevated line pressure created a pressure transient in the letdown line upstream of the CVCS Reactor Coolant Filter. Reactor Coolant Filter Inlet Isolation Valve CH-305 experienced this pressure transient, which resulted in the valve developing a significant leak at the body to bonnet joint. Abnormal Operating Procedure (AOP) 3-AOP-LEAK-1 was entered, and normal letdown was manually isolated to stop the CH-305 leak. Excess letdown was placed in service to balance reactor coolant inventory at a Pressurizer water level of 61 percent.

This exceeded the 54.3 percent limit of Technical Specification 3.4.9 Condition A, and Operations declared the Pressurizer inoperable. The inoperability of the Pressurizer is reportable as a safety system functional failure under 10 CFR 50.73(a)(2)(v). The direct cause of this event was elevated system pressure due to loading of the Reactor Coolant Filter from materials when the 31 Mixed Bed Demineralizer pathway was aligned. The elevated operating pressure in the CVCS letdown stream challenged the integrity of diaphragm valves CH-352 and CH-305, requiring the isolation of normal letdown.

05000286/LER-2017-00113 July 2017Indian Point Unit 3
Indian Point

On May 14, 2017, at 0233 hrs, Indian Point Unit 3 entered Mode 4 as part of coming out of outage 3R19 and preparing for power operations. Operations test group was preparing for performance of 3-PT- CS004, Residual Heat Removal (RHR) Check Valve Testing. The team gathered for a pre job brief in accordance with the requirements of EN-HU-102, Human Performance Traps &Tools Procedure. At the time the only allowable access point to the Inner Crane Wall was through the double gate combination of Gates D and E, which require one gate to be maintained closed and secured at all times. Workers needed to enter inside of the Crane Wall to perform a portion of the valve lineup required by 3-PT-CS004. After unbolting and opening the gate, the two operators and a contract Radiation Protection (RP) Technician went through gate C despite a posted sign stating that the gate was not to be utilized in modes 1 through 4.

While the valve manipulations were in progress the NRC Resident Inspector was also conducting a tour of the Vapor Containment (VC) and identified that gate C was opened. This gate being open in this plant condition resulted in a safety system functional failure, since with the gate unsecured this made the containment sumps inoperable.

05000247/LER-2016-00228 February 2017Indian Point

On March 7, 2016, while performing set-up activities for 2-PT-R084C, "23 EDG 8 Hour Load Test," the normal supply breaker to 480 Volt AC Bus (ED) 3A tripped on overcurrent. This caused 480 Volt AC Buses 3A and 6A to de-energize since, as part of the test set-up activities, the tie breaker (3AT6A) between Buses 3A and 6A was closed and the normal supply breaker for Bus 6A was opened. This resulted in a loss of both 21 and 22 Residual Heat Removal (RHR) (BP) pumps. As 'designed, all Emergency Diesel Generators (EDGs) (EK) received automatic initiation signals to start. All required 480 Volt AC buses automatically re-energized by design, with the exception of Bus 3A, which had an overcurrent lockout. Operators manually started 22 RHR pump to restore RHR cooling.

However, prior to restoring the normal supply power to Bus 3A, 23 EDG tripped on overcurrent which resulted in a second loss of RIM event. The cause for the Bus 3A supply breaker tripping was inadequate procedural guidance resulting in excessive loads being energized on Buses 3A and 6A. The direct cause for 23 EDG tripping was cracked solder joints on the automatic voltage regulator (AVR). Corrective actions included revising 2-PT-R084C and replacing the voltage regulator. The event had no effect on public health and safety.

05000247/LER-2015-00115 September 2016Indian Point

On August 11, 2015, during operator investigations inside the reactor containment building, a through wall leak was discovered on the 24 Fan Cooler Unit (FCU) motor cooler service water (SW) return line. The leak was in a 2 inch copper-nickel pipe near a brazed joint upstream of containment penetration SS. The leak was located within the ASME Section XI Code ISI Class 3 boundary and estimated to be approximately 2 gpm.

Since the pipe flaw was through wall and was located within the ASME Section XI boundary, it exceeds the flaw allowable limits provided per IWC-3000.

The weld leak was evaluated and determined to meet the structural requirements of ASME Code Case N-513-3.

The condition was determined to have no impact on SW cooling safety function or adverse impact on piping structural integrity. The pipe is considered a closed loop system inside containment and required to meet containment integrity.

An engineering evaluation was performed to determine the potential air leakage out of containment based on the observed SW leakage into containment.

This evaluation concluded that the leaking defect could result in post-LOCA air leakage out of containment in excess of that allowed by Technical Specification 3.6.1 (Containment) which requires leakage rates to comply with 10 CFR 50, Appendix J.

The direct cause was corrosion. The apparent cause was the length of time to implement a modification to replace the FCU motor cooler copper-nickel piping identified in 2009 per the SW mitigation strategy.

An engineered clamp was installed over the pipe defect. The pipe and affected elbow were replaced in accordance with the requirements of ASME Section XI Code during the spring refueling outage in 2016. A modification to replace piping will be processed for funding. The event had no significant effect on public health and safety.

05000286/LER-2015-00414 September 2016Indian Point

On May 9, 2015, an automatic reactor trip (RT) occurred due to a Turbine-Generator trip as a result of a failure of the 31 Main Transformer (MT). All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the condenser. There was no radiation release. The emergency diesel generators did not start as offsite power remained available. The auxiliary feedwater system actuated as-expected due to steam generator low level from shrink effects. Control room operators received alarms on the fire detection panel of the activation of the 31 MT and curtain wall deluge valves. Report to operators that there was an explosion and fire on the 31 MT. The plant fire brigade responded to the fire. The 31 MT had failed. Due to collateral influence from the 31 MT failure, the deluge system for the 32 MT and Unit Auxiliary transformer had also activated. In accordance with the emergency plan a Notice of Unusual Event (NUE) was declared at 1801 hours, which was terminated at 21:04 hours. The direct cause was an internal fault of the A Phase high voltage winding in the upper portion of the transformer.

The root cause was vendor design/manufacturing deficiency that caused an internal failure that resulted in a fault on the A phase HV side of the transformer and the A phase HV voltage bushing. Key corrective actions included replacement of the 31 MT with a spare transformer, associated acceptance testing, repair of the isophase bus ducting for the 31 MT, inspections, cleaning, testing of the 32 MT, the Unit Auxiliary Transformer, high voltage components, isophase buses and main generator. A 4-year PM was prepared to perform Partial Discharge testing on the Unit 2, and Unit 3 MTs, Unit 2 and Unit 3 Auxiliary Transformers and the Unit 3 GT Auto Transformer The event had no significant effect on public health and safety.

FACILITY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

05000286/LER-2015-00514 September 2016Indian PointOn June 15, 2015, an automatic reactor trip (RT) occurred due to a Main Turbine-Generator trip as a result of a direct generator trip from the Buchanan switchyard. All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the condenser. There was no radiation release. The emergency diesel generators did not start as offsite power remained available. The auxiliary feedwater system actuated as expected due to steam generator low level from shrink effect. Prior to the RT, Con Edison requested that Main Generator Output breaker 1 be opened to support removing 345kV feeder W97 from service for removal of a Mylar balloon on a 345kV conductor at the Millwood substation. After breaker 1 was opened, Main Generator Output breaker 3 opened initiating a direct generator trip signal due to a fault in South Ring Bus breaker 5. Direct cause of the RT was failure of 345kV breaker 5 due to an internal fault which activated protective relays that opened the remaining Main Generator Output breaker 3 which initiated a trip sequence that resulted in a RT. The root cause was Indian Point Energy Center did not provide formal notification of industry operating experience (OE) to Con Edison owner of breaker 5. The specific OE pertained to ITE Type GA breakers. Corrective actions include replacement of breaker 5. Procedure EN-0E-100 (OE Program) was revised to add a section describing how to initiate formal notification to external groups when OE related to components they own and/or control can affect generation. A new site procedure was issued (SMM-LI-126) to formalize the site process for notifying external groups of OE that can affect generation. The event had no effect on public health and safety.
05000247/LER-2016-0096 September 2016Indian Point

On July 6, 2016,Instrument and Control (I&C) technicians were preparing to perform 2-PT-2M3A (RPS Logic Train B Actuation Logic Test and Tadot). Prior to starting the test, the I&C technicians were unable to locate key #184 that was identified in the test as associated with the reactor trip breaker B bypass key switch. Control Room staff recommended obtaining key #183 associated with reactor trip breaker A bypass key switch to use in lieu of key #184. To ensure the key would work prior to starting the test, the train B bypass key switch was positioned by an I&C technician to the Defeat position. Because reactor trip Bypass Breaker B was in the racked out position, when the key switch was taken to the Defeat position, it caused the normal Reactor Trip Breaker B to open, which initiated a reactor trip (RT) and auxiliary feedwater system actuation. The direct cause was an I&C technician turned the key interlock to defeat on switchgear Channel B Reactor Protection Logic without having the BYB Bypass breaker racked in and closed. The root cause was Indian Point personnel emphasized work culture production goals without fully recognizing the need to maintain fundamental standards and expectations for nuclear workers. Key corrective actions included site all-hands meeting discussing the event, lessons learned, reinforced expectations and the Fleet Refocus Initiative. As an interim action, all essential work that effects generation was required to have direct oversight by a superintendent or above, all work start authorizations provided by operations undergo a work challenge utilizing a new checklist from this event. Complete the actions associated with the Fleet Refocus Observation program. The event had no effect on public health and safety.

Indian Point 2 05000-2'47 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 (1.

DESCRIPTION OF EVENT

On July 6, 2016,while at 100 percent reactor power, preparations were in progress to commence a scheduled bi-monthly surveillance test in accordance with 2-PT-2M3A (RPS Logic Train B Actuation Logic Test and TADOT (>25% Reactor Power)). The purpose of the surveillance is to perform actuation logic testing of the Reactor Protection System (JC) logic Train B in accordance with Technical Specification (TS) 3.3.1 (Reactor Protection System Instrumentation) Table 3.3.1-1, Function 20, Surveillance Requirement 3.3.1.5. The test had been originally scheduled for June 30, 2016, but due to concerns about Battery Changer 22 grounds, the test was re-scheduled for the following week., At approximately 07:30 hours, on July 6, 2016, a pre-job briefing was held with four I&C technicians and the I&C job Supervisor. Subsequent to the briefing, the I&C technicians went to the Control Room (NA) and informed the Control Room Supervisor (CRS) of the test and what to expect. In the prerequisites section of 2-PT-2M3A, the breaker interlock key number 182, 184 or equivalent was to be obtained from operations prior to commencing the test. At approximately 9:15 hours, I&C personnel determined neither key number 182 nor key number 184 could be found in the Control Room key locker. The CRS suggested that the Train A key number 183 could be used as an equivalent because it was believed that both trains were keyed the same.

Due to concerns with the short Technical Specification (TS) 8-hour Allowed Outage Time (AOT) for the test the I&C technicians wanted to ensure the key would work prior to entering the TS Limiting Condition for Operation (LCO) and starting the test and discussed it with the CRS. The key concerns were discussed with the CRS. After a brief discussion, the I&C technicians believed that Operations gave them permission to test the key prior to starting the surveillance test. Operations believed that the I&C technicians would test the key during the surveillance.

At approximately 9:30 hours, two of the I&C technicians, one operator and two Nuclear Plant Operator (NPOs) took key number 183 (designated for Train A) to the location of the Reactor Trip Breakers (RTBs) (BKR)(Cable Spreading Room) (NA). The 8-hour TS LCO was not entered. Two non-licensed operators (NPOs) were present in the Cable Spreading Room to rack in the bypass breaker when requested by the I&C technicians.

The Field Shift Supervisor (FSS) was also there to inspect cables that were utilized with the Rod Drop Testing during the recent outage. One of the I&C technicians called the Control Room and told another I&C technician, who was staged in the Control Room, that they would receive an annunciator on Panel SK, Window 2-5. The Control Room operator acknowledged the alert of an expected alarm and the I&C technician in the Control Room relayed the acknowledgement to the I&C technician in the Cable Spreading Room containing the RTBs.

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 intemet e-mail to An I&C technician signaled the other I&C technician that was at the RTBs to test the key. Without using a procedure or an approved work instruction, the other I&C technician positioned the Train B bypass key switch to defeat.. Because reactor trip Bypass Breaker B was in the racked out position, when the train B bypass key switch was taken to the Defeat position, it caused the normal Reactor Trip Breaker B to open, which initiated a reactor trip (RT) at approximately 9:38 hours.

All control rods (AA) fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the condenser (SG). The auxiliary feedwater system (BA) actuated as expected due to steam generator low level from shrink effect.

Normally during performance of the test, the train B bypass key switch is only positioned to Defeat after Bypass Breaker B has been closed and the Reactor Trip Breaker B- has been opened. The condition was recorded in the Indian Point Energy Center (IPEC) Corrective Action Program (CAP) in. Condition Report CR-IP2-2016-04320.

The reactor protection system (RPS) (JC) initiates a reactor shutdown, based on values of selected unit parameters, to protect against violating the core fuel design limits and reactor coolant system pressure boundary during anticipated operational occurrences and to assist the Engineered Safety Feature Systems in mitigating accidents. The RPS instrumentation is segmented into four distinct but interconnected modules one of which is reactor trip switchgear that includes the reactor trip breakers (RTBs) and Bypass Breakers. These components provide a means to interrupt power to the control rod drive mechanisms (CRDMs) and allows the rod cluster control assemblies (RCCAs) or rods to fall into the core and shut down the reactor. The bypass breakers allow testing of the RTBs at power. The control rod drive system is designed such that the control rods are held in place and are capable of being moved only when its power supply is energized. Two RTBs placed in series with the control rod drive power supply remain closed as long as their respective under-voltage coils are kept energized by the RPS logic buses. Two bypass breakers are provided to allow in service testing of either RTB. The key-interlock switch is provided such that if both bypass breakers are closed at the same time while racked in, both bypass breakers will be tripped. This interlock is defeated in the test position with the key to allow for tripping of the undervoltage device of the bypass breaker when the reactor is in operation. The key interlock switch at the Reactor Trip Switchgear is placed in the Defeat position to prevent repeated breaker operation as the logics are tripped and reset.

During normal testing of the RPS Logic, the bypass breaker is racked in and closed and the key-interlock switch would then only bring in the alarm in the Control Room supervisory annunciator. For this event the bypass breaker was not racked in (closed).

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 bypass breakers must be manually closed and under no circumstances should both bypass breakers be racked in and closed at the same time. During normal testing of Channel B, the associated key-interlock switch would have been placed in the defeat position. This would have resulted in: 1) Illuminating a red light on the Train B cabinet, 2) Annunciating an alarm RTB & BYA Train B Defeat on the Control Room supervisory annunciator, 3) Opened up the closing circuit of RTB which is being tested, 4) Opened up the coil circuit of undervoltage trip devices for breakers RTB and BYA which is being tested and preventing the unit from tripping. In this event the key bypass switch was turned to the defeat position while the Bypass Breaker was still racked out (open) which de-energized the undervoltage coil for the B RTB which caused it to open and trip the unit.

An extent of condition (EOC) review determined the condition is bounded to only the RTBs because they are the only breakers with a key-interlocked switch such that if both bypass breakers are closed at the same time while racked in, both bypass breakers will be tripped. The test procedure for unit 2 calls for key number 182, 184 or allows for an equivalent key to be used. This is vague guidance unlike unit 3 which only has one key. The Unit 2 test procedure 2-PT-2M3A will be revised to remove "equivalent.

CAUSE OF EVENT

The direct cause of the RT was due to operating the "B" RPS bypass key out of sequence during Reactor Protection logic testing. An I&C technician turned the key interlock to defeat on switchgear Channel B Reactor Protection Logic without having the BYB Bypass Breaker racked in and closed, which opened the undervoltage tripping device of the RTB and tripped the reactor. The I&C technician turned the key without procedural guidance. The I&C technicians were testing the key with verbal guidance from operations, due to vague procedure guidance in 2-PT-2M3A, that allowed an equivalent key to be used (number 183). Due to not stopping when unsure (conservative decision making), the I&C technicians tested the key prior to starting the surveillance because of perceived time pressure.

The root cause (RC) of the event was that IPEC personnel emphasized work culture production goals for productivity, schedule adherence, and backlog reduction without fully recognizing the need to maintain fundamental standards and expectations for nuclear workers, such as procedure use and adherence and staying in process during work activities. The RC resulted in the I&C technician turning the key without procedure guidance or work instructions and tripped the plant.

CORRECTIVE ACTIONS

The following corrective actions have been or Action Program (CAP) to address the causes of

  • Site all-hands meeting was held to discuss to reinforce expectations.

will be performed under the Corrective this event:

the event, the lessons learned, and 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 intemet e-mail to

  • discuss the Fleet Refocus Initiative.
  • work that effects generation was to have direct oversight by a superintendent or above.
  • All work start authorizations provided by operations watch personnel must now undergo an additional work challenge utilizing a checklist developed in response to this event. Revised process was formalized by an Operations Standing Order.
  • The completion of corrective actions associated with the Fleet Refocus Observation Program will be documented to ensure all personnel apply the essential knowledge, skills, behaviors and practices needed to conduct work safely and reliably.
  • Procedures 2-PT-2M3, 2-PT-2M2, and 2-PT-2M2A will be revised to remove the word "equivalent" to prevent any questions on which key to use.

EVENT ANALYSIS

The event is reportable under 10CFR50.73(a)(2)(iv)(A). The licensee shall report any event or condition that resulted in manual or automatic actuation of any of the systems listed under 10CFR50.73(a)(2)(iv)(B). Systems to which the requirements of 10CFR50.73(a)(2)(iv)(A) apply for this event include the Reactor Protection System including reactor trip and AFWS actuation. This event meets the reporting criteria because an automatic reactor trip was initiated at 9:38 hours, on July 6, 2016, and the AFWS actuated as a result of the RT. On July 6, 2016, at 13:16 hours, a four hour non-emergency notification was made to the NRC (Log Number 52067) for an automatic reactor trip while critical and included the eight hour non-emergency notification for the actuation of the AFW system. Both notifications were in accordance with 10CFR50.72(b)(3)(iv)(1). The event was recorded in the Indian Point Energy Center corrective action program (CAP) as CR-IP2-2016-04320.

As all primary safety systems functioned properly there was no safety system functional failure reportable under 10CFR50.73(a)(2)(v).

PAST SIMILAR EVENTS

A review was performed of the past three years of Licensee Event Reports (LERs) for events that involved a reactor trip due to testing of the reactor protection system.

No applicable LERs were identified.

SAFETY SIGNIFICANCE

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

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

There were no actual safety consequences for the event because the event was an uncomplicated reactor trip with no other transients or accidents.

  • Small Group Meetings.
  • from the Fleet Refocus Initiative.

Site All-hands meeting was held to Conducted Fleet Refocus Initiative Implemented observation activities As an interim action all essential 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 intemet e-mail to Required primary safety systems performed as designed when the RT was initiated. The AFWS actuation was an expected reaction as a result of low SG water level due to SG void fraction (shrink), which occurs after a RT and main steam back pressure as a result of the rapid reduction of steam flow due to turbine control valve closure.

For this RT there was no actual condition to initiate the reactor trip breaker opening. Event was initiated by human error.

There were no significant potential safety consequences of this event. The RPS is designed to actuate .a RT for any anticipated combination of plant conditions to include low SG level. All components in the RCS were designed to withstand the effects of cyclic loads due to reactor system temperature and pressure changes. The reactor trip breakers (RTBs) are in the electrical power supply line from the control rod drive motor generator set power supply to the CRDMs. Opening of the RTBs interrupts power to the CRDMs, which allows the shutdown rods to fall into the core by gravity. Each reactor trip breaker (RTB) is equipped with a reactor trip bypass breaker (RTBB) to allow testing of the trip breaker while the unit is at power. Each RTB and RTBB is equipped with an undervoltage coil and a shunt trip coil to trip the breaker open when needed. The reactor trip signals generated by the RPS automatic trip logic cause the RTBs and associated RTBB to open and shut down the reactor.

There are two RTBs in series so that opening either will interrupt power to the rod control system and allow the control rods to fall into the core and shut down the reactor. Each RTB has a parallel RTBB that is normally open. This feature allows testing of the RTBs at power. A trip signal from RPS logic train A will trip RTB A and RTBB B; and a trip signal from logic train B will trip RTB B and RTBB A. During normal operation, both RTBs are closed and both RTBBs are open. When any one train is taken out of service for testing, the other train is capable of providing unit monitoring and protection until the testing has been completed.

For this event, rod control was in automatic and all rods inserted upon initiation of a RT. The AFWS actuated and provided required FW flow to-the SGs. RCS pressure remained below the set point for pressurizer PORV or code safety valve operation and above the set point for automatic safety injection actuation. Following the RT, the plant was stabilized in hot standby.

Indian Point 2 05000-247

05000286/LER-2015-0086 September 2016Indian Point

On December 14, 2015, an automatic reactor trip (RT) occurred due to a Turbine-Generator trip caused by a fault on 345 kV feeder W96 transmission tower IP3-4. All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the condenser. The auxiliary feedwater system actuated as expected due to steam generator low level from shrink effect. _Inspections identified that an electrical fault damaged the 345 kV Transmission Tower line insulators. Direct cause of the RT was radial flashover of insulators on C phase of the 345 kV feeder W96 line at Transmission Tower IP3-4. The most likely cause is a pre-existing damaged insulator as a result of a prior flashover event that resulted in a repeat flashover due to environmental conditions. A single event with multiple flashovers associated with reduced insulation resistance due to a bird streamer is , possible but less likely. Transmission Tower design does not have barriers to prevent avian perching on feeder towers. Corrective actions included inspection of Transmission Tower line insulators and ancillary hardware and replacement of damaged insulators and hardware. The preventive maintenance (PM) scope for the Unit 2 345 kV and 138 kV feeders was revised to include inspection and cleaning of Transmission Tower line insulators and hardware. An action request was generated to implement PM Template ENN-EP-G-004, Attachment 7.7 and Model Work Orders were revised and thermography and corona camera inspections performed. Bird guards will be installed on Entergy owned 345 kV and 138 kV Transmission Towers to preclude the effects of bird streaming. The event had no effect on public health and safety.

FACILITY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

05000286/LER-2015-0076 September 2016Indian Point

On July 8,2015, during surveillance testing, the Control Room received a 6.9kV motor trip alarm due to 31 Condensate Pump (CP) Motor circuit breaker trip on overcurrent. .

Operators entered Alarm Operating Procedure 3-A0P-FW-1 due to loss of the 31 CP and initiated a load reduction. During this time the Main Boiler Feedwater Pump (MBFP) suction pressure decreased to its suction pressure cutback controller pressure range and its output decreased MBFP speed control to a minimum. The 31 MBFP speed control signal locked in at this minimum speed signal due to actuation of the MBFP Lovejoy speed control system Track and Hold feature. Due to this minimum 31 MBFP condition, the 31 MBFP , recirculation valve opened causing the 31 MBFP check valve to close. With the 31 MBFP unloaded, Steam Generator (SG) water levels decreased and at 15 percent operators manually tripped the reactor. The Auxiliary Feedwater System automatically started as expected due to SG low level from shrink effect. Direct cause was the 31 MBFP entered a Hold condition erroneously due to a miss-wired Track and Hold board in the speed control system. The root cause was the procurement for the MBFP Lovejoy Track and Hold boards was at an insufficient quality level commensurate with its criticality. There was a failure to mandate functional testing and wiring verification requirements on the vendor to ensure the procurement of a quality product. Corrective actions included replacement of MBFP track and hold board and 31 CP motor. A new replacement Track and Hold circuit board for both the 31 and 32 MBFP speed control system with the miss-wiring corrected was installed. The quality levels for the Track and Hold boards were revised from Q4 to Q3.

MBFP Lovejoy speed control maintenance procedures and site vendor manuals were revised to include more detail. The event had no effect on public health and safety.

FACILITY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

05000247/LER-2016-00823 August 2016Indian Point

On November 30, 2015, a leak was discovered on Service Water (SW) weld F-1924, which joins a cement-lined carbon steel elbow to a Copper/Nickel (Cu/Ni) Heat Exchanger pipe nozzle on the 21 Component Cooling Water Heat Exchanger. Code case N-513-3 was applied to the pipe defect to justify, continued operability and preparations initiated for a weld repair during the upcoming spring refueling outage (RO) starting March 7, 2016.

'On. March 19, 2016, weld repair was performed on the weld F-1924 and satisfactory non- destructive examination was completed. On June 12, 2016, a new leak was discovered in the same SW pipe repair area. During the subsequent repair, cracking was experienced in the ERCuNi filler metal which extended the duration of the repair and forced a Unit shutdown to comply with the TS 72 hour AOT. The direct cause was recurring longitudinal solidification cracks that developed during welding of copper-nickel to carbon steel pipe. The apparent cause was that the team assigned to prepare and execute the weld repair plan failed to ensure all risks and issues were.identified and managed properly. Key corrective actions included weld repair using a new vendor weld procedure and ERNiCu-7 filler material, communication of the lessons learned to all site personnel reinforcing standards and expectations for readiness for critical work.

Incorporate recommendations for improving risk management process effectiveness by incorporating actions taken,in response to INPO IER L2-16-9. The event had no effect on public health and safetY". .. .

Indian Point 2 05000-247 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 30, 2015, a 1 drop per second leak was discovered on Service Water (SW) (BI) weld F-1924 on SW line #411, which joins a carbon steel elbow to a 90/10 Copper/Nickel (Cu/Ni) Heat Exchanger (HX) pipe nozzle on the 21 Component Cooling Water (CCW) (CC) Heat Exchanger (HX). In accordance with Generic Letter 89-13 program guidance and ASME Code case N-513-3 the weld was evaluated and determined acceptable but required to be repaired prior to start-up from the 2016 spring refueling outage (RO) (2R22). The degradation mechanism leading to the leak was likely crevice corrosion. Leakage was seen to emanate at the weld toe, on the carbon steel side. The leak was recorded in Indian Point Energy Center (IPEC) corrective action program (CAP) as CR-IP2-2015-05358 and repairs scheduled to be performed during the upcoming spring refueling outage (RO) starting March 7, 2016. The copper- nickel to carbon steel weld joints in the CCW to SW piping are the only known welds on site with this configuration. A flaw characterization and full pipe circumference examination of this weld found that the leak was a localized area of corrosion.

Another area of thinning at one other circumferential location on the same weld was identified, but the weld thickness in that area met minimum wall thickness requirements and was designated for continued monitoring with no immediate action necessary.

To support the weld repair plan, from December 17, 2015 to February 8,.2016, a draft Entergy Welding Procedure Specification (WPS) was developed for welding P34 90/10 copper-nickel base material to P1 carbon steel base material. ERNiCu-7 was chosen as the filler metal. Two separate weld test coupons were prepared to qualify the procedure and were shipped to the weld test lab (Lucius Pitkin Inc.) for procedure qualification testing. Test results were obtained on March 3, 2016, which showed one of the four bend tests failed due to inclusions in the root of the weld joint resulting in a failure to qualify the procedure. On March 4, 2016, vendors are contacted to determine if they have a qualified welding procedure for copper-nickel to carbon steel. Only one vendor (Westinghouse PCI) had a qualified procedure using the ERCuNi filler metal. Due to the limited time available to repeat the procedure qualification testing prior to scheduled work, the weld repair was contracted to the vendor with the approved qualified procedure for welding P34 90/10 copper-nickel to P1 carbon steel using the ERCuNi filler metal.

On March 7, 2016, the Unit 2 Refueling Outage (RO) started. Repairs to the 21 CCW Heat Exchanger SW line #411 pinhole leak were scheduled to be performed on March 18 through March 19, 2016. On March 19, 2016, weld repairs, including excavation, weld build-up, and post-repair non-destructive examination (NDE) of the flaw on weld F-1924 was completed. On June 4, 2016, a In-service Leak Test (ISLT) of the SW system was completed satisfactorily. No leaks identified.

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 intemet e-mail to On June 12, 2016, CR-IP2-2016-03818 recorded a new leak that was discovered in the same SW pipe line #411 repair area. The leak was estimated at 1 drop per 5 seconds in the SW System piping supplying the 21 CCW HX. The leak was on the elbow side at the toe of the elbow to inlet nozzle weld of the 21 CCW HX on 20 inch SW line #411, weld number F-1924. This line is the SW supply to the 21 CCW HX. SW line #411 is a standard wall (schedule STD) cement-lined carbon steel pipe having a nominal wall thickness of 0.375 inches. The nozzle/pipe of the 21 CCW HX is 90/10 copper/nickel with a thickness of 0.500 inches. Its function is the inlet pipe to the 21 CCW HX.

SW line #411 is fed from either 20 inch SW line #411 (1-2-3 SW Header), or 20 inch line #407 (4-5-6 SW Header). At the time of discovery, the 1-2-3 SW header was the essential header supplying the 21 CCW HX. Leaking weld F-1924 is a dissimilar metal butt-weld between a carbon steel cement-lined elbow and a copper-nickel heat exchanger inlet nozzle/pipe. The weld location is ASME Section XI Class 3 and is nuclear safety related. The SW pipe with the weld defect is located in the Primary Auxiliary Building (PAB) on the 80 foot elevation downstream of valve SWN-34.

Engineering performed an Operability Evaluation using the methodology and structural margins provide in ASME Code case N-513-3. The pipe weld degradation was determined to be within the Code Case limits. The affected pipe section was considered structurally acceptable therefore Operable DNC. An outage emergent team designated to address the leak determined after discussions with site departments that the leak did not have to be repaired until the next outage (2R23). The Mode 1 hold was removed from the leak repair Work Order and the repair was designated to be scheduled as soon as the work was ready to be performed.

On June 13, 2016, weld repairs were scheduled to be performed beginning June 21, 2016. Work migrated from the refueling outage schedule to the online schedule. The preliminary schedule included 24 hours for the weld repair based on vendor input and time estimates from the original 2R22 outage repair window. A leadership challenge meeting discussed the weld plan because the online weld repair requires entry into a Technical Specification (TS) 72 hour shutdown LCO due to removal of the 21 CCW HX from service.

On June 16, 2016, a conference call was held with the weld vendor to discuss the repair approach. The weld vendor and the Indian Point welding engineer concluded the failure of the original weld repair was caused by contamination of the weld and not as a result of any metallurgical issues with the vendor weld procedure.

Subsequent follow-up correspondence with the weld vendor questioned the possibility of hot cracking of the ERCuNi filler metal due to iron dilution from the carbon steel base material. The weld vendor's opinion was that using this process on this configuration would not result in hot cracking. Peer review by another Entergy site made the same conclusion. An Engineering Change was approved to repair the weld defect from both the inner diameter and outer diameter of the pipe using the vendor weld procedure on June 16, 2016. On June 16, 2016, at 23:30 hours, the unit returns to service following an extended refueling outage.

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 On June 17, 2016, a management challenge and critical evolution meeting (CEM) was held for the 21 CCW HX leak repair. At the CEM it was presented that the 2R22 outage repair failed due to weld contamination that occurred because the repair was attempted from the outside of the pipe only and since the cement lining surrounding the repair cavity was not accessible for adequate cleaning around the weld joint, resulting in contaminants becoming trapped in the weld that were not evident in the final exam. In addition, a surface exam of the root pass was not specified to be performed to ensure proper weld integrity below the surface of the finished weld.

Assurance was provided that the new plan would be successful due to a change in work scope (internal access to the defect area, allow proper removal of cement lining, clean affected area, perform a surface exam, weld build-up, adequate access for purging and inspection/repair). The CEM also identified that the contingency Enecon coating of internal piping following weld repairs was an excessive time contributor. Therefore, the plan was altered to use a quick curing waterplug coating repair to the inner piping wall.

On June 21, 2016, the TS 3.7.7 LCO was entered when the 21 CCW HX was declared inoperable for scheduled maintenance. Work to repair the weld commenced. On June 22, 2016, during installation of the remainder of the copper-nickel to carbon steel weld, workers identified repeated cracking problems and could not successfully complete the weld. A leadership team conference was held to discuss the cracking problem and determine a resolution plan. A decision was made to implement a revised plan to grind out the defective copper-nickel to carbon steel weld area, perform a PT exam on the excavated area, weld out the excavated area using a modified transverse technique across the root gap and perform a final PT and UT.

On June 23, 2016, weld repairs were completed in accordance with the revised plan.

During the final inspection of the weld, the qualified inspector rejected the weld based on incomplete weld penetration and appearance on the inside diameter (ID) of the piping in the weld area. CR-IP2-2016-04085 recorded the unsatisfactory condition of poor weld quality. Follow-up engineering discussions with the fleet welding engineer and qualified inspector determined that the internal weld could not be accepted and the weld would have to be removed and re-welded. At 14:30 hours, the outage control center (OCC) issued a schedule update indicating that the 72 hour TS AOT will expire prior to completing the revised plan for weld repairs and restoration of the 21 CCW HX.

On June 24, 2016, at 04:00 hours, the TS 3.7.7 AOT expired forcing a unit shutdown.

The SW System (SWS) 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.

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 intemet e-mail to The CCW System (CCWS) is a closed loop cooling system that provides cooling water for systems and components important to safety. The CCWS transfers its heat load to the SWS via heat exchangers. The SWS is a once through cooling system that transfers its heat load. to the ultimate heat sink (Hudson River). The CCWS consists of three pumps and two heat exchangers. These components are divided into two independent, full capacity cooling loops with each loop consisting of one pump and one heat exchanger.

The principal safety related function of the CCW System is the removal of decay heat from the reactor via the Residual Heat Removal (RHR) System during a normal or post accident cooldown and shutdown. The design basis of the CCW System is for one CCW train to remove the post loss of coolant accident (LOCA) heat load from the containment sump during the recirculation phase of a LOCA.

An extent of condition (EOC) review determined that the copper-nickel to carbon steel dissimilar weld configuration is unique to the 21 and 22 CCW HX inlet and outlet SW piping. The 31 and 32 CCW HX inlet and outlet nozzles are rubber-lined carbon steel flanged piping and are not susceptible to the same failure mechanism. CCW HX SW piping weld EOC inspections at five similar locations were completed. No, new problems or degraded conditions were identified.

CAUSE OF EVENT

The direct cause was recurring longitudinal solidification cracks that developed during welding of copper-nickel to carbon steel pipe. The primary degradation mechanism leading to the November '30, 2015 leak Was likely crevice corrosion, caused by small holidays in the internal coating at the field weld that allowed SW to contact the internal piping base metal. The corrosion promoted thinning in the affected area, which resulted in the development of a pin hole at the weakened toe of the carbon steel elbow to copper-nickel inlet nozzle field weld on the carbon steel. Surface exams performed during the RO repairs did not identify any defects. However, potential subsurface flaws would not be detected using the surface exam technique.

During the RO and the June 2016 post outage repair work, repairs to the leaking indication initially used ERCuNi filler metal to restore the weld integrity. This method resulted in strain-induced longitudinal cracking in the highly restrained joint due to the relatively low tensile strength of the material, its thermal conductivity differences with carbon steel, and its susceptibility to iron dilution from steel, which can increase the tendency for brittle fracture.

Standard industry practices to reduce cracking tendencies prior to joining dissimilar metals with filler material were not identified in the repair plan.

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 intemet e-mail to The apparent cause was that the team assigned to prepare and execute the weld repair plan failed to ensure all risks and issues were identified and managed properly.

This apparent cause resulted in this condition because risks were not identified and work planning and scheduling did not include effective contingencies or back-out criteria. Key team members contributing to work preparations did not effectively perform their roles and responsibilities. There was inadequate preparation and lack of rigor during planning and challenge reviews for the critical work activity.

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 vendor (PCI) qualified a new copper-nickel to carbon steel weld procedure using a different filler metal (ERNiCu-7) with better performance characteristics based on industry best practices. An Engineering Change (EC) was developed to eliminate the weld stresses that were contributing to the observed in-process weld cracking. The defective weld and degraded piping section was cut out and replaced with a flush welded patch according to the new EC using the new filler metal (ERNICu-7) and the newly qualified vendor (PCI) welding procedure. All welds were inspected according to the code-required visual and surface examinations. The completed weld was leak tested and the 21 CCW HX returned to service.
  • The lessons learned from this event were discussed at the work week critique and were communicated site-wide during all-hands meetings and through distribution of the weekly newsletter. The message reinforced standards and expectations for ensuring readiness.
  • A System Outage Critique will be performed in accordance with EN-FAP-WM-003 to communicate lessons learned with individuals involved with the weld repair outage.
  • Incorporate recommendations for improving risk management process effectiveness by incorporating actions taken in response to INPO IER L2-16-9 Revision 0.

EVENT ANALYSIS

The event is reportable under 10CFR50.73(a)(2)(i)(A). The licensee shall report the completion of any nuclear plant shutdown required by the plant's Technical Specification (TS). The event meets the reporting requirement because on June 24, 2016, at 04:00 hours, operations implemented actions to commence reactor shutdown to comply with TS 3.7.7 (CCW System).

Indian Point 2 05000-247 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 intemet e-mail to TS 3.7.7 LCO requires two CCW trains to be Operable. TS 3.7.7 Condition A (One CCW train inoperable) required action A.1 is to restore the inoperable CCW train to operable within 72 hours. TS 3.7.7 Condition A was entered on June 21, 2016, at 02:30 hours, when the 21 CCW HX was declared inoperable for scheduled maintenance.

On June 24, 2016, at 04:00 hours, the TS 3.7.7 AOT window expired forcing a unit shutdown to comply with TS 3.7.7 Condition B which requires the plant to be in Mode 3 within 6 hours and Mode 4 within 12 hours. On June 24, 2016, at 7:59 hours, a manual reactor shutdown was completed and the plant entered Mode 3. At 12:58 hours, the plant entered Mode 4. On June 24, 2016, at 04:05 hours, a four hour non-emergency notification was made to the NRC (Log Number 52039) for a TS required shutdown. On June 26, 2016, at 14:11 hours, the 21 CCW HX was declared operable and TS 3.7.7 Condition B exited. Operations commenced plant start-up. Unit entered Mode 1 on June 27, 2016, at 15:01 hours. The event was recorded in the Indian Point Energy Center corrective action program (CAP) as CR-IP2-2016-04118.

PAST SIMILAR EVENTS

A review of the past three years of Licensee Event Reports (LERs) for events that involved a TS required shutdown due to faulty SW pipe repair. No applicable LERs were identified.

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 events impacting redundant components.

There were no significant potential safety consequences of this condition. The CCW System provides a heat sink for the removal of process and operating heat from safety related components during a design basis accident (DBA) or transient. The CCW System consists of three pumps and two heat exchangers. The CCW pumps are connected to a common discharge header that is arranged so that any of the three pumps will supply either CCW heat exchanger and the heat exchangers are connected to a common discharge header so that both heat exchangers supply all CCW System heat loads. Any one of the three CCW pumps in conjunction with any one of the two CCW heat exchangers is sufficient to accommodate the normal and post-accident heat load. For this event one CCW Heat Exchanger was removed from service to perform a weld repair. The remaining redundant CCW HX and associated components were operable and available to perform their safety function.

A risk evaluation was performed to estimate the increase in core damage probability (CDP) and large early release probability (LERP) using a baseline zero maintenance plant configuration and the 21 CCW HX outage time of 5 days. The results of the risk evaluation concluded the risk impact associated with the inoperability of the 21 CCW Heat Exchanger is non-risk significant per NRC Regulatory Guide 1.177 (i.e., the increase in CDP is less than 1E-6/year and the increase in LERP is less than 1E-7/year) Indian Point 2 05000-247 Na

05000247/LER-2016-0079 August 2016Indian Point

On June 20, 2016, Entergy management was advised by the NRC that during a tour in containment while the unit was in Mode 4, the inspector identified two open barrier gates for the Emergency Core Cooling System (ECCS) sump.

Personnel were moving scaffolding from inside the crane wall to areas outside the crane wall through the two open barrier gates. Having both sump barrier gates open violated ECCS operability basis which requires the sump barrier system to be operable in Modes 1-4.

The inspector notified the operator touring with him of the observation. The operator subsequently coached the Radiation Protection (RP) door guard to ensure that one of the gates be closed at all times. The apparent cause was a latent organizational weakness associated with the use of procedure OAP-007 (Containment Entry and Egress) which had not been communicated well within the organization.

The failure mode was personnel not being aware of all available information.

The scaffold supervisor was not aware of his requirement to serve as containment coordinator and provide the required briefing on gate closure. The RP brief was focused on the locked high radiation requirements not gate control. Corrective actions included closing and securing one gate, briefing RP personnel on the event, the lessons learned and management expectations. This event will be included in all 3R19 supplemental supervisors qualifications required reading list. Procedure OAP- 007 will be revised to include a checklist for entry briefings to include GS-191 requirements. The event had no significant effect on public health and safety.

Indian Point 2 05000-247 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 intemet e-mail to Note: The Energy Industry Identification System Codes are identified within the brackets ().

DESCRIPTION OF EVENT

On June 20, 2016, Indian Point management was advised by the NRC that during a tour in containment (NH) while the unit was in Mode 4, the inspector identified two open barrier gates for the Emergency Core Cooling System (ECCS) (BQ) sump. Personnel were removing disassembled scaffolding from inside the crane wall on the 46 foot elevation of containment and moving it through the ECCS sump barrier gates (GATE) to areas outside the crane wall through the two open barrier gates. Having both sump barrier gates open violated ECCS operability basis which requires the sump barrier system to be operable in Modes 1-4. The plant had entered Mode 4 on July 10, 2016, at 23:30 hours. The inspector notified the operator touring with him of the observation. The operator subsequently coached the Radiation Protection (RP) door guard to ensure that one of the gates were closed at all times. No condition report recorded the event at the time. Subsequently, on June 20, 2016, after an NRC inspector advised a site manager the condition was recorded in the Indian Point Energy Center (IPEC) Corrective Action Program (CAP) as Condition Report CR-IP2- 2016-04036. On June 21, 2016, CR-IP2-2016-04037 recorded the failure to initiate a CR at the time of the event.

For postulated breaks in the Reactor Coolant System (RCS) (AB) there are two recirculation related sumps within the containment, 1) the Recirculation Sump and, 2) the Containment Sump. Both sumps collect liquids discharged into the containment during a design basis accident. As part of the resolution of Generic Safety Issue (GSI)-191 (Assessment of Debris Accumulation on PWR Sump Performance) and Generic Letter 2004-02 (Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at Pressurized Water Reactors) various flow barrier debris interceptors were installed in the containment to channel the recirculation flow into the reactor cavity sump area, up and out of the Incore Instrumentation Tunnel, through the crane wall and containment sump labyrinth wall via specially designed openings, and into the annulus area outside the crane wall.

The recirculation flow will migrate towards the Recirculation Sump or the Containment Sump depending on which pump(s) are operating. Flow channeling barriers are installed on the Reactor Cavity Sump around the Incore Instrumentation Tunnel, on the Recirculation Sump trenches, and at the Containment Sump. Flow channeling barrier gates are installed in the northeast and northwest quadrant openings of the Crane Wall. In addition, flow channeling barrier gates are installed in the north and south entrances to the Recirculation Sump area. There is one dual access gate (gates 17 and 23) to allow access without violating the flow barrier integrity during transient through the flow barrier system.

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 intemet e-mail to Investigation of the event determined that the scaffold work group was the largest group within containment during the time the scaffold job on the 46 foot elevation was being worked. In accordance with procedure OAP-007 (Containment Entry and Egress) the scaffold group was to assume the role of containment coordinator and be responsible for performing a containment entry briefing. However, instead of providing a containment entry briefing, a regular or standard HU pre-job brief was given to the scaffold workers by their contractor supervisor. Because the area being worked was a radiation controlled area the scaffold workers then met with Radiation Protection (RP) personnel at the Health Physics access (HP1) for a Locked High Radiation Area (LHRA) RP pre-job brief. The RP brief included discussion that one of the ECCS barrier gates had to be closed at all times per GSI-191 and OAP-007 requirements. The job also required an RP door guard whose only function was to ensure that anyone entering into the inside crane wall had to have an HP individual with them. There was no ECCS barrier gate monitor assignment as required by OAP- 007. As work progressed the scaffold workers left both ECCS barrier gates open to enhance removal of scaffold material to storage. Although the scaffold workers were told during the RP briefing that one ECCS barrier gate must remain closed at all times, it was discovered in interviews with workers that they thought that none of the other gates could be opened while they were using their gate location to remove scaffold.

It was determined that the supplemental scaffold supervisor was not aware of a specific entry procedure that was required to be used prior to a containment entry.

A specific OAP-007 procedure containment entry brief was not given to the workers nor were they and their supervisor aware of the procedure. The supplemental scaffold group supervisor stated that in previous containment entries he and his group were never the main group going into containment so they were always briefed by operations or RP and didn't recall using OAP-007. Procedure OAP-007 is specifically written to cover many aspects of containment entries. The procedure contains sections and steps discussing the ECCS barrier gates with diagrams of the crane wall and all of the gates with their locations and numbers. If the procedure had been used in addition to a pre-job and RP brief, the requirements would have been clearer to the workers and this event most likely would not have occurred.

An extent of condition (EOC) review was performed and it determined that both units are similar and both would be vulnerable in an event if there was a direct flow path for accident debris to enter the containment/internal recirculation sump. The condition is bounded by the crane wall gates as these are the only types of gates in the containment installed in the crane wall that protect the ECCS sumps from debris.

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 intemet e-mail to

CAUSE OF EVENT

The apparent cause was a latent organizational weakness associated with the use of procedure OAP-007 (Containment Entry and Egress) which had not been communicated well within the organization. The failure mode was personnel not being aware of all available information. The scaffold supervisor was not aware of his requirement to serve as containment coordinator and provide the required briefing on gate closure. The RP brief was focused on the locked high radiation requirements not gate control.

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:

  • Dual gates were closed and applicable gate secured. The RP door guard was coached on requirement to have at least one gate closed and secured at all times.
  • A HU meeting was held and interviews conducted with the work crew, supervisor and RP personnel and the requirements of OAP-007 were reviewed and requirements of the ECCS barrier reinforced.
  • A Department Clock Reset/Yellow memo was prepared and the lessons learned on the event and management expectations communicated with Projects organizations, all site departments, and the Fleet.
  • The event will be included in all 3R19 supplemental supervisors qualifications required reading list.
  • Procedure OAP-007 will be revised to include a checklist for entry briefings to include GS-191 requirements.

EVENT ANALYSIS

The event is reportable under 10CFR50.73(a)(2)(v)(D) as a safety system functional failure as the condition could have prevented adequate post accident core cooling due to DBA debris blockage of the recirculation and/or the containment sump. An ECCS train is inoperable if it is not capable of delivering design flow to the RCS.

Individual components are inoperable if they are not capable of performing their design function or supporting systems are not available. Technical Specification (TS) 3.5.2 (ECCS-Operating) requires three ECCS trains to be operable in Modes 1, 2 and 3, and TS 3.5.3 (ECCS-Shutdown) requires one ECCS residual heat removal (RHR) subsystem and one ECCS recirculation subsystem to be operable in Mode 4.

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 intemet e-mail to Indian Point 2 05000-247 The licensing and design basis of the ECCS per UFSAR Section 6.2.2 (ECCS System Design and Operation) credits flow channeling barriers installed in containment in response to the resolution of GL-2004-02. The two flow barrier gates that were used for removing scaffolding were not closed and secured to prevent it from being forced open during a DBA. The unsecured gates were not in accordance with design and not a sufficient robust barrier to prevent debris from entering the recirculation and containment sumps had a DBA occurred while in Mode 4. The condition is also reportable under 10CFR50.73(a)(2)(vii) (common cause inoperability of independent trains or channels) as the condition caused at least one independent train or channel to become inoperable in multiple systems or two independent trains or channels to become inoperable in a single system designed to (D) mitigate the consequences of an accident. The NRC inspector tour occurred during the time the unit was in Mode 4. The unit entered Mode 4 on June 10, 2016, at 23:30 hours. However, no CR was initiated for this condition at that time. CR- IP2-2016-04037 recorded that condition that while performing a walkdown with an NRC inspector on June 11, 2016, the NRC raised a question about an activity in the field and no condition report was initiated.

PAST SIMILAR EVENTS

A review was performed of the past three years of Licensee Event Reports (LERs) for events that involved SSFFs and/or common cause inoperability of an Engineered Safety Feature System that had a similar cause. No LERs were identified at Unit 2.

A review of all reported events during the past three years at both units identified one LER at Unit 3 that was similar. Unit 3 LER-2013-002 reported on April 29, 2013, a Safety System Functional Failure and Common Cause Inoperability of the Emergency Core Cooling System due to violation of containment sump debris barrier integrity. The LER reported that on March 4, 2013, during shutdown for a refueling outage, Radiation Protection (RP) personnel entered the reactor containment building to install plastic RP fencing for the Reactor Coolant Drain Tank (RCDT). After receiving clearance at Mode 4 to enter the Inner Crane Wall (ICW) to install fencing around the RCDT and post it as a Locked High Radiation Area (LHRA). The RP work crew assumed they could enter the ICW area through any sump barrier gate for the Emergency Core Cooling System (ECCS). The RP work crew chose to use a single gate access point due to its proximity to the RCDT.

Subsequently, a RP Technician identified that personnel had not entered the area using the double access gate and had brought in plastic fencing which was inappropriate material for the sump area. The apparent causes were an inadequate pre-job brief and inadequate procedure for Containment Entry and Egress (OAP-007, 0-RP-RWP-405) due to poor change management. The pre-job brief failed to cover the requirement to use the dual sump barrier gate access point when in Modes 1-4, nor did it address the type of fencing allowed. Corrective actions included revision of Procedure OAP-007 to clearly state that within the procedure's attachments that only the sump barrier dual access gate for 46 foot Containment ICW entries shall be used in Modes 1-4.

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 intemet e-mail to The revision specified the use of the double entry gate and that one gate is to remain shut and secured at all times. Securing the gates at unit 3 which uses a slide latch does not state the use of a gate monitor. The step for Unit 2 includes statements that the gates be secured with a padlock or nut and bolt closure from the outside. This condition requires posting of a gate monitor to allow exit.

SAFETY SIGNIFICANCE

This event had no significant effect on the health and safety of the public. There were no actual safety consequences for the event because there were no accidents or transients during the time of the event. The analysis performed in response to GL- 2004-02 included debris transport analysis conservatisms for transport of debris to both the IR sump and the Containment sump in excess of quantities that would be generated. Establishing normal RHR cooling to the RCS has RCS temperature below 350 degrees F and pressure less than 400 psig.

In Mode 4 the reactor is not critical and reactivity is stable. In Mode 4 there is significantly less energy in the RCS to generate debris. At the time the actual RCS pressure (pressurizer pressure) was approximately 355 psig. An evaluation of a LOCA during Mode 3 and 4 operation was performed by Westinghouse (WCAP-12476) that showed a direct reduction in break probability for Mode 4. The evaluation concluded that Mode 4 LOCAs are not a significant contributor to shutdown risk.

During this event the entire flow barrier was not disabled because only two debris barrier gates were unsecured and only for the time scaffold workers were allowed to perform assigned work. The exact time the gates were open cannot be determined as the barrier gates have no electronic timing devises. However, the scaffold workers were assigned three entries with stay time limitations for heat stress of 45 minutes each for a total job time of 135 minutes. The scaffold work assignment took place in Mode 4. The unit entered Mode 4 on June 10, 2016, at 23:30 hours.

For the first two of three entries, the scaffold workers had to go inside the crane wall and disassemble erected scaffolding. Per the scaffold supervisor at least one door was closed during scaffold disassembly. Therefore approximately 60 minutes were left for moving disassembled scaffolding from inside the crane wall through the open gates to the outside crane wall storage areas. Therefore most debris would have been intercepted by the flow barrier system. Also, the barrier gates swing into the crane wall so that DBA flow and forces would tend to close the gate when pressure is applied (e.g., DBA debris loads) therefore limit flow barrier bypass and sump debris loading.

05000286/LER-2015-0068 August 2016Indian Point

On July 1, 2015, Engineering was notified by

  • Wyle Laboratories that two of three Pressurizer Code Safety Valves (RC-PCV-464 and RC-PCV-468) were outside their As-Found lift set point test acceptance criteria (2411 - 2559 psig).

The As-Found set pressure testing acceptance criterion for operability is 2485 +/-3%. The SVs were removed during the last refueling outage (RO) in the spring of 2015 and sent offsite for testing.

Testing was performed within one year of removal as required by the Inservice Testing Program. SV RC-PCV-464 lifted at 2573 psig and SV RC-PCV-468 lifted at 2379 psig which is outside their set pressure range. The remaining SV tested satisfactorily. All three SVs were found with zero seat leakage. During the RO all'three SVs were removed and replaced with certified pre-tested spare SVs.

The SVs installed during the RO were As- Left tested to 2485 +/-1% with zero seat leakage in accordance with procedure 3-PT-R5A.

Technical Specification (TS) 3.4.10 (Pressurizer Safety Valves), requires three pressurizer safety valves to be operable with lift settings set at greater than 2460 psig and less than 2510 psig.

TS Surveillance Requirement (SR) 3.4.10.1 requires each PSV to be verified operable in accordance with the Inservice Testing Program.

The valves were disassembled and internals inspected. The most probable cause of SV RC-PCV-464 lifting greater than 3% of its nominal setpoint was setpoint drift. The most probable cause of RC-PCV-468 lifting below 3% of its nominal set point was set point drift. Corrective actions included replacement of all three code safeties with pretested spares and disassembly and inspection of valves RC-PCV-464 and RC-PCV-468. The event had no effect on public health and safety.

05000286/LER-2014-0041 August 2016Indian PointOn August 13, 2014, Instrumentation and Control (I&C) technicians started performance of an 8-hour scheduled surveillance 3-PC-OLO4A (Pressurizer Pressure Loop P-455 Channel Calibration) with Loop I in test and tripped. The test was approved by I&C and operations to be stopped for a break with the bistables still tripped, Channel I in test. During the break, an automatic reactor trip (RT) occurred as a result of meeting the trip logic for Overtemperature Delta Temperature (OTDT). All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The Auxiliary Feedwater System automatically started as expected due to SG shrink effect. No work was being performed at the time of the RT and no actual OTDT existed. The direct cause of the RT was a spurious signal spiking on channel 3 of the OTDT circuitry with another channel tripped for testing. The two possible root causes were 1) a random failure of the OTDT static gain unit (Foxboro Integrator/Converter module QM-431D), 2) loose wiring connection on distribution block DB-4 (output of static gain unit QM-431) due to workmanship issue. Corrective actions included replacement of static gain module QM- 431D and associated PR N-43 isolation amplifies NM306 and NM307, and static gain modules QM-421D, and QM-411D, replacement of three OPDT trip bistables (TC-421 A/B, TC-431 A/B, TC-441 A/B), replacement of setpoint module TM-432B (other setpoint modules had been previously replaced), and replacement of Loop 3 T(avg) E/I converter TM-432R. Procedure IP-SMM-WM-140 revised to include expectation on minimizing break times when a channel is tripped. The event had no effect on public health and safety.
05000247/LER-2016-00431 May 2016Indian Point

During a scheduled refueling outage that commenced on March 7, 2016, an inspection of the reactor vessel internals that is required by MRP-227-A was performed. As a result of the inspection, 227 baffle-former bolts were identified to have either visual anomalies or ultrasonic indications or could not be examined by ultrasonic testing. A visual inspection of the baffle-former plates and edge bolts showed no discernible material degradation or distortion. All other MRP-227-A inspections of the reactor vessel internals showed no other failures or premature degradation.

The root cause of the failed baffle-former bolts is primarily Irradiation Assisted Stress Corrosion Cracking (IASCC) in combination with applied stresses and fatigue loads. Failure analyses will be conducted to confirm the cause for the degradation - of the baffle-former bolts.

At the time of discovery, the unit was in a safe and stable condition with all fuel removed from the reactor vessel. The event had no impact on public health and safety.

05000247/LER-2016-00525 May 2016Indian Point

On March 26, 2016, during a refueling outage, an NRC inspector identified that the trip of the MBFPs is not tested in accordance with Technical Specification 3.7.3 (Main Feedwater System) Surveillance Requirement (SR) 3.7.3.3.

This was discovered as a result of an assessment of the failure of the Main Boiler Feedwater Pumps (MBFPs) steam stop valves to close after the reactor trip on December 5, 2015.

  • TS SR 3.7.3.3 requires testing the MBFP trip function every 24 months on an actual or simulated actuation signal.

Surveillance tests 2-PT-V024DS60 .and 2-PT-V24DS61 are performed every 24 months, but only test up to the limit switch contact that actuates the MBFP turbine.trip solenoid valves and does not include the trip of the pump. A review determined the requirement to verify the trip of the MBFPs was added to the TS during the implementation of the improved TS (ITS) conversion program in 2004 but the corresponding testing was not added to the surveillance tests.

The direct cause was human error for failure to ensure testing was established to meet new ITS„SRs. The apparent cause of the error is indeterminate due to the time passed since TS conversion by Amendment 238 on November 21, 2003. Corrective actions include revision of Surveillance tests 2-PT-V024DS60 and 2-PT-V24DS61 to test tripping of the MBFPs. The MBFPs will be tested per the revised procedures prior to startup from the. outage. The event had no significant effect on public health and safety.

05000247/LER-2016-0036 May 2016Indian Point

On March 7, 2016, during a refueling outage the control switch for the 21 Main Boiler Feedwater Pump (MBFP) was positioned to trip and the 21 MBFP tripped as designed but the MBFP discharge valve BFD-2-21 failed to fully close. MBFP discharge valve BFD-2-21 was declared inoperable and Technical Specification (TS) 3.7.3 (Main Feedwater Isolation) Condition C (One or both MBFP discharge valves inoperable) was entered. Troubleshooting on the valve determined the close torque switch contact finger was out of position within the contact holder. This misalignment allowed the contact finger to move out of the proper position causing Motor Operated Valve (MOV) BFD-2-21 to fail to close.

Direct cause was valve BFD-2-21 close torque- switch was out of position. The apparent cause was the MOV preventive maintenance procedure lacked the level of detail and direction to provide the appropriate guidance to recognize the susceptibility associated with the orientation of the close torque switch contact finger bracket opening and spreading of the "U" shape bracket. Corrective actions included replacement of the defective torque switch, inspection and testing. A case study from this event will be developed and included in the continual ESP training. The adequacy of the guidance on work instruction on the arrangement/alignment of the contact "U" shape brackets will be evaluated and the necessary guidance provided. The event had no significant effect on public health and safety.

NRC FORM366AU.S. NUCLEAR REGULATORY COMMISSION FACILITY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3) Note: The Energy Industry Identification System Codes are identified within the brackets a.

DESCRIPTION OF EVENT

On March 7, 2016, at approximately 00:10 hours, during plant shutdown for refueling outage cycle 22, while in Mode 3 (Hot Standby), the control switch (33) for the 21 Main Boiler Feedwater Pump (MBFP) (SJ) was positioned to trip and the 21 MBFP tripped as designed but the MBFP discharge valve BFD-2-21 (ISV)failed to close. Operations observed a duel light indication for BFD-2-21 valve position on Control Room Panel FAF identifying the valve failed to fully close. MBFP discharge valve BFD-2-21 was declared inoperable and Technical Specification (TS) 3.7.3 (Main Feedwater Isolation) Condition C (One or both MBFP discharge valves inoperable) was entered. TS 3.7.3 Required Action C.1 is to close or isolate the MBFP discharge valves within 72 hours,.

and C.2 verify MBFP discharge valves are closed or isolated once per 7 days. At 3:15 hours, valve BFD-2-21 was manually closed and de-energized then cracked open 20 hand wheel turns off its seat'to eliminate. thermal binding concerns. The condition was recorded in the Indian Point Energy Center (IPEC) Corrective Action Program (CAP) in Condition Report CR-IP2-2016-01236.

On March 7, 2016, troubleshooting commenced at approximately 19:47 hours, to determine the cause of the valve BFD-2-21 failure to close. On March 9, 2016, during .

troubleshooting.of'valve BFD-2-21, when the limit switch compartment cover was removed the close torque switch contact finger was found slipped out of position within the contact holder. Inspection of the failed torque switch identified that the "U" shaped contact holder was slightly bent 'or spread open and the tabs at each end of the holder were not parallel with each other. Engineering concluded this misalignment would allow the contact finger to have free play within the contact holder. Excessive free play within the contact holder contributed to the contact finger moving out of the proper position. In addition, the orientation and arrangement of BFD-2-21 actuator/torque switch is such that

  • the opening in the contact holder is angled slightly downward.

This orientation would make it easier for the contact finger to slip out of the gap.

On March 9, 2016, the torque switch was replaced and the valve stroke tested satisfactory. Discussions were held with the original torque switch manufacturer (Limitorque) (OEM) and they recommended that during installation of the new torque switch specific additional inspections be performed and the Indian Point MOV preventive maintenance (PM) procedure be enhanced. Limitorque also recommended an enhancement which could provide a' heavier duty compression spring (located under the contact finger) which would aid in preventing recurrence of this type failure. After a major PM on the valve, inspections' and diagnostic testing were performed to monitor torque switch operation and proper torque switch contact holder assembly.

The closed circuit for motor operated valve (MOV) BFD-2-21 is supervised by"limit switch 8. Limit switch 8 (LS8) is set to open and de-energize the motor after the valve disc contacts the valve seat (closed position). The closed torque switch is in series with the close LS8 and provides mechanical overload protection. The closed torque switch is set high enough so that normal operation of BFD-2-21 will not cause its contacts to open. The closed torque switch is bypassed using Limit Switch 9 (LM9) for the first two seconds of the closing stroke. This ensures full motor capability is available to start the valve close which will initiate the trip signals to the MBFPs.

After two seconds the close torque switch bypass is out of the circuit and the valve will continue to close until either LS8 or the Close torque switch contacts opens.

The MBFP discharge valve BFD-2-21 is a motor operated gate valve with a torque switch, model number SMB-3 (actuator) manufactured by Limitorque (L200) (Flowserve)-

  • -part number 11501-042 (Torque switch)'(33). "

Corrective Actions

The following corrective actions have been or will be performed under Entergy's.

Corrective Action Program to address the cause and prevent recurrence:

  • The defective torque switch was replaced and BFD-2-21 and BFD-2-22 were inspected and tested.
  • MBFP 22 discharge valve BFD-2-22 was inspected and a Work Order implemented to validate BFD-2-22 was acceptable.
  • The remaining population of motor operated valves (MOVs) will be evaluated for a similar condition.
  • A case study from this event will be developed and included in the continual ESP training.
  • The adequacy of the guidance on work instruction on the arrangement/alignment of the contact "U" shape brackets will be evaluated and the necessary guidance provided to either the fleet procedure (EN-MA-141) or the Work Program (Asset Suite.

Event Analysis

The event is reportable under 10 CFR 50.73(a) (2)(i)(B). The licensee shall report any operation or condition which was prohibited by the plant's TS. This condition meets the reporting criteria because TS 3.7.3 (Main Feedwater System) requires the two MBFP discharge valves and the trip function to be operable. TS 3.7.3 Condition C (One or both MBFP discharge valves inoperable) required action C.1 is to close or isolate MBFP discharge valve within 72 hours and C.2 verify MBFP discharge valve is closed or isolated once per 7 days. As a result of discovering on March 7, 2016, that MBFP discharge valve BFD-2-21 would not close and that would not haVe closed upon demand due to a failed torque switch, TS 3.7:3 Condition C was not met. Valve BFD-2-21-was last demonstrated operable on December 5, 2015, when there was a reactor trip and no reported issue with valve closure.

There was no safety system functional failure reportable under 10 CFR 50.73(a)(2)(v).

The MBFP discharge valve BFD-2-22 for the 22 MBFP was operable and isolation of Main FW from the 21 MBFP could have been accomplished in accordance with TS Basis 3.7.3.a by closure of the Main FW Regulating Valves (MFRVs), trip of the MBFPs, and the closure of all four Low Flow Main FW Bypass Valves (FBVs).

Past Similar Events

A review was performed of the past three years of Licensee Event Reports (LERs) for events reporting a TS violation due to inoperable MBFPs. No LERs were identified.

Safety Significance

This event 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.

Isolation of the main FW system is necessary to mitigate accident and transient conditions (Main Steam Line Breaks (SLB), SG Tube Ruptures, and Excessive Heat Removal Due to FW System Malfunction). Main FW must be isolated to prevent excessive reactor coolant system cooldown, containment overpressure, and steam line overfill. Main FW isolation is initiated by either an Engineered Safety Feature Actuation System (ESFAS) safety injection (SI) signal or a high steam generator water level signal. Main FW isolation to all four SGs is provided by either 1) Closure of all four main FW regulating valves (MFRVs) and all four Low Flow Main FW Bypass Valves (FBVs), or 2) Closure of both MBFP discharge valves which initiates closure of all eight FW Isolation Valves (MFIVs), and the trip of both MBFPs. Either of these combinations is capable of achieving main FW isolation to all four SGs within the time limits assumed in the accident analysis. If all eight valves referenced in item 1 close, main FW isolation to all four SGs is completed within time limits that satisfy accident analysis assumptions. To establish redundancy for main FW isolation safety function, the SI ESFAS or High SG Level signal also provides a direct signal- that closes the two MBFP discharge valves. When both MBFP discharge valves move off the open seat, the relay actuates and generates a signal that initiates closure of the four main FW isolation valves (MFIVs) and the four Low Flow FIVs. For this event, all FW isolation capabilities were operable except the 22 MBFP discharge valve BFD-2-21. This event was bounded by the analyzed event described in FSAR Section 14.1.10, (Excessive Heat Removal Due to Feedwater System Malfunctions). Excessive FW additions is an analyzed event postulated to occur from a malfunction of the FW control system or an operator error which results in the opening of a FW control valve. The analysis assumes one FW valve opens fully resulting in the excessive FW flow to one SG. For the FW system malfunction at full power, the FW flow resulting from a fully open control valve is terminated by the SG high level signal that closes all FW control valves and trips the MBFPs. The SG high water level signal also produces a signal to trip the main turbine which initiates a reactor trip. The analysis for all cases of the excessive FW addition initiated at full power conditions with and without automatic rod control, show that the minimum DNBR remains above the applicable safety analysis DNBR limit. In the case of excessive FW flow with the reactor at zero power, the resulting transient is similar to, but less severe than the hypothetical steamline break transient and is bounded by the analysis in UFSAR Section 14.2.5 (Rupture of a Steam Pipe).

05000247/LER-2016-0012 May 2016Indian Point

On March 4, 2016, during the performance of surveillance procedure 2-PT-R006, Main Steam Safety Valve (MSSV) MS-45B failed to lift within the Technical Specification (TS) as- ' found required range of +/- 3% of the setpoint pressure. Valve MS-45B lifted at 1125 psig, 29 psig outside its acceptance range of 1034 to 1096 psig and 5.7% above its 1065 psig setpoint. The valve was declared inoperable, then subsequently restored to operability upon two successful lifts within the required setpoint range without the need for adjustment. Nine other MSSVs that were tested lifted within the as-found required setpoint range. The apparent cause for the failure was internal friction due to spindle rod wear, which causes the spindle rod to bind against internal components.

Corrective actions were modification of MS-45B and twelve other MSSVs, and the replacement of their spindle rods. The event had no effect on public health and safety.

05000247/LER-2015-00418 February 2016Indian Point

On December 20, 2015, operator investigations identified service water (SW) leakage in containment and on December 22, 2015 discovered a through wall leak on a socket welded elbow for the 21 Fan Cooler Unit (FCU) motor cooler SW 2 inch copper-nickel return line.

The leak was located in a pipe fitting that is within the ASME Section XI Code ISI Class 3 boundary and estimated to be

  • approximately-1 gpm.

Since the pipe flaw was through wall and was located within the ASME Section XI boundary, it exceeded the flaw allowable limits provided per IWD-3000. Engineering determined that since the through wall flaw was located on a socket welded fitting, the ASME Code Case N-513-3 did not apply.

The 21 FCU was declared inoperable and Technical Specification (TS) 3.6.6 (Containment Spray and Containment FCU System), entered for one FCU train inoperable and TS 3.6.1 Condition A entered for containment inoperable.

The 21 FCU SW return line was isolated.

The pipe is part of a closed loop system inside containment and is required to meet containment integrity. Since a containment leakage evaluation was not performed, the pipe flaw -was conservatively assumed to result in post-accident containment out leakage in excess of the 10CFR50, Appendix J limits resulting in violation of the containment integrity requirements and therefore is a safety system functional failure.

The direct cause was flow assisted erosion-corrosion. The apparent cause was high SW flow conditions that caused high localized velocities and flow separation at the sharp interior edge of the socket welded fitting.

Corrective actions included replacement of the affected fitting.

The faulted fitting was sent out to a vendor for metallurgical failure analysis.

The procedure for FCU SW flow balanced will be revised to reduce the SW flow in FCU motor coolers. The event had no significant effect on public health and safety.

FACILITY NAME (1) PAGE (3) DOCKET (2) LER NUMBER (6)

05000247/LER-2015-0033 February 2016Indian Point

On December 5, 2015, control room operators initiated a manual reactor trip (RT) after observing indications consistent with multiple dropped control rods (CR) following an alarm for the trip of Motor Control Center (MCC)-24/24A. No Control Rod indication was available due to MCC-24 being de-energized. All primary safety systems functioned properly except the primary rod control cabinet power supply (PS1) which was in a degraded condition prior to the event and failed to function as required. The plant was stabilized in hot standby. There was no radiation release. The Auxiliary FW system automatically started as designed. The direct cause of the event was loss of MCC-24 due to an internal fault at the line side leads at cubicle 2H where they connect to the bucket stab assemblies (load side fault). This caused the supply breaker feed to open per design and clear the fault. The de-energization of MCC-24 removed the functioning backup Control Rod (CR) power supply and the remaining degraded primary power supply failed to function as required. The apparent cause was an unanticipated loss of power to the CR system due to the degradation of the primary CR power supply (PS1) which failed to function when the operating power supply (PS2) was lost. MCC-24/24A was lost due to a design error that allowed the positioning of a mounting plate too'close and obstructing the line side wiring resulting in contact. Vibration over time resulted in degraded wiring insulation which eventually shorted. Corrective actions included inspection and testing of the MCC-24 bus and control wiring. The degraded Rod Contrl power supply (PS1) was replaced. Maintenance procedures will be revised to provide more in-depth inspection criteria. The event had no effect on public health and safety.

FACILITY NAME (1) PAGE (3) DOCKET (2) LER NUMBER (6)

05000247/LER-2015-00219 October 2015Indian Point

On August 18, 2015, the operations shift manager entered Technical Specification (TS) 3.0.3 upon determination that the Residual Heat Removal (RHR) heat exchanger outlet valves (MOV-746 and MOV-747) would not remain operable during a degraded voltage (DV) condition. RHR heat exchanger outlet valves MOV-746 and MOV-747 are normally closed therefore their failure would result in both trains of RHR becoming inoperable.' The RHR outlet valves are required to open during a Design Basis Accident for the RHR system to perform its safety function. As a result of NRC inspector questioning, an evaluation of the electrical coordination calculations associated with fuses for MOV-746 and MOV-747 determined the fuses would not support continued operability during a DV condition. The fuses were replaced with fuses that would remain operable under DV conditions and the RHR trains restored to operable status.

Direct cause was the electrical coordination calculations for MOV-746 and MOV-747 did not support operability during a DV condition.

The apparent cause was that the Industry Operating Experience (OE) (prior NRC violations and findings) was not properly acted upon during the Focused Self-Assessment on CDBI Preparations due to an incorrect assumption.

Corrective actions included replacement of fuses, and communication to engineering personnel of the lessons learned from the event.

Initiated CR-IP2-2015-03725 recording NRC 2015 CBDI Item 103 and CR-IP2-2015-03702 recording NRC 2015 CBDI Item 104 to addresses. EOC findings and calculation updates which will be processed via Engineering Changes. The event had no significant effect on public health and safety.

NRC FORM 366AU.S. NUCLEAR REGULATORY COMMISSION FACILITY NAME (1) DOCKET (2) LER NUMBER (6) Indian Point Unit 2 05000-247 Note: The Energy Industry Identification System Codes are identified within the brackets (1.

DESCRIPTION OF EVENT

On August 18, 2015, while at 100% steady state reactor power, the operations shift manager entered Technical Specification (TS) 3.0.3 at 13:31 hours, upon determination that the Residual Heat Removal (RHR) (BP) heat exchanger fHX1 outlet valves (MOV-746 and MOV-747) (ISV) would not remain operable during a degraded voltage (DV) condition.

RHR heat exchanger outlet valves MOV-746 and MOV-747 are normally closed therefore their failure due to inadequate fuses for DV conditions would result in both trains of RHR being inoperable. These valves are required to open during a Design Basis Accident for the RHR system to perform its safety function. During a scheduled NRC Component Design Basis Inspection (CDBI), an inspector review of the 480 Volt Motor Control Center (MCC) coordination calculation for MCC 26B resulted in a question concerning the survivability of safety related loads following a degraded voltage (DV) condition.

Specifically, the NRC inspector questioned the ability of the electrical protective devices (fuses) (FU) to hold during locked rotor currents at degraded voltages for the duration of the degraded voltage time delay. The NRC inspector review of protective device coordination plots for Motor Operated Valves (MOVs) 746 and 747 (RHR heat exchanger outlet valves) questioned whether the Shawmut Type A4J30 (S156) fast acting fuses in the supply circuit would coordinate with the MOV locked rotor currents expected under degraded, normal and higher than normal voltage conditions. As a result of inspector questioning, the fuses for MOV-746 and MOV-747 were evaluated in accordance with the guidance contained in Nuclear Energy Institute (NEI) 15-01 (An analytical Approach for Establishing Degraded Voltage Relay (DVR) Settings).

Engineering concluded after review of the NEI 15-01 guidelines that the electrical coordination calculations associated with MOV-746 and MOV-747 did not support continued operability during a DV condition. The condition was recorded in the Indian Point Energy Center (IPEC) Corrective Action Program (CAP) as Condition Report CR-IP2-2015- 03688.

On August 18, 2015, Operations entered TS 3.5.2 (ECCS Operating) for two trains of RHR and Recirculation inoperable due to valves MOV-746 and MOV-747 being determined to be inoperable. Entered TS 3.5.2 Condition C for less than 100 percent equivalent flow of one RHR pump and one Recirculation pump available. Required action C.1 is to enter TS Limiting Condition for Operation (LCO) 3.0.3 immediately. Entered TS 3.0.3 at 13:31 hours, whose actions are to place the unit in a mode or other specified condition in which the LCO is not applicable with actions to be initiated within 1-hour. The installed fuses were replaced with Shawmut Type AJT30 time delayed fuses which have no coordination issues. During change out of fuses with replacement fuses that would remain operable under DV conditions, operators changed out one set of fuses affecting one valve at a time. At 14:19 hours the fuses for MOV-746 were installed and TS 3.0.3 exited. Entered TS 3.5.2 Condition A for one or more trains inoperable with required action A.1 to restore train to operable status with completion time of 72 hours. At 14:31 hours, the fuses for MOV-747 were installed and TS 3.5.2 actions exited.

The RHR system is a subsystem of the Emergency Core Cooling System (ECCS) divided into two 100 percent capacity subsystems. Each RHR subsystem consists of one RHR pump and one RHR heat exchanger as well as associated piping and valves to transfer water from the suction source to the reactor core. ECCS analysis assumes RHR injection into all four reactor coolant system (RCS) cold legs. During the injection phase of a LOCA recovery, a suction header supplies water from the Refueling Water Storage Tank (RWST) to the High Head Safety Injection (HHSI) and RHR pumps. The discharge from the HHSI and RHR pumps divides and feeds an injection line to each of the RCS cold legs. During the recirculation phase of LOCA recovery, the Containment Recirculation pumps take suction from the containment recirculation sump and direct flow through the RHR heat exchangers to the cold legs.

NRC FORM 366AU.S. NUCLEAR REGULATORY COMMISSION FACILITY NAME (1) DOCKET (2) LER NUMBER (6) Indian Point Unit 2 05000-247 2015 002 00 The RHR pumps can also be used to provide a backup method of recirculation. MOV-746 and MOV-747 are RHR heat exchanger outlet valves that are normally closed during power operation but are required to open for a DBA (LOCA).

This issue has been an NRC concern regarding the adequacy of power plant electrical distribution systems voltages as a result of previous events with degraded voltage protection for power plant Class lE electrical safety buses for degraded transmission network (grid) voltage conditions. Previous electrical grid events demonstrated that when Class lE buses are supplied by the offsite power system, sustained degraded voltage conditions on the grid can cause adverse effects on the operation of class lE loads. The degraded voltage conditions will not be detected by the Loss-of-Voltage Relays (LVRs) which are designed to detect loss of power to the bus from offsite circuits. The NRC issued actions to licensees followed up with Generic Letter 79-36, Branch Technical Position (BTP) PSB-1 and Regulatory Issues Summary (RIS) 2011-12.

Indian Point used the NRC guidance to evaluate the plant and developed calculations to address the issue. In 1997, IEEE Standard 741 was issued providing guidance on the use of degraded voltage relays in protective schemes but the guidance was not endorsed by the NRC. IEEE Standard 741 was not part of the Unit 2 protective setting and coordination criteria which was used to assess the Unit 2 coordination adequacy. As a result, the methodology provided in IEEE Standard 741 was not used to develop the coordination calculations. The current Entergy Engineering Standard (ES) invokes only certain portions of the IEEE Standard 741 criteria. Specifically, the one second - margin guideline for prevention of spurious tripping is not included in the ES. RIS 2011-12 was issued to clarify regulatory requirements but did not detail any specific analytical approach to meet the requirements. In March 2015, the Nuclear Electric Institute (NEI) developed technical guidance document NEI 15-01 to provide an analytical approach that could be used to establish the settings for degraded voltage protection schemes. The NRC used NEI 15-01 and RIS 2011-12 in the CDBI to evaluate the current design basis of the electrical protective devices for MOV-746 and MOV-747. In preparation for the CDBI, a Focused Self-Assessment (FSA) was performed and the issued identified but a detailed review was not performed. During the FSA the results of recent NRC CDBI inspections were reviewed and the FSA determined that further review of design basis electrical calculations should be performed to determine if Indian Point was susceptible to similar calculation weaknesses that resulted in NRC findings at other plants. The failure to properly act upon the Industry OE review per the FSA finding resulted in a missed opportunity.

An extent of condition (EOC) review determined the condition is unique to Design Engineering and design basis electrical calculations because the condition specifically concerns survivability of electrical protective devices during a DV condition. As such, this condition does not extend to other equipment, calculations, processes or organizations not already evaluated. As a result of High Risk 1 EOC, an EOC review was performed on the effects of degraded grid voltage on electrical protective devices for safety related motors, motor operated valves and static loads. Loads on the Unit 2 and Unit 3 480 volt safeguards buses and MCCs were reviewed. This review identified two valves, MOV-746 and MOV-747, in need of fuse replacement. Calculation updates associated with this EOC review are tracked by CR-IP2-2015-03725. As a result of High Risk 2 EOC, a review was performed that included an evaluation of all safety related loads at degraded grid voltages. Operating voltage (running and starting) to all Unit 2 and Unit 3 motors, MOVs, static loads and MCC contactors on Unit 2 and 3 480 volt safeguards buses and MCCs were evaluated at degraded voltage conditions. This review determined that the required loads would successfully cope with a DV condition.

Calculation updates associated with this EOC review are tracked by CR-IP2-2015-03702.

The calculation updates will be processed via Engineering Changes (ECs) and all affected documents will be evaluated for update. The calculation updates will be processed via Engineering Changes and all affected documents, including Engineering Standard ENN-EE-S-003-IP and the 480 Volt Electrical System Design Basis Document will be reviewed and any necessary changes incorporated into the appropriate documents.

Cause of Event

Direct cause was electrical coordination calculations for MOV-746 and MOV-747 did not support continued operability during a degraded voltage condition. The apparent cause was that the Industry Operating Experience (OE) (prior NRC violations and findings) was not properly acted upon during the Focused Self-Assessment on CDBI preparation due to an incorrect assumption.

Corrective Actions

The following corrective actions have been or will be performed under Entergy's Corrective Action Program to address the cause and prevent recurrence:

  • Evaluated and replaced the fuses in the supply circuit for MOV-746 and MOV-747 in accordance with Engineering Change (EC) 59435. Issued EC mark-ups for the affected calculations as part of EC-59435.
  • Communicated to Design and Programs Engineering Personnel the lessons learned from this event and to raise the level of awareness regarding recent guidance on the evaluation of degraded voltage conditions and to reinforce importance of verifying assumptions.
  • Initiated CR-IP2-2015-03725 recording NRC 2015 CBDI Item 103 and CR-IP2-2015-03702 recording NRC 2015 CBDI Item 104 to addresses EOC findings and calculation updates which will be processed via ECs. All affected documents, including Engineering Standard ENN-EE-S-003-IP and the Design Basis Document for the 480 Volt Electrical System (IP2-480V DBD) will be evaluated for update as part of the ECs for this issue.
  • Performed and documented EOC review for CBDI Item 103 and Item 104 per EC-59116 and EC-59123.

Event Analysis

The event is reportable under 10CFR50.73(a)(2)(v) as an event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to: (A) shut down the reactor and maintain it in a safe shutdown condition, (B) remove residual heat, (D) mitigate the consequences of an accident (safety system functional failure), and is also reportable under 10CFR50.73(a)(2)(ii)(B) for any event or condition that resulted in the nuclear power plant being in an unanalyzed condition that significantly degraded plant safety and under 10CFR50.73(a)(2)(vii) for any event where a single cause or condition caused at least two independent trains or channels to become inoperable in a single system designed to: (A) shut down the reactor and maintain it in a safe shutdown condition, (B) remove residual heat, (D) mitigate the consequences of an accident. The condition recorded in CR-IP2-2015-03688 meets these reporting criteria since the possible failure of the fuses under degraded voltage conditions for RHR heat exchanger outlet valves MOV-746 and MOV-747 could result in the loss on both RHR trains.

Past Similar Events

A review was performed of the past three years of Licensee Event Reports (LERs) for events that involved a SSFF, Unanalyzed Condition or common mode failure due to loss of redundant ECCS trains as a result of inadequate engineering. No LERs were identified reporting a loss of ECCS function.

FACILITY NAME (1) DOCKET (2) LER NUMBER 6) PAGE (3)

Safety Significance

This event had no significant effect on the health and safety of the public. There were no actual safety consequences for the event because there were no accidents or transients during the time of the event.

A risk assessment was performed by the NRC as discussed in Inspection Report 05000247/2015-007 dated October 5, 2015. The NRC reviewed the Entergy operability assessment and determined it was adequate. However, for the degraded voltage issue, the originally installed fast-acting Shawmut Type A4J30 fuses would likely actuate prior to the RHR MOVs successfully stroking open. That condition results in the potential inoperability of both trains of low pressure injection/recirculation for longer than the TS LCO allowed outage time. A detailed risk evaluation was performed for that condition. The calculated cumulative conditional core damage probability (CCDP) was determined to be 5.5E-6 with an exposure time of one year. To account for the consequential degraded grid voltage condition, the CCDP value was multiplied by 2E-2 to approximate the probability of a LOOP given a LOCA has occurred. The evaluation determined that the estimated increase in core damage frequency (CDF) associated with this performance deficiency is 1E-7/year or very low safety significance. The risk significance approximation is overly conservative and is considered a worst case bounding evaluation. The risk assessment included a review for potential LERF and external events contributions. Based on Unit 2 being a pressurized water reactor with a large dry containment, the finding screens out for LERF consideration. Because the conditional event sequences of interest involve loss of coolant accidents, external events coincident with or contributing to these accidents would be of extremely low probability and considered beyond the plants design basis. Accordingly, there is no external event contribution to core damage risk for this issue.

05000286/LER-2015-0027 July 2015Indian Point

On February 27, 2015, during the performance of surveillance procedure 3-PT-R006A, three main steam safety valves (MSSV) (MS-46-2, MS-45-4 and MS-47-4) failed their As-Found lift.

set point test. Per the test, these valves must lift at +/- 30 of their required setting.

During the test, 7 other MSSVs tested passed their As-Found test criteria.

Technical Specification (TS) 3.7.1 (Main Steam Safety Valves) requires the MSSVs to be operable in accordance with TS Table 3.7.1-1 and Table 3.7.1-2.

Due to the number of failures, during power ascension the remaining MSSVs were tested and two failed (MS-46-2, MS-46-3).

MSSV MS-46-2 had previously failed and had maintenance performed therefore the failure was considered a post maintenance test failure.

MS-46-3 failed its first lift test by 0.60 but met test lift criteria on the second and third test.

TS Surveillance Requirement (SR) 3.7.1.1 requires each MSSV be verified to lift per Table 3.7.1-2 in accordance with the In-service Testing Program. Operability of the MSSVs includes the ability to open within the set point tolerances. The direct cause of the failure of these valves was severely worn spindle rods.

The apparent cause for the failure of MS-47-4 and MS-46-2 was internal friction due to spindle vibration.

The apparent cause of the failure of.MS-45-4 was reuse of a worn spindle. The apparent cause of the failure of MS-46-3 is foreign material.

Corrective actions included testing all 20 MSSVs and adjusting their set point to be within +/- 1% of design set pressure. Installed new spindles and bronze wear sleeves on valves MS-46-4, MS-46-2, MS-47-4, MS-48-2, MS-49-2, MS-49-1, MS-49-3, and replaced the spindle on valve MS-45-4. The Unit 3 MSSV test frequency will be changed from 4 years to 2 years until all modifications are implemented and IPEC is confident the issue is resolved. The event had no effect on public health and safety.

FACILITY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

05000286/LER-2015-0038 June 2015Indian Point

On March 3, 2015, while in Mode 5 (cold shutdown) for a refueling outage, during performance of 3-PT-R200 (Essential Service Water Header Flow Balance) the As-Found service water (SW) flow rates for the 31 Fan Cooler Unit (FCU), 32 FCU and 33 FCU were less than the Technical Specification (TS) 3.6.6 (Containment Spray and Containment Fan Cooler System) Surveillance Requirement (SR) 3.6.6.3 flow of 1430 gpm.

The SW essential header was re-balanced by adjusting FCU throttle valves to obtain a minimum of 1430 gpm for all five FCUs. On April 9, 2015, an engineering review of test data recorded from test 3-PT-R200, determined that the quarterly test (3-PT-Q016) that verifies FCU flows is not performed in the correct alignment for validating SW flow for the FCUs per TS SR 3.6.6.3.

Test 3-PT-Q016 tests SW flow through FCU with SW isolated through the Emergency Diesel Generator (EDG) coolers.

This configuration is not consistent with post accident operation in which SW is aligned to the FCUs and EDGs.

The apparent cause was improper implementation of improved TS requirements.

Corrective action was a revision of procedure 3-PT-Q016 to require validation of FCU SW flow with the EDG SW flow control valves and FCU outlet temperature control valves open.

The event had no significant effect on public health and safety.

05000286/LER-2015-0013 March 2015Indian Point

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.

05000286/LER-2015-001, Safety System Functional Failure Due to Inoperable Refueling Water Storage Tank Level Alarms Due to Freezing of the Level Instrument Sensing Lines Caused by a Failed Strip Heater3 March 2015Indian Point
05000247/LER-2014-00223 April 2014Indian Point

On February 24, 2014, during initial Containment walkdowns after shutdown for a refueling outage, Operations identified a steam leak on 23 steam generator (SG) drain line valve MS-68. Valve MS-68 is a normally closed valve on a one inch drain pipe from the 23 SG shell side to the two inch SG Blowdown piping to the blowdown tank.

The steam leak was due to a through wall defect in the valve body. The one inch SG drain pipe and valve MS-68 are safety related, ISI-ASME Code Class 2 High Energy (HE) and Seismic Class 1 components. Assessment of the condition determined the leak could not be isolated and Ultrasonic Testing (UT) could not be performed to determine the extent of the defect. The valve and associated piping are a pressure boundary for the SG and because there is no ASME Code method to evaluate the structural integrity of the through wall defect, Engineering concluded the valve was inoperable. Operations declared the 23 SG inoperable but the plant was in Mode 5 (Cold Shutdown) and one SG inoperable did not impact Technical Specification (TS) 3.4.7 (Reactor Coolant System (RCS) Loops-Mode 5, Loops Filled). However, the condition had resulted in leaking prior to shutdown and therefore was applicable to TS 3.4.4 (Reactor Coolant System (RCS) Loops-Modes 1 and 2) which requires four operable RCS loops including four operable SGs. The cause of the steam leak was a pin hole in the body of valve MS-68.

The pin hole was likely a defect in the original valve casting which over time propagated through the valve wall. Corrective action was removal and replacement of the valve. The event had no effect on public health and safety.

05000247/LER-2014-0017 April 2014Indian PointOn February 20, 2014, Entergy identified a failure to comply with Technical Specification (TS) 3.4.3 (Reactor Coolant System (RCS) Pressure and Temperature (P/T) Limits) after review of a Westinghouse PWR Owners Group (PWROG) correspondence (0G-14-66) dated February 19, 2014. The PWROG correspondence discussed a Non-cited Violation at Perry Nuclear Plant for failure to comply with their TS for RCS P/T limits when operating the plant with a vacuum in the reactor pressure vessel (RPV) during cold startups and cooldowns. A review of the Indian Point Units 2 and 3 TS 3.4.3 determined that TS 3.4.3 P/T limits for heatup and cooldown only provide for values greater than or equal to 0 psig. TS 3.4.3 requires that the RCS pressures and temperatures be maintained within limits at all times specified in TS Figures 3.4.3-1 and 3.4.3-2. The P/T Figures provide curves with a pressure starting at 0 psig. During past operation at both units, TS 3.4.3 P/T limits were not complied with when performing vacuum refill in Mode 5 as this process results in RCS pressures less than 0 psig. Cause of the event was a failure to recognize that a negative pressure was not allowed by the TS. Corrective actions for Unit 2 was a TS amendment that was processed and approved by the NRC to include the acceptability of the vacuum refill condition. Corrective actions for Unit 3 will be to submit a change to the TS to support this condition. The event had no effect on public health and safety.
05000286/LER-2014-00210 March 2014Indian PointOn July 16, 2012, during operator rounds, a Service Water (SW) leak was discovered on a socket weld elbow of a three quarter inch diameter sample pipe connected to the 31 Component Cooling Water (CCW) Heat Exchanger (Hx) SW discharge pipe upstream of sample valve SWN-49-1. The leak was too small to quantify. The leak is on a component classified as ASME Section XI Code Class 3. The weld leak was evaluated and determined not applicable to acceptance under Code Case N-513-3. The condition was determined to have no impact on SW cooling safety function. The affected SW header was declared inoperable and Technical Specification (TS) 3.7.9 (SW System) entered until the applicable CCW loop for the 31 CCW Hx was isolated. TS 3.7.8 (CCW System) was entered for one CCW loop inoperable. At the time this condition was identified the condition was not recognized as being reportable. The apparent cause was crevice corrosion due to exposure of unlined carbon steel to brackish SW (chloride) environment in low flow or stagnant vent/drain piping. The corrective action was a complete replacement of the affected piping assembly during the TS allowed outage time (AOT). The event had no significant effect on public health and safety.
05000247/LER-2013-00327 August 2013Indian Point

On July 3,'2013, operators initiated a manual reactor trip as a result of lowering steam generator (SG) levels due to the loss of feedwater (FW) from the trip of both main FW pumps. All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The Auxiliary Feedwater System automatically started as expected. Investigations determined the decreasing SG levels were due to a loss of main FW flow as a result of the closure of the FW regulating valves. The FW regulating valves closed due to a loss of instrument air (IA) pressure. The IA pressure was lost when a two inch copper IA tubing in the 22 Main Transformer moat separated at a soldered coupling. Prior to the event piping lines including the IA line buried in the main transformer moat were excavated and temporary supports installed. The apparent cause was poor legacy workmanship assembling the IA tubing coupling during original plant construction. The IA tubing was not fully inserted into the coupling resulting in reduced joint strength. Corrective actions included reassembly and soldering of the IA joint with full insertion, acoustic emission and snoop testing on repaired coupling.

Axial and thrust restraints were installed on the IA line in the moat. A caution was placed in the Buried Piping Program database associated with buried copper tubing identifying the potential for the separation of soldered joints when the line is excavated and the need for restraints or other contingencies to minimize the probability of a line separation.

The event had no effect on public health and safety.

05000247/LER-2013-00115 April 2013Indian Point

On February 13, 2013, operators initiated a manual reactor trip (RT) as a result of lowering steam generator (SG) levels. All control rods fully inserted and all required safety systems functioned properly.

The plant was stabilized in hot standby with decay heat being removed by the main condenser (SG).

The Auxiliary Feedwater System automatically started as expected due to SG low level from shrink effect.

An investigation determined the decreasing SG levels was due to reduced main feedwater (FW) flow from a loss of Heater Drain Tank (HDT) pumps. The HDT pumps tripped during valve diagnostics on HDT level control valve LCV-1127B which resulted in HDT Large Dump valves failing open. The open HDT large dump valves resulted in low HDT level and trip of the HDT pumps. The HDT large Dump valves failed open when the current/pressure (I/P) lead was lifted during air operated valve (AOV) diagnostics per procedure 0-IC- PC-AOV. Loss of HDT flow to the main feedwater pumps (FWPs) caused the FWPs speed controller cutback to reduce FW flow to the SGs. The root cause (RC) was inadequate procedure design and content. Corrective actions from the RC will be to revise Maintenance procedures 0-IC-PC-AOV and 0-VLV-404-AOV to: 1) Eliminate conditional steps for equipment setup that allows changes to work scope to be made in the field without proper review prior to performing work, 2) Eliminate the subject Caution block, and 3) Include signature blocks for review of drawings and validation that lifting a I/P lead or disconnecting the instrument tubing will not affect any other valve or component.

The event had no effect on public health and safety.

05000247/LER-2012-00915 April 2013Indian Point

On November 26, 2012, Operator review of a tag-out for a Preventive Maintenance of the Steam Generator (SG) blowdown (SGBD) radiation monitor R-49 determined the tagout would have placed all the SGBD isolation valves (ISVs) in Rad Bypass. Operators could not identify any procedure allowing this action and determined this action was previously reported in LER-2012-004 as an unanalyzed condition and safety system functional failure when an Auxiliary Feedwater pump is out of service.

which allows the ISVs to Auto close for heat sink events (Loss of Normal Feedwater, Loss of All AC Power to the Station Auxiliaries) in addition to containment Phase A isolation.

Analyzed degraded heat sink events assume SGBD isolation occurs and continuous SGBD during these events has not been analyzed. SG inventory would not be maintained if only one motor-driven AFW pump was operable as it may not provide adequate flow with the SGBD ISVs The normal ISV position is open open. A review identified previous tagouts that placed the SGBD ISVs in Rad Bypass with an Auxiliary Feedwater pump or its emergency power supply inoperable.

cause (AC) was the reviews associated with the condition recorded in CR-IP2-2012-02408 were too narrowly focused. Reviewers failed to consider processes other than procedures that could place the SGBD ISV in Rad Bypass. Corrective action was revision of procedure 2-PC-2Y23-49 to delete steps to place in Rad Bypass while performing Radiation Monitor R- The apparent 49 calibration and installation of a test jumper to disable the blowdown function (as reported in LER-2012-004) Applicable archived tagouts were locked from further use.

UFSAR Section 14.1.9 was revised to state SGBD isolation is assumed starting from event initiation. The AC and lessons learned will be shared with applicable plant personnel.

The event had no significant effect on public health and safety. 1

05000247/LER-2012-0085 November 2012Indian Point

On September 7, 3.8.7 Condition A was entered for an 2012, Technical Specification (TS) inoperable 22 Static Inverter (SI) after the 22 SI swapped to its alternate power source.

Troubleshooting determined the SI frequency meter optical sensor light was out.T Tapping on the meter resulted in the frequency meter light illuminating allowing SI.to sense that the correct frequency was present.T After testing, operations transferred the 22 SI back to its normal power supply and exited TS 3.8.7.T On September 10, 2012, operability of the 22 SI was questioned concerning the 22 SI seismic qualification.TBecause the cause of the failure of frequency meter could not be determined, operations concluded there was no reasonable assurance that the 22 SI would be able to maintain its design function in the event of a seismic event and the 22 SI was declared inoperable. the TS 3.8.7 was entered,T meter was replaced and the 22 SI returned to its normal power supply. The apparent cause was inadequate use of human performance (HP) tools.T Shift management did not effectively use questioning attitude.T The Operations team level of knowledge on the operation of the optical sensor was insufficient to assess the seismic effect on its operation.T Corrective actions included replacement of 22 SI frequency meter, inclusion of event in operations training, and update of vendor manual on meter function.T The System Description for electrical systems will be revised to include a discussion of SI frequency meter optical sensor, a Temp Mod had been installed for the 24 SI and was issued for the 21-23 SIs to bypass the out of frequency transfer.T A mod will be prepared to replace the meters with a model that does not include transfer on out of frequency.T An equipment failure analysis will be performed to determine the cause of the failure of the 22 SI frequency meter photocell LED.T The event had no significant effect on public health and safety.

05000247/LER-2012-00720 August 2012Indian PointOn June 21, 2012, the results of a diesel fuel oil (FO) sample from the Diesel Generator (DG) Reserve FO Storage Tank were received from an offsite vendor that showed the total particulates were not within the allowable value per Technical Specification (TS) 5.5.11 (Diesel Fuel Oil Testing Program) for Unit 2 and TS 5.5.12 for Unit 3. FO sampling is performed in accordance with TS Surveillance Requirement 3.8.3.4 to verify that FO properties of new and stored FO are within the limits specified in the Diesel FO Testing Program. TS 3.8.3 (Diesel Fuel Oil and Starting Air) Condition D was entered with a required action to restore stored FO total particulates to within limits within 30 days. Actions were initiated to provide the required total usable reserve FO that met FO properties per the Diesel Fuel Oil Testing Program. TS 3.8.3 Condition D was exited on July 5, 2012. Previous FO sample results were reviewed and some were not within the TS allowable value and in some cases there was no credible documentation to verify operability during past operation. The apparent cause was a failure to trend adverse conditions identified for out of spec FO particulates and failure to use the Corrective Action Process to document out of spec FO particulate results. Corrective actions included implementation of a process for formal trending of safety related chemistry analysis results, updating the duty matrix to ensure responsibilities for trending are assigned and documented. A stand down will be performed to review the CR process and sampling protocol and training will be performed on the event and lessons learned. In addition, the cause of the increase in particulates after the change in sample vendor will be determined. The event had no significant effect on public health and safety.
05000247/LER-2010-00921 June 2012Indian Point

On November 7, 2010, an automatic reactor trip (RT) was initiated as a result of a turbine-generator trip due to actuation of the main generator primary and back-up lockout relays. All control rods fully inserted and all primary systems functioned per design except for the 138 kV Station Auxiliary Transformer tap changer. The plant was stabilized in hot standby with decay heat being removed by the main condenser (SG). Based on reports of two explosions an Alert was declared in accordance with the emergency plan which was terminated at 22:18 hours. There was no radiation release. The Emergency Diesel Generators did not start as offsite power remained available. The Auxiliary Feedwater System automatically started as expected due to SG low level from shrink effect. The direct cause of the RT was due to actuation of the 86P and 86BU relays that sensed a fault from the failure of 21 main transformer (MT) as a result of a low impedance fault of the 345 kV Phase B bushing. The root cause was an internal failure of the phase B bushing due to a vendor design/manufacturing deficiency.

Corrective actions include replacement and acceptance testing of the 21 MT, external visual inspections of the 22 MT HV bushings, Unit Auxiliary Transformer (UAT), Iso-phase bus and 345 kV feeder W95, testing of the 22 MT, UAT, Iso-phase bus and HV components. Damaged HV components were replaced. The bushings for the 21 and 22 MT were replaced with another manufacturers bushing. The event had no effect on public health and safety.

05000286/LER-2012-00213 April 2012Indian Point

On February 13, 2012-01 (Seismic 2012, a review of NRC Information Notice (IN)T Considerations-Principally Issues Involving Tanks) determined there was a clarification in NRC's position regarding aligning non-seismic piping to the seismically qualified Refueling Water Storage Tank (RWST). The IN identified failures by licensees to recognize that aligning non-seismic piping to the RWST would require Technical Specification (TS) Limiting Condition of Operation (LCO) action statement entry or license amendments.

Intentionally aligning the seismically qualified RWST piping to non-seismic Fuel Pool Purification System (FPPS) by opening a boundary valve can cause the RWST to become inoperable.T TS LCO 3.0.2 requires that upon discovery of a failure to meet an LCO, the required actions of the associated conditions must be met. TS LCO 3.0.2 does not allow applying compensatory measures such as manual actions in place of a closed boundary valve for periods longer than the TS completion time for restoring the RWST to operable unless the TS expressly permit such operation.T Indian Point unit 3 had performed a safety evaluation based on IN 97-78 that allowed operator action. IN 2012-01 clarifies that application of compensatory actions for periods longer than the TS completion time is not allowed. Original issue was resolved The apparent cause was historical interpretation.

using the NRC guidance for operator manual actions.T Corrective actions will include revision of system operating procedure 3-SOP-SI-003 to prevent aligning the RWST to the FPPS during applicable Modes until the issue is resolved, evaluate the feasibility of a license amendment to allow operator action, assessment of FPPS piping for upgrade to seismic.T The event had no effect on public health and safety.

05000247/LER-2011-00121 February 2012Indian Point

On March 1, 2011, Emergency Diesel Generators (EDGs) 21, 22' and 23 automatically actuated as a result of undervoltage on 480 Volt buses 5A and 6A due to a loss of 138 kV offsite power. 480 volt buses 2A and 3A remained energized as 6.9 kV buses 2, and 3 were energized from the Unit Auxiliary Transformer (UAT) which is connected to the Main Generator. All EDGs operated as designed. EDGs 21 and 23 were manually loaded onto buses 5A and 6A. Prior to the event Con Edison personnel were performing troubleshooting in the Buchanan switchyard on a metering circuit for 138 kV feeder 95332.

The direct cause was loss of power to 480 volt safeguards buses 5A and 6A due to isolation of 138 kV feeder 95332 to the Station Auxiliary Transformer.

Feeder 95332 isolated as a result of an arc on the feeder metering circuit current transformer (CT) switch that caused an imbalance.

The CT circuit also supplies the first line pilot wire relay which tripped due to the imbalance. In accordance with design, the pilot wire relay tripped 138 kV breakers F2 and BT3-4 in the Buchanan switchyard and actuated protective relay 87L/138 which actuated lockout relay 86 STP tripping unit 2 breakers BT4-5 and 6.9 kV breakers 52/ST5 and 52/ST6 thereby isolating feeder 95332.

The apparent cause was a failure of the current transformer (CT) test switch associated with the 138 kV feeder metering circuit to make- before-break. The test switch did not make-before-break due to corrosion on the contact surfaces. Corrective actions include closure of the test switch and restoring feeder 95332 to service. A Con Edison deficiency tag was placed on the switch. Troubleshooting was performed on the Buchanan switchyard feeder 95332 CT circuit and the test switch replaced. Con Edison revised their notification procedure for work impacting the switchyard. The event had no significant effect on public health and safety.

05000247/LER-2011-0021 December 2011Indian Point

On October 3, 2011, the 21 Service Water Pump (SWP) failed to start as required.

Personnel were sent to investigate the 21 SWP breaker and discovered the control power fuse had blown. Subsequently the breaker inertia latch was found to be stiff and binding throughout its movement. With the breaker inertia latch toggled and not reset, the breaker will be mechanically blocked from closing and will result in control fuse actuation. The direct cause was the breaker inertia latch was not reset and prevented the breaker from closing on demand. The root cause was a failure of workers to perform the required cleaning to remove the Zinc Dichromate plating as required by the Preventive Maintenance (PM) procedure. A contributing cause was a lack of OEM notification and ineffective direction for cleaning and removal of the zinc dichromate coating. Corrective actions included replacement of the breaker inertia latch, testing and return to service, review of previous DB breaker work packages to identify which latches and associated pins were not cleaned. Maintenance completed a human performance error review and re-enforced expectations of worker practices in department communications and prejob briefs. A Snapshot assessment on procedure use and adherence was performed and the MARC process implemented for placekeeping/procedure use events. The OEM provided a detailed step list for onsite breaker cleaning that will be incorporated into the breaker PM procedures.

Breaker PM procedures (2-BRK-022-ELC, 0-BRK-410-ELC, and 0-BRK-401-ELC) will be revised to include the new OEM detailed step list for onsite cleaning of inertia latch bushing and pivot pin and include independent verification sign offs for the latch and pin cleaning steps. The event had no significant effect on public health and safety.

05000247/LER-2011-0031 December 2011Indian Point

On October 3, 2011, during performance of the quarterly surveillance test of the Containment Fan Cooler Unit (FCU) cooling water flow, all five FCUs failed to meet minimum flow requirements with the essential service water (SW) header (1/2/3 header) supplied by the 22 and 23 SW pumps. Operations entered Technical Specification (TS) 3.0.3 per TS 3.6.6.F for 3 trains of FCUs inoperable. In accordance with TS 3.0.3 operations initiated actions to place the plant in Mode 3 within 7 hours. Operations initiated turbine load reduction by approximately 5 MW and swap of the essential SW supply to the 4/5/6 header.

Upon completion of the essential header swap, operations re-performed the quarterly surveillance test on the 4/5/6 header with satisfactory results. Based on successful completion of the test, Operations exited the TS 3.0.3 action statement and commenced power ascension to 100% power. The direct cause was excessive accumulation of silt in the SW Bay that resulted in degraded inlet flow to the SW pumps. The root cause was ineffective barriers established to monitor and remove silt accumulations that would affect SW pump Net Positive Suction Head (NPSH) margin failed to include predictive elements that account for changing environmental conditions. Corrective actions included sonar mapping and de-silting of the SW Bay. The sonar mapping frequency will be increased and the SW System Monitoring Plan will be revised to include alert and action levels for silt buildup. A comprehensive silt monitoring and mitigation plan will be developed to include predictive trending and monitoring methods. The event had no significant effect on public health and safety.

05000286/LER-2011-00325 April 2011Indian Point

On February 22, 2011, the Control Room was notified of flooding in the south service water (SW) valve pit. Subsequent investigation determined there was approximately three feet of water in the south valve pit with leakage in the area of Conventional Essential Header Discharge Isolation Valves SWN-6 and SWN-7.

The leak was estimated to be approximately 150 gpm and not isolable. Technical Specification (TS) 3.7.9 (Service Water System) Condition E was entered. After further evaluation, it was concluded there was a loss of safety function because the condition would prevent the credited method of isolating the SW loads in the event of a Design Basis Accident due to the inaccessibility to the valve pit for valve operation. As a result of this determination TS 3.7.9 Condition E was no longer applicable and the plant was in a condition not specified in the TS and required a plant shutdown per TS 3.0.3. The direct cause was a 3/4 inch hole in the 10 inch SW pipe (line 1222) downstream of valve SWN-6. The root cause was an inadequate installation plan and repair of a flaw identified in 1992. Interim corrective actions included installation of a modified pipe clamp and UT readings to determine pipe operability.

Corrective action was replacement of the effected pipe section in spring 2011 refueling outage.

An engineering guideline will be developed providing direction on how SW leak repairs should be performed.

The Generic Letter 89-13 program will be revised to prioritize inspection frequencies of SW pipe welds and include SW lines 1221 and 1222. Inspections of SW piping in the Unit 2 SW valve pit and the Unit 3 north SW valve pit will be performed. The event had no significant effect on public health and safety.

05000286/LER-2011-00110 March 2011Indian Point

On November 12, 2010, during performance of the quarterly functional test of the 32 Containment Spray Pump (CSP) the supply breaker failed to close. The breaker was fully charged and there were no abnormal indications. A second attempt to close the breaker failed and the breaker was racked out and visually inspected with no anomalies identified with the breaker or cubicle. A test of the close circuit was satisfactory and the breaker and cubicle secondary contacts were cleaned and inspected. With the breaker in the test position it operated successfully, but when racked into the connect position it failed to close. The trip circuit was verified to operate. The breaker problem was isolated to the close circuit. With the breaker racked in and charged, the fuses were removed and the control switch was positioned to close while measuring continuity across the closing circuit. With the breaker in the test position all indications were as required. With the breaker in the connect position, an open circuit was measured. Measurements and contact alignment inspections were performed with no problems identified. The breaker was replaced with a spare breaker and the quarterly test successfully performed. The direct cause was the breaker closing circuit was not reset to allow breaker closure. The apparent cause was a malfunction in the breaker closing circuit resulting in an open circuit. Engineering's review of a vendor equipment failure evaluation (EFE) concluded the breaker failed to close due to a high contact resistance of the motor cutoff switch.

Corrective actions include breaker replacement and revision of the Preventive Maintenance procedure to include resistance testing of the motor cutoff switch contacts. The event had no significant effect on public health and safety.

05000286/LER-2009-0093 November 2010Indian Point

On September 24, 2009, during performance of IC-SI-18 (Full Power Alignment for the Gamma-Metrics Excore Nuclear Instrumentation System) channel N-38 could not be aligned and the power range was declared inoperable and Technical Specification (TS) 3.3.3 (Post Accident Monitors) entered.T Subsequent engineering review of signal data determined the signal for N-38 started to degrade on September 15, 2009. Because the power supply was common cover the full operating range including the source range, TS 3.3.4T The neutron flux detector N-38(Remote Shutdown) was applicable. (source range) is a function specified in TS Basis Table 3.3.4-1 Function 1, Reactivity Control (and credited in Technical Requirements Manual (TRM) 3.3.D, Appendix R Alternate Safe Shutdown Monitoring). The inoperable N-38 failed to meet the specified safety function of TS 3.3.4. The apparent cause was a lack of a recurring preventive maintenance (PM) action to replace the power supplies because N-38 was not included in the Indian Point Energy Center (IPEC) Power Supply PM Program or the IPEC Capacitor Replacement Program.

N-38 was classified low critical using guidance of Entergy procedure EN-DC-153, "Preventive Maintenance Component Classification."T N-38 should have screened out as high critical.T Corrective actions included replacement of the failed power supply with the operable power supply from redundant detector N-39. New power supplies were provided for N-39 and N-38, N-38 was reclassified as high critical, and a new PM was initiated to periodically replace the power supplies of N-38 and N-39.TProcedure 3-PT- M100 (Monthly Post Accident Monitor Channel Checks) will be enhanced. The event had no effect on public health and safety.

05000247/LER-2010-00630 October 2010Indian Point

On September 1, 2010, during performance of 2-PT-Q017C (Alternate Safe Shutdown Supply Verification to 23 CCP), the Reactor Coolant System (RCS) Wide Range Hot Leg Temperature Instruments TI-5139Tand TI-5141 test readings were found out of (Loop 21) (Loop 22) specification. (Remote Shutdown), T Technical Specification Basis 3.3.4 Table 3.3.4-1, Function 3.b Decay Heat Removal via Steam Generators, RCS Hot Leg (HL) Temperature requires one operable function. The RCS HL Temperature is also credited in Technical Requirements Manual (TRM) 3.3.D (Appendix R Alternate Safe Shutdown Instrumentation).

After verification of proper performance of the test, Operations concluded the function for RCS HL Temperature was inoperable and entered TS 3.3.4 Action Statement A.1.

The apparent cause was indeterminate.

T A Failure Modes and Effect Analysis identified two possible causes: PC-1) A test process failure. The test has had historical problems with the test sequence where the instruments are powered prior to start of the 23 CCP and starting currents impacted instrument readout. Also the instruments and circuit is required to warm up and stabilize after establishing power.

T To mitigate these effects the test was revised. PC-2)TT A complete failure of the R/I converter Component failure.T (TM) could cause the condition but a successful re-test and calibration ruled out a complete failure. Corrective actions include re-performing test 2-PT-Q017C with engineering review, and evaluating re-test results and identifying any additional actions.TThe event had no effect on public health and safety.

05000247/LER-2010-00310 May 2010Indian Point

On March 13, 2010, during a refueling outage work window protective tagout (PTO) of a service water (SW) - header valve, the Balance of Plant (BOP) work window manager approved a PTO which authorized closure of a SW valve isolating SW to all three emergency diesel generators (EDGY from the SW 1-2-3 header.AUpon closure of the SW valve, the control room (CR) received a EDG SW low flow alarm and directed the field operator to remove the PTO and un-isolate the header.

The apparent cause was improper verification techniques by the BOP work window manager to determine current plant conditions.A A contributing cause was the field operator did not verify that the actual valve line-up supported the expectation for current plant conditions.APrior to authorizing work, the BOP window manager checked the unit log for the scheduled swap of SW to header 4-5-6 and then authorized the PTO.

A Prior to SW isolation from the 1-2-3 header the field operator failed to verify that the SW 4-5-6 header was in-service.

Corrective actions included coaching the BOP window manager on use.of reliable sources for determining plant condition and the need for good communications with watch personnel, an operations stand down was performed to re-enforce management expectations on properly verifying plant conditions required for PTOs and understanding their impacts prior to implementation.A An Outage Lessons Learned will be prepared to establish a method for implementation during outages that requires peer checking initial conditions for PTO's prepared for specific plant conditions.

AA review will be performed to determine if changes to tagging procedures or fleet practices are warranted.A The event had no significant effect on public health and safety.

05000286/LER-2009-0082 December 2009Indian Point

On September 17, 2009, during performance of surveillance 3-PT-Q87D (Channel Functional Test of Reactor Coolant Temperature Channel 441) bistable 3TC-441C/D As-Found test readings were identified as out of specification for the Over Power Delta Temperature (OPDT) reactor trip function.

The bistable was adjusted in accordance with the procedure and all readings were left in specification.

T An'assessment of the condition determined that bistable 3TC-441C/D had been found out of specification on the previous quarterly surveillance on June 26, 2009.T (Reactor Protection Technical Specification 3.3.1T delta Temperature span, which for bistable TC-441C/D correlates to a 0.144 Volts DC T (Vdc) deviation from the nominal value. The OPDT Trip test criteria is 6.60 T(6.56 to 6.64) Vdc. On The As-Found OPDT value was 6.86 Vdc which exceeded the TS allowed value.

October 6, 2009, engineering concluded the second failure can not be assumed to have occurred at the time of discovery and represented an inoperable condition during past operation. The apparent cause was a discrepancy between the maintenance and test equipment (M&TE) output and reference value seen by the bistable. The discrepancy can be attributed to a deficiency with the test points used to input the reference value.

T The failure mechanism was concluded to have been a faulty reference value that was sensed by the bistable. Surveillance procedures The OPDT bistable (3TC-441C/D) was replaced.T 3-PT-Q87 A through D where revised to require recording voltages that are inputted into the instrument loop.

Troubleshooting will be performed on the bistable circuit for possible test point deficiencies.

The event had no effect on public health and safety.

NRC FORM 366AU.S. NUCLEAR REGULATORY COMMISSION (9-2007) FACILITY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

05000286/LER-2009-00721 October 2009Indian Point

On August 27, 2009, a Turbine Trip and Reactor Trip were initiated by main turbine control oil Autostop turbine trip. All control rods fully inserted and-all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. No Emergency There was no radiation release.T Diesel Generator actuated as offsite power remained available.

TThe Auxiliary Feedwater (AFW) System automatically started as expected due to Steam Generator low level from shrink effect.T The cause of the trip was a loss of Turbine Autostop oil pressure below the trip setpoint due to a failed pipe adaptor fitting on the line connecting the Turbine Autostop oil to the Turbine solenoid trip device.

The pipe adaptor fitting failed due to high cyclic fatigue caused by the improper installation of the Autostop,oil line fitting in the Turbine pedestal bulkhead wall.T The cause of the event was the as-found configuration did not meet the Original Equipment Manufacturer (OEM) design expectation.

This condition resulted in a configuration where the threaded fitting bottoms out in the threaded hole which induced additional stress on the fitting threads.TThe additional stress combined with normal stress caused a premature failure.

TCorrective actions included replacement of the failed fitting,T inspection of Autostop oil lines, and monitoring vibrations on turbine bearing No. 1. An engineering change will be developed to redesign the turbine pedestal piping wall penetration for the autostop oil turbine protection solenoid valve.T The event had no effect on public health and safety.