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On 10/23/2017, during a walkdown of containment at the start of the Unit 3 refueling outage, a leak was identified in a socket weld for a 1-inch diameter instrument line. The line is connected to discharge piping for the 'B' recirculation pump and is part of the reactor coolant system pressure boundary. Because the leak was misting, the leakage rate could not be quantified. However, the reactor coolant system unidentified leakage prior to plant shutdown was 0.18 gpm. RCS pressure boundary leakage while in Mode 1 is a violation of Technical Specification 3.4.4 and is a reportable condition.

The cause of the event was a lack of fusion defect in the weld when it was done in the late 1980's. Normal vibration of the line since it was installed resulted in the crack initiating at the weld defect and propagating to the surface. The section of pipe and associated fitting were replaced, along with welds in similar sections of piping. There were no actual safety consequences as a result of this event.

On October 16, 2017, with Unit 2 shutdown for a refueling outage, investigation into a boric acid indication identified a through wall leak at the socket weld that joins a 3/4 inch line to Loop A Reactor Coolant System (RCS)(AB) shutdown communication line valve 2RC-8-37 )(VTV). The leak was isolated by closed valves that would have limited primary coolant leakage to within the capacity of the charging system when the reactor coolant system was pressurized. The quantity of dry boric acid at the location was small (estimated at 1/2 teaspoon in volume). This failure constituted a welding or material defect in the primary coolant system that was not found acceptable under ASME Section Xl and an event or condition prohibited by Technical Specifications.

The cause of the leakage was determined to be stress corrosion cracking. Valve 2RC-8-37 was replaced. In addition, Prairie Island Nuclear Generating Plant intends to perform phased array ultrasonic inspections of socket welds on similar Class 1 piping containing stagnant water during future refueling outages.

On August 6, 2017, with Unit 1 at 100% power, a Reactor Coolant System (RCS) leak rate calculation determined the unidentified leak rate increased by 0.08 .gallons per minute. On August 8, a leak was obServed at an RCS hot leg.sample system valve,- and Unit 1 power level was reduced to investigate leakage indications. The. root isolation valve for the sample system valve was closed; however, leakage could not be verified as completely isolated. Further evaluation determined the leak to be through wall at the inlet of the sample system valve. Based upon the source of the leak and possible continued leakage, a Technical Specification shutdown clock was entered on August 9, at 13:38 hours. At 16:37 hours, Unit 1 was placed in Hot Shutdown.

The cause of the event was the RCS pressure boundary leakage at the tubing/socket weld area of the hot leg sample system valve. With the unit in Hot Shutdown, the leak was isolated and repaired, and Unit 1 was returned to power operation on August 11, 2017. An apparent cause evaluation is being conducted. The event was reported as a plant shutdown required by Technical Specifications pursuant to 10 CFR 50.72(b)(2)(i) and degraded condition pursuant to 10 CFR 50.72(b)(3)(ii)(A). This report is being provided pursuant to 10 CFR 50.73(a)(2)(i)(A) and 10 CFR 50.73(a)(2)(ii)(A).

On February 23, 2017, at 19:22 hours, with Unit 1 and Unit 2 operating at approximately 100 percent power, operators commenced a Unit 2 shutdown upon discovery of pressure boundary leakage on Unit 2 Safety Injection (NI) pipe upstream of the connection to "D" Reactor Coolant System (NC) Cold Leg. During a containment walk down inspection in Mode 3 on the next day, a pinhole pressure boundary leak was observed in the body of 2NC-30, Pressurizer Spray Bypass Valve.

The cause of the NI pipe leak is thermal fatigue damage caused by NC cross-loop flows. The cause of the 2NC-30 valve leak is a casting flaw attributed to a combination of defects during the manufacturing process that resulted in a through wall pinhole leak in the valve body. The NI pipe with the flaw and the valve with the pinhole leak could have structurally performed their design functions. Therefore, the health and safety of the public were not affected by these events.

Valve 2NC-30, the NI pipe, and leaking B-Loop NI check valves were replaced. Thermal cycling monitoring and mitigation devices were installed on Unit 2 and will be installed on Unit 1 during the next refueling outage.

During the Byron Station, Unit 1, spring 2017, refueling outage, volumetric and surface examinations of the Reactor Vessel Head Penetration (VHP) nozzles identified recordable indications for VHP nozzles 31, 74, 76, and 77 that did not meet the applicable acceptance criteria. The unacceptable indications were identified and repaired prior to returning the reactor head to service. None of the indications were located in the Reactor Coolant System pressure boundary region.

The cause of the P-31 unacceptable indication is attributed to existing welding discontinuities/minor subsurface voids opening to the surface or enlarging due to thermal and/or pressure stresses during plant operation. The cause of the P-74, P-76 and P-77 unacceptable indications is attributed to Primary Water Stress Corrosion Cracking.

The indication in penetration 31 was removed by manual buffing. The indications in P-74, P-76 and P-77 were repaired by manual grinding with no welding required.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(ii)(A) for any event or condition that results in the condition of the nuclear power plant, including its principal safety barriers, being seriously degraded.

On December 18, 2016, during a forced plant outage reported under Licensee Event Report (LER)-2016-004, a leak was identified on the minimum flow line of the High Pressure Core Spray (HPCS) system downstream of the Primary Containment Isolation Valve.

HPCS system had been running on minimum flow after being used to maintain Reactor Pressure Vessel water level. The HPCS line leak was identified during a walk down by Operations personnel after the HPCS pump had been secured. Due to the location of the leak downstream of the Primary Containment Isolation Valve, this leak constituted a breach of Primary Containment. Both HPCS and Primary Containment were declared inoperable.

The cause of the leak was determined to be from a gasketed flange in the HPCS minimum flow piping. Corrective actions included replacing the gasket. Further evaluation is ongoing and this report will be supplemented once complete.

On January 31, 2017, while St. Lucie Unit 1 was shut down in Mode 3, technicians identified reactor coolant pressure boundary leakage within the 1B2 reactor coolant pump (RCP) lower seal heat exchanger. At 1200 hours, St. Lucie Unit 1 entered Technical Specification 3.4.6.2 Action a. and the plant was maneuvered to Mode 5 to affect repairs.

The most probable cause was determined to be a deficiency in the lower seal heat exchanger design which permitted stresses that approached or exceeded the yield strength of the assembly tubing during torqueing of the CCW flanges.

The resultant plastic deformation and associated flaw formation caused low stress high cycle fatigue failure of the weld joint.

The flaw was removed and the weld repair was completed. St. Lucie Unit 1 was subsequently returned to service on February 7, 2017.

All remaining in-service and a spare RCP lower seal heat exchangers have since been inspected and no defects have been found. This event had no impact on the health and safety of the public.

Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send 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 e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Description On January 31, 2017, St. Lucie Unit 1 was shut down in Mode 3 for a maintenance outage to investigate and repair the source of reactor coolant system (RCS) (EIIS:AB) leakage coming from the vicinity of the 1B2 reactor coolant pump (EIIS:P) (RCP) seal (EIIS:SEAL) package. At 1200 hours, technicians determined that the leak was located in the RCP lower seal heat exchanger (EIIS:HX) and that the leakage was classifiable as reactor coolant pressure boundary leakage. St. Lucie Unit 1 entered Technical Specification (TS) 3.4.6.2 Action a. and the plant was maneuvered to Mode 5 to affect repairs. The 10 CFR 50.72(b)(3)(ii) notification was made at 1539 hours.

The flaw was removed and the weld repair was completed. St. Lucie Unit 1 was subsequently returned to service on February 7, 2017.

Cause of the Event

The most probable cause was determined to be a deficiency in the lower seal heat exchanger design which permitted stresses that approached or exceeded the yield strength of the assembly tubing during torqueing of the CCW flanges. The resultant plastic deformation and associated flaw formation caused low stress high cycle fatigue failure of the weld joint.

All of the in-service and spare St. Lucie Unit 1 and 2 RCP lower seal heat exchangers have been inspected.

These inspections did not find any deficiencies.

Analysis of the Event

This condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as an operation or condition prohibited by TSs, and 10 CFR 50.73(a)(2)(ii)(A) as a degraded or unanalyzed condition. Remote video analysis at power was inconclusive whether the leak was RCS pressure boundary. However, close visual inspection following unit shutdown determined the leak to be a small flaw in a RCS pressure boundary component (i.e. RCP seal cooler) which was a degraded condition prohibited by Technical Specifications.

The rotating assembly, the pump cover, and integral lower seal heat exchanger for the 1B2 RCP had been replaced during the previous refueling outage in the fall of 2016. The 1B2 RCP has an integral tube-in-tube heat exchanger which is permanently attached to the pump cover. This heat exchanger surrounds the labyrinth seal and provides cooling of the RCS water prior to entering the seal. This heat exchanger is comprised of two rows of six coils circling the RCP seal. The inner tube of the tube-in-tube configuration carries the high pressure RCS water. The outer tube carries the low pressure component cooling water (CCW) (EIIS:CC). RCS fluid enters the coils at the bottom of the assembly and exits the coils at the top of the assembly (one from the inside coil and one from the outside coil). The outlet of the coils is directed thru a machined elbow fitting welded to a short length of 1.5 inch diameter pipe, which carries the RCS flow to the seal housing and seal cartridge The leak was located in the tube material near the toe of the partial penetration weld that joins the seal cooler inner tube and ring.

A review of the Unit 1 containment atmosphere particulate monitor and reactor cavity leakage flow instrument data indicates that RCS leakage from the 1B2 RCP lower seal heat exchanger was initiated on November 9-10, 2016, approximately 1 week after the 1B2 RCP had been started during startup from the fall 2016 refueling outage. The Unidentified RCS leak rate was closely monitored while a maintenance outage was planned to repair or replace the newly installed RCP seal package.

Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send 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 e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Safety Significance

This condition was determined to be of very low safety significance for the following reasons:

• The maximum Unidentified RCS leak rate of 0.17 gpm was well within the capacity of the three charging (EIIS:CB) pumps (44 gpm each) (EIIS:P) which make up water volume to the RCS. RCS leak balances are normally calculated at once per day. Real time RCS leakage indications are detected through containment particulate radiation monitoring and cavity sump detection and may drive more frequent leakage calculations.

• The indication of RCS leakage approximately one week after pump start indicates that fatigue crack initiation and propagation through the inner tubing (0.125-inch min wall) occurred quite rapidly after pump start. Crack propagation appears to have slowed or arrested quickly as the total flaw length had only reached 15% of the inner tube's outer circumference approximately three months later. Such fatigue crack behavior is consistent with the postulated reduction in fatigue strength due to the presence of a residual stress. As the crack propagated, the residual stress was relieved and the positive mean stress reduced or eliminated. The applied cyclic loads associated with pump operation were insufficient to support continued crack propagation across the entire tubing cross section. The Unidentified RCS leak rate plateau during this period of time validates this observation. A Finite Element Analysis calculation was performed to confirm that the observed through wall crack would not propagate and leakage would remain within the capacity of the charging pumps.

Therefore, this event had no impact on the health and safety of the public.

Corrective Actions

1. The 1B2 RCP lower seal heat exchanger leak was repaired during the maintenance outage.

2. All remaining St. Lucie Unit 1 and 2 RCP lower seal heat exchangers were inspected and no other flaws were identified.

3. FPL is developing methods to reduce the stress on the RCP lower seal heat exchanger tubing during installation activities.

Failed Components Identified Flowserve supplied RCP lower seal heat exchanger

Additional Information

The weld repair required relief from ASME Code requirements, and those details are documented in FPL letter L-2017-017 dated Feb 2, 2017, titled “In-service Inspection Plan Fourth Ten-Year Interval Unit 1 Relief Request No. 14, Revision 0,” ADAMS accession number ML17033A151.

On October 2, 2016, during the liquid penetrant examination on the weld build up for control rod drive mechanism (CRDM) Penetration 69 during refueling outage Al R19, two rejectable rounded indications were documented. The first was a 7/32 inch rounded indication on the reactor head portion of the weld build up which was 4 inches from the transition of the head to penetration. The second was a 1/4 inch rounded indication located at the transition of the head to penetration.

The transition is the point where the vertical portion of the penetration meets the horizontal area of the reactor head. This LER is being submitted in follow-up to ENS 52275.

Based on industry experience, the cause of this event was determined to be mechanical discontinuities/minor subsurface voids opening up to the weld surface due to thermal and/or pressure stresses during plant operation.

The indications in penetration 69 were reduced to an acceptable dimension by manual buffing.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(ii)(A), "any event or condition that results in the condition of the nuclear power plant, including its principal safety barriers, being seriously degraded" since the as found indication did not meet the applicable acceptance criterion referenced in ASME Code Case N-729-1 to remain in-service without repair.

On April 10, 2016, at 2335, with Unit 1 in Mode 5, during a planned extent-of-condition inspection of the Unit 1 reactor coolant system (RCS), engineering personnel at the Palo Verde Nuclear Generating Station (PVNGS) identified white residue on a one-inch instrument nozzle on the reactor coolant pump 2B discharge pipe. Isotopic analysis confirmed the white residue resulted from leakage of RCS coolant and, at 0535 on April 11, 2016, engineering personnel determined that RCS pressure boundary leakage had occurred resulting in a condition prohibited by Technical Specification 3.4.14, RCS Operational Leakage.

The cause of the event was determined to be primary water stress corrosion cracking of the Alloy 600 instrument nozzle.

To correct the condition, the nozzle was repaired utilizing a Mechanical Nozzle Seal Assembly. A final repair of the nozzle will be addressed in the Corrective Action Program.

PVNGS reported similar events in licensee event report numbers 50-530/2015-001-00 (on June 5, 2015, when RCS pressure boundary leakage was identified on a Unit 3 RCP 2A suction pipe instrument nozzle) and 50-530/2013-001-00 (on December 6, 2013, when RCS pressure boundary leakage was identified on a Unit 3 reactor vessel bottom mounted instrument nozzle).

On March 22, 2016, while Unit 1 was in end of cycle (EOC) refueling outage 1E0C24 (Mode 5), a manual ultrasonic (UT) examination of the Chemical and Volume Control System (NV), Charging Line to the 1A Reactor Coolant System (NC) cold leg confirmed a previously identified circumferential indication associated with weld 1NC1F-1374. The current examination results had shown that the indication had changed since the previous examination during 1E0C23 and concluded that the indication no longer met American Society of Mechanical Engineers (ASME) Section XI Code requirements. This condition is reportable under 10CFR50.73(a)(2)(ii)(A) as a degraded condition.

A specific cause for the condition could not be determined. A metallurgical examination concluded that the cause of the UT result could have been influenced by pre-existing welds associated with a legacy modification.

The affected NV piping on Unit 1 was replaced during refueling outage 1E0C24.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 01/31/2017 Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send 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 infocollects Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

At 0649 on March 15, 2016 with Unit 1 shut down in MODE 5 for refueling activities, a boric acid indication upstream of the valve seating surface on the inlet of the valve body of 1CV-200B, Letdown Orifice B Outlet Control Valve was identified as a through-wall flaw. The flaw location was within the reactor coolant system (RCS) pressure boundary as defined by 10 CFR 50.2, "Definitions." The valve body is original plant equipment.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(ii)(A) for material defects in the primary coolant system that were not acceptable in accordance with ASME Section Xl.

APPROVED BY OMB: NO. 3150.0104 EXPIRES: 01/31/2017 Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Wa shing ton, DC 20555-0001, or by intemet e-mail to Infocollects.Resource©nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

On February 20, 2016, during Calvert Cliffs Inservice Inspections of Unit 1 dissimilar metal welds, an evaluation of recorded ultrasonic examination (UT) data identified the presence of one axially oriented flaw in a 4 inch Unit 1 pressurizer (PZR) safety relief nozzle (NZL) to safe end weld. The indicated flaw exhibited characteristics indicative of primary water stress corrosion cracking (PWSCC). The flaw was inner diameter connected and measured 81.6 percent through-wall. This measured axial flaw depth did not meet the American Society of Mechanical Engineers (ASME) Code allowable limit. The UT of this weld done in 2006 and 2010 had determined the axial flaw depth was only approximately 8 percent through-wall. After re-analysis of the prior UT data, the root cause was determined to be limitations in sizing data collection and analysis techniques prior to 2016 that were unable to connect the detected inner .

diameter indication to the full through-wall extent of ultrasonic signal response of the flaw. The weld was repaired using a full structural weld overlay repair method using PWSCC resistant material deposited around the circumference of the weld area. Two other Unit 1 welds that had previously shown potential PWSCC were examined with the new techniques and showed no change in their indication characteristics and remain within ASME Code allowable limits.

On November 13, 2015, at 1745 hours during drywell entry, a leak was reported on the "B" Reactor Reactor Recirculation (RXR) Pump Lower Seal Cavity Vent piping. The leak was identified at the inboard pipe-to-union weld and required a weld repair prior to returning to service. The affected piping weld is for 3/4-inch piping, schedule 80 SA-479 TP304 or TP316, union 3000# SA-182 Gr F304 or F316. The affected piping had been in service for approximately 11 months following a previous repair of the weld at this location during the December 2014 forced outage, (e.g., LER 2014-011-00, issued February 11, 2015).

The condition was reported on November 13, 2015 in accordance with 10 CFR 50.72(b)(3)(ii)(A) as a principal safety barrier degradation (EN 51538). This Licensee Event Report (LER) is written in accordance with 10 CFR 50.73(a)(ii)(A) and 10 CFR 50.73(a)(2)(i)(B) as a condition that resulted in a principal safety barrier degradation with evidence of reactor coolant pressure boundary leakage, which is a condition prohibited by the Technical Specifications.

The previous December 2014 weld repair did not fully excavate the weld and remove the J-groove, and thereby eliminate the presence of the crack.

Repair of the cracked weld was performed prior to the restart of Unit 1. The safety significance of this condition is minimal. Given the size of the leak, there were no consequences to the health and safety of the public.

On August 7, 2015, Unit 2 was in Mode 3 for a planned maintenance outage. At 1300 hours, during the initial drywell entry, a steam leak was observed on the Reactor Recirculation (RR) system line 2RR94AB-3/4", which is upstream of valve 2B33-F080B (RR Pump Discharge Valve 2B33-F067B Inspection Port - Reactor Side Upstream Stop Valve). At 1345 hours, the leak was determined to be pressure boundary leakage. Technical Specification 3.4.5, "RCS Operational Leakage," Required Actions C.1 and C.2 were entered, which require the unit to be in Mode 3 within 12 hours and in Mode 4 in 36 hours, respectively. Unit 2 entered Mode 4 at 2209 hours on August 7, 2015.

This condition was reported (EN# 51300) on August 7, 2015 to the NRC in accordance with 10 CFR 50.72(b)(3)(ii)(A) for the pressure boundary leakage as a principal safety barrier being in a seriously degraded condition.

The cause of the steam leak was determined to be poor weld quality and vibration induced fatigue. The weld was repaired during the maintenance outage.

examination was performed on the previously repaired control rod drive mechanism (CRDM) penetration 69. During the examination of the repair for CRDM penetration 69, one 3/8 inch rounded indication was documented exceeding the acceptance criterion (ASME Section III 1971 Edition through the Summer 1973 Addenda) of dimensions greater than 3/16 inch. This LER is being submitted in follow-up to ENS 50953 made on April 3, 2015.

Based on industry experience, the cause of this event was determined to be mechanical discontinuities/minor subsurface voids opening up to the weld surface due to thermal and/or pressure stresses during plant operation.

The indication in penetration 69 was reduced to acceptable size as approved by the NRC in Braidwood Relief Request I3R-09.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(ii)(A), "any event or condition that results in the condition of the nuclear power plant, including its principal safety barriers, being seriously degraded" since the as found indication did not meet the applicable acceptance criterion referenced in ASME Code Case N-729-1 to remain in-service without repair.

On July 25, 2014 with St. Lucie Unit 2 in Mode 1 at 100% power, a leak was confirmed on a one inch pipe between a safety injection tank (SIT) and a discharge header vent valve. In accordance with Technical Specifications (TS) and plant procedures, operators subsequently shut down the unit to repair the leak. The shutdown was uncomplicated and all plant safety systems functioned as designed. The leaking vent line and valve assembly were replaced and returned to service on July 28, 2014.

Engineering evaluation identified the direct cause of the pipe leak as through-wall cracking from high cycle, low stress fatigue. This condition is reportable in accordance with the following requirements: 1) 10 CFR 50.73(a)(2)(ii)(A), 2) 10 CFR 50.73(a)(2)(i)A, 3) 10 CFR 50.73(a)(2)(i)B, 4) 10 CFR 50.73(a)(2)(v)(D), 5) 10CFR50.73(a)(2)(ii)(B) and 6) 10 CFR 50.73(a)(2)(vii)(B).

This supplement revises the event description, analysis of event and safety significance and adds additional reporting criteria. This condition was determined not to be a significant impact on the health and safety of the public.

On March 31, 2014, at 1302 hours, an Inservice Inspection Program VT-2 examination of the Unit 2 Control Rod Drive (CRD) Hydraulic Control Unit (HCU) ASME Class 2 piping and components was being performed. An apparent through-wall valve body leak of approximately two drops per minute was discovered on the 2-0305-101-18-27 CRD HCU Scram Insert Isolation Valve. This valve is subjected to full reactor pressure during normal service and during this inspection. This valve is the isolation valve to the reactor vessel CRD drive housing, and since it is the first isolation boundary off of the reactor vessel, it therefore cannot be isolated from the reactor coolant system to allow repairs. The valve was declared inoperable, Technical Specifications LCO 3.4.4 Condition C was entered, and the Unit was shutdown and depressurized to effect repairs.

On April 1, 2014, the 2-0305-101-18-27 valve was removed from the system and shipped for analysis. It was determined that the through wall leak that developed was the direct result of an inherent manufacturing defect that eventually propagated to the valve surface following years of pressure and temperature cycles that the system normally experiences.

Corrective actions included replacing the failed isolation valve and performing additional CRD system inspections. A root cause analysis was performed and no additional contributing factors were identified.

The safety significance of this event was minimal since the leakage rate was very small and full scram capability was maintained by the control rod. Due to the impact on the reactor coolant pressure boundary, this report is submitted in accordance with the requirements of 10 CFR 50.73(a)(2)(ii)(A), which requires the reporting of any event or condition that results in the condition of the nuclear power plant, including its principal safety barriers, being seriously degraded. Since a plant shutdown was completed as required by the plant Technical Specifications, this report is also submitted in accordance with the requirements of 10 CFR 50.73(a)(2)(i)(A), which requires the reporting of the completion of any nuclear plant shutdown required by the plant's Technical Specifications.

On January 17, 2014, leakage into the Reactor Building Closed Cooling Water (RBCCW) System was determined to be Reactor Coolant Pressure Boundary (RCPB) leakage as identified by the Monticello Nuclear Generating Plant (MNGP) Technical Specifications (TS). Based on this, the TS limiting condition for operation was not met and a plant shutdown was required. The plant shutdown commenced at 2029 on January 17, 2014. There was no radioactive release from the plant. The plant was shut down without incident to repair the source of the inleakage.

The apparent cause for the RCPB leak was the lack of an established maintenance strategy in place to periodically check the condition of the heat exchanger or replace it. A crack formed in the #12 Recirculation Pump Upper Seal Heat Exchanger coil due to intergranular stress corrosion cracking.

The leaking # 12 Recirculation Pump Upper Seal Heat Exchanger was removed and the system was modified to operate without this heat exchanger by utilizing the excess capacity of the #12 Recirculation Pump Lower Seal Heat Exchanger.