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At 1710 EDT on June 11, 2021, a Technical Specification required shutdown was initiated at Plant Hatch Unit 1. Technical Specification Condition 3.4.4.B unidentified LEAKAGE increase not within limits, was entered due to a greater than 2 gpm increase in unidentified LEAKAGE within the previous 24 hour period in MODE 1. This specification was entered on June 11, 2021, at 1615 EDT with a REQUIRED ACTION to restore leakage increase within limits within 4 hours. This REQUIRED ACTION could not be completed within the COMPLETION TIME; therefore, a Technical Specification required shutdown was initiated, and this event is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(i). There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified.

• * * RETRACTION ON 6/17/2021 AT 1309 FROM JASON BUTLER TO JEFFREY WHITED * * *

Upon further review of the leakage rates, it was determined that at 1900 EDT on 6/11/2021 the drywell floor drain unidentified leakage increased greater than 2 gpm within the previous 24 hours while in MODE 1. Technical Specification (TS) 3.4.4.B was entered to reduce leakage increase to within limits within 4 hours. At 2000 EDT on 6/11/2021 unidentified leakage was reduced below the 2 gpm increase within the previous 24 hours due to actions taken to lower reactor power and pressure. Therefore, the TS required shutdown per TS 3.4.4.C was not applicable. Thus Event Report 55303 is being retracted. The NRC resident has been notified of the retraction. Notified R2DO (Miller).

During an inspection of a fire penetration between Fire Area 1404, Switchgear Room 1G and Fire Area 1408, Switchgear Room 1F in the diesel generator building, the penetration was determined to be non-functional as a 3 hour fire barrier. In the event of a postulated fire in the affected areas, both safe shutdown paths on Unit 1 could be compromised. Given this information, the determination was made that this condition meets the reporting criteria of 10 CFR 50.72(b)(3)(ii)(B). Compensatory measures were established in accordance with the plant's Fire Hazard Analysis (FHA). The presence of the compensatory measures in addition to automatic fire detection in the fire areas ensure that the safe shutdown paths are preserved until the degraded condition can be repaired. (Condition report No.) CR904013 The licensee notified the NRC Resident Inspector

• * * RETRACTION PROVIDED BY KENNY HUNTER TO JEFF ROTTON AT 0915 EST ON 12/30/2014 * * *

Further investigation revealed that after removing the outermost two inches of loose silicone foam material, and taking additional measurements there remained adequate silicone foam material to provide 10 inches of silicone foam sealing the penetration. Plant design shows that the wall in question is 18 inches thick and also that 9 inches of silicone foam is required in the penetration in order maintain a 3 hour fire rating for the wall/penetration. Since there is adequate foam in the penetration to maintain the 3 hour fire rating the penetration is fully functional. Based on this information, this penetration in its 'as found' state does NOT represent a condition that seriously degrades a principal safety barrier. As such this condition has been determined to no longer meet reporting requirement 10CFR50.72(b)(3) and is therefore NOT reportable. Based on this information the previous notification for Event 50662 is being retracted. The licensee notified the NRC Resident Inspector. Notified R2DO (Bartley)

On February 28, 2013, at 1155 EST, with the unit in Refueling Mode, a determination was made that reactor building closed cooling water (RBCCW) isolation valve (2P42-F051) exceeded its acceptance criteria for designed leakage when performing local leak rate testing. Diagnostic testing confirmed that all the leakage from its test boundary is going through this valve with an 'as found' leakage of >200,000 sccm at 32.87 psig. This valve is the outboard isolation barrier for that affected primary containment penetration with the inboard barrier being the RBCCW system itself as a 'closed' system. Previous practice is to conservatively include any leakage through this valve when performing as found leak rate tests as part of the primary containment leakage summary or as part of 0.6La. This is considered conservative since the RBCCW system inside containment is assumed to remain intact following a design basis accident (DBA) loss of coolant accident (LOCA). If the closed system remains intact there is no path for leakage to exit primary containment through this system. Since the past practice is to include the 'as found' leakage through this valve as part of 0.6La and since the 'as found' leakage would result in exceeding La, this condition is being considered a condition that results in the principal safety barriers being seriously degraded. This leakage would represent a loss of the containment function since the leak rate exceeded the Technical Specification limiting condition for operation (LCO) for primary containment. Further investigation is underway to determine if leakage through this single containment barrier is required to be included in the Appendix J primary containment leakage summary, since it is associated with a closed system. The licensee notified the NRC Resident Inspector.

• * * RETRACTION ON 3/15/13 AT 1607 EDT FROM KENNY HUNTER TO DONG PARK * * *

Further investigation revealed an Appendix J exemption that was granted for the Hatch Unit 2 local leak rate test (LLRT) program in the 1978 time frame that specifically addressed the primary containment penetration that has primary containment isolation valve (PCIV) 2P42-F051 as its outboard barrier and the 'closed' system as its inboard barrier. The exemption recognizes that this system is designed to be intact and water filled post-LOCA, allows testing of the of the PCIV with water and states that the leakage through this PCIV is not included in the 0.6 La total. Since the Hatch RBCCW system supplying components inside primary containment is a 'closed' system and remains intact and water filled post-LOCA, there is no leakage path from primary containment through this RBCCW penetration. Since no leakage from primary containment can occur through this penetration in its 'as found' state, this condition does not represent a condition that seriously degrades a principal safety barrier. As such this condition has been determined to no longer meet reporting requirement 10CFR50.72(b)(3) and is therefore not reportable. Based on this information the previous notification is being retracted. The licensee notified the NRC Resident Inspector. Notified R2DO (O'Donohue).

This is a one-hour report for the discovery of a condition that met an Emergency Activation Level (EAL) for a Notification of an Unusual Event (NOUE). EAL HU-1 - Natural and Destructive Phenomena Affecting the Protected Area Threshold Value 6 states, 'Exceed Max Normal Operating Values specified in EOP 31 EO-EOP-014-1 SC - Secondary Containment Control Table 5 Secondary Containment Operating Water Levels.' Plant Hatch Unit 1 declared a NOUE on 9/18/10 at 1627 based on HU-1 Natural and Destructive Phenomena Affecting the Protected Area due to exceeding the Max Normal Operating Value for the Reactor Building NE Diagonal Floor Drain Sump. At 1615, both the Level High and Level High-High annunciators alarmed. Water has not overflowed the sump. However, due to its design, it is not possible to immediately visually confirm the sump level. The sump pumps were not running and would not run with their switches in START indicating either: (1) there is no water in the sump, (2) both pumps are OOC (Out of Commission), or (3) there is a problem in the sump level control system. Maintenance is assessing the situation. The licensee has notified the state and local agencies and will notify the NRC Resident Inspector.

• * * UPDATE FROM STEVE BURTON TO HOWIE CROUCH @ 0427 EDT ON 9/19/10 * * *

At 0400 EDT, the NOUE was terminated. The termination criteria was that the NE Diagonal Floor Drain Sump level was in its normal operating range with no abnormal sump in-leakage detected. Compensatory measures are in place to measure level in the sump. An investigation into the abnormal level indication is still in progress. The licensee will be notifying state and local authorities as well as the NRC Resident Inspector. Notified R2DO (Henson), IRD (Gott), NRR EO (Howe), DHS (Inser) and FEMA (Via).

• * * RETRACTION FROM STEVE BURTON TO JOE O'HARA AT 1533 EDT ON 10/7/10 * * *

On September 18, 2010, a notification, Event Number 46258, was submitted to the NRC to report a circumstance at Plant Hatch Unit 1 which appeared to be a 'High-High' reactor building sump level alarm. Such an alarm would meet the designated Emergency Activation Level (EAL) for a Notification of an Unusual Event (NOUE). On the day of the event, it was thought that receipt of both the 'High' and 'High-High' level annunciators for the reactor building northeast diagonal floor drain sump was indicative of the sump level having reached its maximum normal operating level, and a NOUE was made. During a subsequent Investigation, engineering personnel determined that the 'High' and 'High-High' level switches for this sump are wired such that both alarms are actuated concurrently when the 'High' level in the sump is reached at approximately 52 Inches. The 'High-High' sump level annunciation (the level at which the NOUE must be made) Is supposed to alarm at approximately 60 inches. Engineering personnel also determined that the level logic is currently improperly configured to clear both the 'High' and 'High-High' level alarms when the sump level rises to 60 inches. The initial 'High' and 'High-High' level alarms in the main control room were received at approximately 1615 EDT on September 18, 2010. At that time the sump level would have reached an actual level of approximately 51 inches (albeit with a false indication of approximately 60 inches due to the configuration error noted above) based on the setpoint at which this alarm occurs. The normal leakage into this sump at the time of this event was at a rate of approximately 1 inch per hour. The sump pumps were started at approximately 1800 EDT to pump down the sump. This action resulted in a maximum actual sump level of approximately 53.5 inches, assuming the normal leakage into the sump was occurring during this period. At no time did the sump level actually reach the 'High-High' sump level criteria of 60 inches, nor did the annunciated level clear prior to pumping down the sump which also demonstrated that the 60 inch criteria was not met. It is now apparent that the initial NOUE was a conservative report that was properly made based on the information available to the operators at the time. The subsequent investigation provided additional information regarding actual sump level conditions including information that both 'High' and 'High-High' alarms annunciate at the 'High' sump level and would have cleared had the 'High-High' level been reached. Since the 'High-High' sump maximum normal operating level of 60 inches was never reached during this event, the determination has been made that the EAL was not appropriate given the actual sump conditions, thereby making the event non-reportable and an NOUE unnecessary. Based on the preceding Information, Southern Nuclear Company (SNC) hereby provides notification that Event Number 46256 is retracted. The licensee will notify the NRC Resident Inspector. Notified R2DO(McCoy).

At approximately 1816 EDT, loss of prompt notification system (tone alert radios) occurred. Security notified Jacksonville National Weather Service and Information Technology to investigate. Jacksonville National Weather Service determined a problem with their equipment and prompt notification system (tone alert radios) was returned to service at approximately 1845 eastern time. Security has notified state and local agencies of prompt notification system (tone alert radio) outage and return to service. The licensee has notified the NRC Resident Inspector. Licensee also notified State and local agencies.

* * * RETRACTION FROM FRANK GORLEY TO PETE SNYDER AT 1535 ON 3/25/10 * * * 

On 3/18/10 at approximately 11:40 am we started receiving an 'off-air' alarm for the Plant Hatch NOAA Weather Radio. Initially we determined that a loss of the prompt notification system had occurred due to the alarm and consultation with Jacksonville National Weather Service, Ref. 10 CFR 50.72 (b)(3)(xiii). NOAA personnel subsequently provided information to Plant Hatch personnel at which time it was learned that even though 'off-air' alarms were received for the NOAA Weather Radio, the radio was never off the air. While NOAA personnel were troubleshooting the system the broadcast was switched over to a digital backup system that continued to have the capability to warn the public. There was a problem noted in the broadcast that was causing several seconds of silence in the broadcast signal. While on the digital backup, the notification capability was maintained. The broadcast had been returned to the primary system today. During the time these activities were underway, broadcast capability to the public was never lost. Based on this information, Plant Hatch is entering a Notification of Retraction for the 8 hr. report documented to the NRC Event Number 45775, as entered on 3/18/10. The licensee will notify the NRC Resident Inspector. Notified R2DO (Franke).

During an inspection of the Unit 2 Reactor Building Steam Chase as a result of a similar situation being previously discovered on Unit 1, a storage gangbox was noted to be resting on one of the two hinged blowoff panels in the floor of the Steam Chase (elevation 130') and the hinged blowoff panels were determined to be restrained which would prevent their opening. The blowoff panels are designed to open to provide pressure and temperature relief between the torus room and 130 ft elevation of the reactor building for high energy steam line breaks. The 'as found' configuration of the blowoff panels hinder their capability to open, which constitutes a non-conforming and unanalyzed condition in that the vent area between the torus room and main steam chase in the reactor building is less than the area assumed in the analysis for a HPCI steam line break. As such, for a HPCl steam line break in the torus room, the short term pressure across the torus room ceiling would likely be greater than 2.3 psid, which is the maximum differential pressure stated in Chapter 15A of the Unit 2 FSAR. There is no known analyzed limit for the differential pressure between the torus room and the 130 ft elevation of the reactor building. The actual differential pressure given the 'as found' condition is not known at this time. Corrective actions have been taken to restore the assumed vent area between the torus room and the reactor building 130ft elevation. The gang box has been removed and both blow off panels no longer have restricted movement. The remaining 3' x 3' floor plug has also been removed, completely restoring the assumed vent area into compliance. Based on this information there is reasonable assurance that an adequate vent path currently exists such that the plant is no longer considered to be in a condition that significantly degrades plant safety. However, since the actual differential pressure given the 'as found' condition is not known at this time, the 'as found' condition as previously discussed is assumed to be an unanalyzed condition that represents a condition that significantly degraded plant safety; however, additional information is needed in order to more conclusively determine this. If more conclusive information is provided that indicates otherwise an update notification will follow. This was also reported under 10CFR50.72(b)(3)(v)(D). The licensee notified the NRC Resident Inspector.

• * * RETRACTION FROM GORLEY TO HUFFMAN AT 1435 EDT ON 8/30/07 * * *

A review of the 'as found' configuration of the plant was performed to determine if this configuration would still be bounded by the calculations that support the HELB analysis in the Unit 2 FSAR. The 'as found' configuration consisted of having one torus plug in place rather than open and the two hinged torus ceiling blow-off panels bolted shut instead of being free to open. This engineering review concluded that if the torus ceiling blow-off panels do not open and with only one torus plug open, the torus pressures will not exceed the current FSAR pressures. Additionally, the torus pressures were found to be acceptable as a result of the modeling of friction in the HPCI pipe break mass and energy releases. This being the case, for a HPCI steam line break in the torus room, the short term pressure across the torus room ceiling would be 1.93 psid for the 'as found' condition which is less than the maximum differential pressure of 2.27 psid as stated in Chapter 15A of the Unit 2 FSAR. It should be noted that corrective actions were taken upon discovery and that the assumed vent area between the torus room and the reactor building 130 ft elevation was restored shortly following discovery. The gang box was removed, the restraint on the blow-off panels removed and both blow-off panels were confirmed to have full range of motion to open if the conditions were present that would warrant that movement. Based on this review of the design calculations while taking the 'as found' conditions into consideration, the conclusion reached is that the nonconforming 'as found' conditions did not represent a condition that significantly degraded plant safety. For this reason this condition that was initially reported under 10CFR50.72(b)(3)(ii)(B) is being retracted. The licensee will notify the NRC Resident Inspector. R2DO(Shaeffer) notified.

Unit HPCI system declared inoperable. During performance of the quarterly surveillance, HPCI pump operability, the HPCI system was secured when the "HPCI Turbine Oil Pressure Low" alarm was received and confirmed. Turbine governor end bearing oil pressure was 2 PSIG. The alarm setpoint is 6 PSIG and procedure limit is 10-12 PSIG. Pressure adjust valve was throttled open to raise pressure to 11 PSIG. The HPCI system was not immediately declared inoperable since an evaluation was being performed to determine if 2 PSIG turbine bearing oil pressure was adequate. Evaluation by the vendor will not be complete until 10/18/06. At 1655 hours, HPCI declared operable after a successful run with adequate oil pressure. HPCI is a single train system. The licensee notified the NRC Resident Inspector.

• * * UPDATE PROVIDED BY NRC ON 11/06/06 AT 1106 EST DUE TO EVENT ENTRY ERROR * * *

Original report was entered in error on 10/17/06 with Unit 2 versus Unit 1. Changed EN #42914 to accurately reflect the affected unit (Unit 1).

• * * RETRACTION PROVIDED BY E. BURKETT TO KOZAL ON 11/16/06 AT 1039 * * *

EN #42914 was submitted by Southern Nuclear Operating Company based upon a conservative decision to declare the HPCI system inoperable pending further evaluation to support its operability. Southern Nuclear Operating Company retracts EN #42914 based on the following discussion. During a subsequent review of the parameters by the HPCI Turbine Vendor, Dresser-Rand, and site engineering it was concluded that the HPCI system would have been capable of performing its intended safety function with the lower turbine governor end bearing oil pressure. During the operation of the system, the visual local indication was approximately 2.5 PSIG oil pressure at the governor end bearing. A review of the data showed that with a governor end oil pressure of the procedural minimal of 10 PSIG, the predicted oil flow rate would be 1.08 gpm with a minimum film thickness of 0.48 mils and a maximum bearing temperature of 228 deg F. With a degraded oil pressure of 2.5 PSIG, the predicted oil flow rate would be 0.54 gpm with a minimum film thickness of 0.46 mils and a maximum bearing temperature of 233 deg F. Based on the calculated data, the turbine governor end bearing would have performed satisfactorily for at least 8 hours at an oil pressure of 2.5 PSIG. Using the design basis success criteria, HPCI operation is successful if the system can inject water through the core Feedwater line for a total of 4 hours over a 24 hour period. The 4 hour mission time for HPCI is based on the design basis - if HPCI fails, it is backed up by the Automatic Depressurization System (ADS) in combination with Core Spray and Low Pressure Coolant Injection. The HPCI system is not credited for long term injection or late injection. Although the oil flow rate was reduced by 50% and the minimum film thickness reduced by 4%, the bearing temperatures were predicted to only increase a maximum of 5 deg F. Supporting this conclusion is the fact that the bearing was not damaged during the operation with low oil pressure when the turbine was run for 9 minutes at 2.5 PSIG governor end bearing oil pressure. The licensee will notify the NRC Resident Inspector.

Based on increasing conductivity in the reactor vessel and condenser hotwell, a power reduction was initiated from 100 percent power. A manual scram was inserted at 57 percent RTP and 49 percent Core Flow based on Chemistry recommendations due to sulfates and chlorides in the hotwell. Following the scram a reduction in reactor water level to -28 inches resulted in a Primary Containment Group 2 Isolation (ESF) occurring. All isolations and systems responded as expected. Current plant status is Hot Shutdown with plans to proceed to cold shutdown. All control rods fully inserted and decay heat is being removed with the bypass valves into the condenser. The licensee notified the NRC Resident Inspector.

• * * RETRACTION FROM SHIFT SUPERVISOR (TONY SPRING) TO ABRAMOVITZ AT 16:33 ON 6/6/2005 * * *

After further review and evaluation it has been determined that the four hour call made May 23, 2005 per the guidance of 50.72(b)(2)(iv)(B) should be retracted. A review of the event with respect to NUREG 1022 Revision 2 determined that: The manual scram was part of a pre-planned sequence to shut the plant down due to an equipment problem. The manual scram was part of a pre-planned sequence. The guidance to scram the reactor was established by the plant's Abnormal Operating Procedure addressing a condenser tube leak and was part of a preplanned sequence to prevent future equipment and component failures. The Manual Scram was not inserted to protect the plant against an event that presented a challenge to an FSAR analyzed event. In other words, this was not an Anticipated Operational Occurrence, an Accident, or a Special Event as defined in section 15.1.3 of the Unit 2 FSAR. Rather it was part of a plan to shutdown the reactor to protect against future potential equipment problems due to out of limits chemistry parameters. Further justification is provided by the fact that the manual scram was not initiated in anticipation of an automatic scram. Per NUREG 1022 Rev. 2: 'The staff also considers intentional manual actions, in which one or more system components are actuated in response to actual plant conditions resulting from equipment failure or human error, to be reportable because such actions would usually mitigate the consequences of a significant event. This position is consistent with the statement that the commission is interested in events where a system was needed to mitigate the consequences of the event.' However, the reporting requirement itself indicates that actuations that result from pre-planned sequences are not reportable. An example is provided in the NUREG of an equipment problem involving the loss of recirc pumps. In this example it is stated that: 'Even though the reactor scram was in response to an existing written procedure, this event does not involve a preplanned sequence because the loss of the recirc pumps and the resultant off-normal procedure entry were event driven, not pre-planned.' This is similar to our event, however, in the NUREG example, the reactor is scrammed to protect against the possibility of a stability event and stability is an FSAR analyzed event. In our case we were shutting down for chemistry reasons, not an FSAR type event. It is concluded that when the RPS is used to shutdown the reactor as part of a plan for the resolution of equipment problems, and the RPS is not needed to mitigate the consequences of an FSAR analyzed event, i.e., one which threatens a fission product boundary (i.e., fuel cladding, RCPB, primary and secondary containments), the RPS actuation is not reportable under 50.72(b)(2)(iv)(B).

The licensee notified the NRC Resident Inspector. Notified R2DO (Haag).

• * * RETRACTION RESCINDED - S. BURTON TO M. RIPLEY 1524 EDT 06/08/05 * * *

On May 23, 2005 a four hour report was made per the guidance of 50.72(b)(2)(iv)(B), 'Any event or condition that results in an actuation of the RPS when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.' This was made per event # 41725. The report was made within the four hour time frame of 10 CFR 50.72(b)(2). The four hour report for event # 41725 was retracted on June 6, 2005. After further consideration, the retraction made on June 6, 2005 is being cancelled and the original report re-instated. The licensee notified the NRC Resident Inspector. Notified R2 DO (K. Landis)

While changing out a light bulb in the Unit 1 HPCI room, the surveillance operator noticed that the bolts for the HPCI pump discharge check valve, 1E41-F005, bonnet on pressure seal were loose. All six bolts could be turned by hand. HPCI was declared inoperable until an investigation is performed. The bolts were properly torqued and HPCI pump run is complete and sat. Licensee entered Technical Specification 3.5.1 (14 day Limiting Condition of Operation). All other Emergency Core Cooling Systems are fully operable including the Reactor Core Isolation Cooling System. The NRC Resident Inspector was notified of this event by the licensee.

• * * RETRACTION FROM DISMUKE TO CROUCH AT 1700 EDT ON 10/28/04 * * *

The following information was obtained from the licensee via facsimile: A subsequent investigation revealed that a hot torque of the Unit 1 HPCI pump discharge check valve (1E41-F005) was performed during the 165 psig pump operability surveillance test which was performed following reassembly during the Unit 1 refueling outage. During this surveillance, the pump discharge pressure and thus internal pressure on the pressure seal cover, is maintained between 265 and 305 psig. However, during the rated pressure run, the pump discharge pressure achieved is required to be greater than or equal to 1135 psig. This difference in internal pressure (1135-305 = 830 psig minimum), acting on the bottom of the pressure seal cover, forced the pressure seal cover to move upward toward the cover retainer, compressing the pressure seal more tightly. As the pressure seal cover moved toward the cover retainer, the retainer bolts also moved upward, but the cover retainer remained stationary, due to gravity. Therefore, the retainer bolts were no longer torqued against the retainer cover, creating the 'as found' condition. It is site and vendor (Flowserve) experience that once the pressure seal cover is wedged upward, sufficient friction exists between the pressure seal cover, the pressure seal, and the valve body to prevent the pressure seal cover from relaxing the sealing force on the pressure seal once the valve internal (system) pressure is removed. Furthermore, no gap existed between the head of any of the retainer bolts and the retainer cover. The sealing function of the pressure seal was never lost, and the valve would have performed its design function while the retainer bolts were in the 'as found' 'finger tight' condition. Therefore, the valve remained operable at all times when the HPCI system was required to be operable following the Unit 1 refueling outage. This was further substantiated by the fact that no leakage was observed during the rated pressure pump operability run on 3/14/04. Following discovery of the 'finger tight' condition, the retainer bolts were cold torqued to the appropriate value (370 ft-lbs) by Maintenance personnel on 6/17/04. A HPCI pump surveillance was then performed and a hot torque of 370 ft-lbs was performed immediately after the system was shutdown. Tampering was considered as a possible cause for the loosened bolts, but no evidence could be found to support these bolts being loosened intentionally. All evidence available suggests that the bolts were loosened by internal pressure, which is consistent with vendor experience. Based on the above information this event is not reportable, and this notification serves to withdraw the previous notification made on 6/17/2004. The licensee has notified the NRC Resident Inspector. The Headquarters Operations Officer notified R2DO (Bonser).

Site experienced a momentary loss of the NOAA Weather Radio System from 1916 to 1918 EST. During the time that this system was out of service, a major loss of offsite communication capability is considered. Site emergency planning personnel were notified and will investigate this momentary loss. The system is in service and functioning properly. The licensee notified both state/local agencies and will inform the NRC Resident Inspector.

• * * RETRACTION AT 1700 ON 4/9/04 RUSSELL TO GOTT * * *

After further investigation, a determination has been made that there was no major loss of offsite notification capability of the Hatch Prompt Notification System (NOAA Weather Radio System). The momentary losses reported were caused by testing of the primary audio feed line utilizing a tone generator while investigating the loss of this feed. The secondary audio feed from Jacksonville NWS remained operable during the time of testing. The Licensee notified the NRC Resident Inspector. Notified R2DO (Decker)