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The following information was provided by the licensee: At 2013 EST on March 9, 2022, the HPCI System was declared inoperable following evaluation of routine HPCI surveillance testing data indicating that the required response time for reaching rated conditions was not met. Therefore, this condition is being reported as an eight-hour, non-emergency notification per 10 CFR 50.72(b)(3)(v)(D). The Reactor Core Isolation Cooling (RCIC) System and Automatic Depressurization System (ADS) are operable. There was no impact on the health and safety of the public or plant personnel. Investigation is in-progress to determine the cause. Unit 1 is not affected by this event. Unit 1 is in a refueling outage. The NRC Resident Inspector has been notified.

• * * RETRACTION ON 05/04/22 AT 1135 EDT FROM CHARLIE BROOKSHIRE TO DAN LIVERMORE * * *

The following information was provided by the licensee via email: At 20:13 EST on March 9, 2022, the HPCI System was declared inoperable following evaluation of routine HPCI surveillance testing data indicating that the required response time for reaching rated flow and pressure was not met. Subsequent to this, it was determined that the required response time was overly conservative for assuring the safety function of the system could be fulfilled. The required response time was revised. The operability determination for this event has been updated indicating that system operability was never lost for this event. There was not a condition that could have prevented the system from fulfilling the safety function. The NRC Resident Inspector has been notified. Notified R2DO (Miller).

On August 4, 2017, at 1511 EDT, Unit 1 Secondary Containment was declared inoperable due to a small (i.e., approximately 0.75 inch diameter) hole in Service Water system piping which was found during ultrasonic testing activities. The affected portion of piping penetrates Secondary Containment and flow in the piping creates a vacuum condition; thus bypassing Secondary Containment. The identified hole is being evaluated with respect to its impact on operability of the Service Water system. This condition is being reported in accordance with 10 CFR 50.72(b)(3)(v)(C), as an event or condition that could have prevented fulfillment of a safety function needed to control the release of radioactive material. This event did not result in any adverse impact to the health and safety of the public. Initial Safety Significance Evaluation: The initial safety significance of this event is minimal. At the time of discovery, Unit 1 was at 100% steady state conditions. Reactor Building Ventilation was in service in a normal alignment. No abnormal radioactivity conditions existed within Secondary Containment. Corrective Actions: Temporary repair of the affected Unit 1 Service Water piping has been completed. This repair was evaluated by Engineering and it has been determined that the repair meets the requirements to maintain Secondary Containment operable. Unit 1 Secondary Containment operability was restored at 1704 EDT on August 4, 2017. The licensee notified the NRC Resident Inspector.

• * * RETRACTION FROM MIKE BRADEN TO RICHARD SMITH AT 1447 EDT ON 9/27/17 * * *

Based upon further evaluation, Duke Energy is retracting Event Notification 52888. The safety objective of Secondary Containment is to limit the release of radioactivity to the environment after an accident so that the resulting exposures are kept to a practical minimum and are within regulatory limits. A bounding engineering evaluation was performed which demonstrates that potential releases from Secondary Containment could not have resulted in offsite or control room doses exceeding regulatory limits. Furthermore, the condition did not impact Technical Specification operability of Secondary Containment in that the ability of Secondary Containment to maintain the required vacuum was not impacted. Therefore, this condition does not represent an event or condition that could have prevented fulfillment of a safety function needed to control the release of radioactive material and is not reportable in accordance with 10 CFR 50.72(b)(3)(v)(C), and the event notification is being retracted. The NRC Senior Resident was notified of this retraction. Notified R2DO (A. Masters).

On 2/24/2012 at 0037 EST, Unit 1 was in Mode 4 when an unplanned Reactor Protection System (RPS) actuation occurred. The trip occurred while operators were returning the Mode Switch to the 'Shutdown' position during restoration from Neutron Instrumentation testing. Jumpers had not been installed to bypass this actuation signal at the time the Mode Switch was operated, resulting in a valid signal of the RPS. The RPS actuation is reportable in accordance with 10 CFR 50.72(b)(3)(iv)(A). The safety significance of this event was minimal. Plant equipment performed as expected. All control rods were inserted prior to the RPS actuation and remain inserted. The RPS actuation was reset and the plant remains in Mode 4. The licensee has notified the NRC Resident Inspector.

• * * RETRACTION FROM MARK TURKAL TO JOHN KNOKE AT 1316 EST ON 3/1/12 * * *

Based on a detailed review of NUREG-1022, Revision 2, 'Event Reporting Guidelines 10 CFR 50.72 and 50.73,' this event has been determined not to be reportable under 10 CFR 50.72(b)(3)(iv)(A). The RPS actuation was inadvertent and was caused by a human error (i.e., failure to install appropriate jumpers) that occurred during a surveillance test. This RPS actuation was not in response to actual plant conditions satisfying the requirements for initiation of the RPS. There was no plant condition present that either warranted a scram or would prompt manual operator action in anticipation of scram condition. Therefore, this RPS actuation is considered invalid and is not reportable per 10 CFR 50.72(b)(3)(iv)(A). Investigation of this condition is documented in the corrective action program in Condition Report (CR) 519432. The NRC Resident Inspector was notified of this retraction." Notified the R2DO (Mark Franke).

EVENT DESCRIPTION: During return to service testing for Emergency Diesel Generator (EDG) #3, it was noted that the fuel rack limiting cylinder was not returning to its non-limiting position. The fuel rack limiting cylinder is designed to limit the stroke distance of the fuel rack assembly during the initial EDG start sequence. Once the EDG is at rated speed, ~10 seconds, the fuel rack limiting cylinder should return to its non-limiting position. Failure of this component to operate as expected may have prevented EDG #3 from fulfilling its safety function during the postulated Loss of Off Site Power and/or Loss of Coolant Accident conditions. As a result, EDG #3 remains inoperable. During performance of subsequent surveillance testing on the remaining EDG's (#1, #2, and #4), in accordance with Technical Specifications, a similar condition as described above existed on EDG #4. EDG's #1 and #2 did not exhibit the same behavior and therefore, these EDG's remained operable during this sequence of events. Consequently, EDG #4 was declared inoperable at 1430 on 1/01/09. Failure of this component to operate as expected may have prevented EDG #4 from fulfilling its safety function during the postulated Loss of Off Site Power and/or Loss of Coolant Accident conditions. The concurrent failure of this component on EDG #3 and EDG #4 may have prevented on-site emergency power to Emergency busses 3 & 4 and thus the fulfillment of a safety function needed to mitigate the consequences of an accident. INITIAL SAFETY SIGNIFICANCE EVALUATION: Plant operation is being maintained within the limiting conditions of the license expected. However, transient analyses relating to accident mitigation could have been impacted due to the inability to ensure emergency on-site power supply to Emergency busses 3 & 4. Off-site power and the grid have been stable during the time period both EDG's were inoperable. CORRECTIVE ACTIONS: The fuel rack limiting cylinder for EDG #4 was repaired and EDG #4 was restored to Operable on January 1, 2009 at 1755 EST. Actions required per technical specifications for 2 EDG's were exited within the required time frame. Repair efforts are in progress for EDG #3. The licensee informed the NRC Resident Inspector.

• * * RETRACTION PROVIDED BY LEE GRZECK TO JASON KOZAL AT 1530 ON 3/2/09 * * *

On January 1, 2009, at 2106 hours, the Control Room Shift Manager made a notification (i .e. Event Number 44748) to the NRC Operations Center in accordance with 10 CFR 50.72 (b) (3) (v) (D) (i.e., 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 mitigate the consequences of an accident). The notification was made due to two Emergency Diesel Generators (EDGs) being declared inoperable. During return to service testing for BSEP's EDG 3, it was noted that the fuel rack limit cylinder was not returning to its non-limiting position in a timeframe consistent with prior observations. The fuel rack limit cylinder is designed to limit the stroke of the fuel rack during the initial EDG start sequence, preventing too much fuel from being provided to the engine cylinders on initial start. Once the EDG is at half-rated speed (i.e., in approximately 5 to 8 seconds), the fuel rack limit cylinder should be released to return to its non-limiting position. Failure of this component to operate as expected may have prevented the EDG from fulfilling its safety function during the postulated Loss of Off-site Power (LOOP) and/or Loss of Coolant Accident (LOCA) conditions. As a result, EDG 3 was conservatively declared inoperable due to the potential for the unexpected response of the fuel rack limit cylinder to impact Design Basis Accident (DBA) transient loading criteria. During performance of subsequent surveillance testing on the remaining EDG's, (i.e.,1,2, and 4), in accordance with Technical Specifications, a similar condition was identified on EDG 4. EDGs 1 and 2 did not exhibit the same behavior and therefore, these EDGs remained operable during this sequence of events. Consequently, EDG 4 was also conservatively declared inoperable at 1430 on January 1, 2009. The concurrent failure of this component on EDG 3 and EDG 4 may have prevented the onsite emergency power from fulfilling its intended safety function needed to mitigate the consequences of an accident. Basis for Retraction Further investigation has demonstrated that both EDG 3 and EDG 4 were fully operable. The EDG 3 evaluation concluded that the fuel rack limit would remain in effect for approximately seven (7) seconds after the diesel output breaker closed during a LOOP loading event or a design basis LOOP/LOCA loading event. After that, the fuel limit cylinder would not have limited the governor response in any way. The generator capacity during the first seven seconds of load acceptance at the fuel rack limited position would be sufficient to ensure proper acceleration of the 480-volt design basis loads and the Nuclear Service Water pump. These are the only loads expected to start during the first seven seconds of the EDG loading. The generator frequency response during the acceleration of these loads would be well within the EDG design limits. The Residual Heat Removal and Core Spray pumps are sequenced onto the EDG at 10 seconds and 15 seconds, respectively, following the closure of its output breaker and are not affected by the fuel limiter impairment. The EDG 4 evaluation is bounded by the above analysis. Therefore, the fuel rack limiter impairment would not have prevented either EDG 3 or EDG 4 from fulfilling their intended safety function. On this basis, this event is not reportable under 10 CFR 50.72(b) (3) (v) (D). Investigation of this condition is documented in the corrective action program in Nuclear Condition Report (NCR) 312876. The NRC resident was notified of this retraction. R2DO (Musser) has been notified.

At 1645 EDT, it was determined that an unacceptable flaw existed in reactor pressure vessel penetration N9. This penetration leads to a capped line and the flaw is in the cap-to-pipe weld. Based on manual ultrasonic examination, the flaw is 6.2 inches in length on a 5.5 inch OD pipe. Using non-qualified ultrasonic sizing techniques, the flaw is estimated to have a maximum depth of 30 percent through-wall. The flaw was discovered during in-service inspection examination of this penetration, using an improved technique compared to the technique used during a 2004 inspection. The flaw has been found unacceptable per paragraph IWB-3514.4 of the 1989 Edition of ASME Section XI Code and is therefore reportable. A weld overlay repair is being planned. The safety significance of this is minimal. Unit 1 is currently in a refueling outage. Repairs of the affected weld will be completed prior to startup. The licensee notified the NRC Resident Inspector.

• * * RETRACTION PROVIDED BY BILL MURRAY TO JASON KOZAL AT 0946 ON 5/23/08 * * *

On March 27,2008, at 2027 hours, the Control Room Supervisor made a notification (Event Number 44102) to the NRC Operations Center in Accordance with 10 CFR 50.72(b)(3)(ii)(A) (i.e., any event or condition that results in the condition of the nuclear power plant, including its principal safety barriers, being seriously degraded). The notification was made as a result of determining that an unacceptable flaw existed in the reactor pressure vessel penetration N9 (control rod drive system return line) nozzle-to-pipe cap weld. At the time of discovery, based on manual ultrasonic examination, the flaw was determined to be 6.2 inches in length on a 5.5-inch OD pipe. Using non-qualified ultrasonic depth sizing techniques, the flaw was estimated to have a maximum depth of 30 percent through-wall. The flaw was found unacceptable in accordance with paragraph IWB-3514.4 of the 1989 Edition of ASME Code, Section XI and therefore was reportable. Basis for Retraction On March 30, 2008, manually indexed phased-array ultrasonic examination of the CRD return line nozzle-to-array caw weld was preformed. Based on these inspections, it was determined that the indication does not exhibit stress corrosion cracking characteristics and is not consistent with ultrasonic responses associated with inside diameter (ID) connected geometry. Therefore, the CRD return line nozzle-to-pipe cap weld is acceptable from an ASME Code Section XI perspective. On this basis, the indication did not result in the condition of the nuclear power plant, including its principal safety barriers, being seriously degraded and the issue is not reportable under 10 CFR 50,72(b)(3)(ii)(A). Investigation of this condition is documented in the corrective action program in Nuclear Condition Report (NCR) 272454. The NRC resident was notified of this retraction. Notified R2DO (Vias).

On October 13, 2006 at 1357 (EST) Unit 2 HPCI system was declared inoperable due to indications of a leaking rupture diaphragm in the turbine steam exhaust line. This determination was made when water was discovered in the E41-PSH-N012A and E41-PSH-N012C instrument lines during the performance of 0MST- HPCI23Q (HPCI Turbine Exhaust Diaphragm High Pressure Instrument Channel Calibration). TS LCO 3.5.1. 'ECCS - Operating,' Condition D was entered for the HPCI system being declared inoperable. The Reactor Core Isolation Cooling (RCIC) system was verified operable per Required Action D.1. Required Action D.2 of TS LCO 3.5.1 requires the HPCI system to be returned to operable status within 14 days. The initial safety significance of this condition is considered to be minimal. The RCIC system and all other required ECCS, are operable at this time. HPCI has been isolated and will be placed under clearance to allow the turbine exhaust diaphragm to be inspected and replaced if necessary

The (NRC) Resident Inspector has been notified.
* * * RETRACTION FROM M. TURKAL TO P. SNYDER ON 12/05/06 * * * 

Upon further review, it has been determined that the HPCI system was not rendered inoperable as a result of the condition identified on October 13, 2006. The HPCI system is equipped with two rupture diaphragms on the steam exhaust line installed in series. Between the rupture discs are four instrument lines leading to pressure switches (i.e., E41-PSH-N012A, N012B, N012C, and N012D) and a header vent line that vents to the HPCI room atmosphere. The HPCI Turbine Exhaust Diaphragm Pressure - High signals are initiated from these pressure switches; which are required to be operable per Technical Specification 3.3.6.1, 'Primary Containment Isolation Instrumentation,' to isolate the HPCI exhaust line in the event of a degraded inner rupture disc, before the redundant outer disc is significantly challenged. This isolation provides equipment protection and (is) not assumed in any transient or accident analysis. The suspected leaking inner rupture diaphragm was confirmed to be fully intact and, as such, not a source of the water (i.e., approximately 1.125 quarts) in the E41-PSH-N012A and E41-PSH-N012C instrument lines. The most likely source of this water is residual water remaining from a rupture disc failure that occurred in November 2003. Engineering has evaluated the potential impact of the residual water and determined that both the HPCI system and the HPCI Turbine Exhaust Diaphragm Pressure - High isolation function remained operable. There was not sufficient water in the lines to affect the function of the HPCI rupture diaphragms if required. In addition, the quantity of water discovered would not have prevented a HPCI initiation, if required, as evidenced by successful operation of the Unit 2 HPCI system on at least 10 occasions since November 2003. The Technical Specification required function of the pressure switches was not impacted by the presence of residual water. Investigation of this condition is documented in the corrective action program is Nuclear Condition Report (NCR) 209265. On this basis, the HPCI system was capable of performing its function to mitigate the consequences of an accident and the issue is not reportable under 10 CFR 50.72(b)(3)(v)(D). The NRC Resident Inspector was notified of this retraction. Notified R2DO (Landis).

During plant startup from the Brunswick Unit 1 Refueling Outage, the High Pressure Coolant Injection (HPCI) System was declared inoperable due to pump data not meeting the acceptable value of OPT-09.2, HPCI System Operability Test. With pump flow established at the reference value of 4550 gallons per minute, the actual turbine speed was 2530 rpm, outside the acceptable range of 2485-2515 rpm. Initial Safety Significance Evaluation: Minimal since the Automatic Depressurization System (ADS), the Low Pressure Coolant Injection System (LPCI), and the Core Spray System are Operable. In addition the Reactor Core Isolation Cooling System (RCIC) is Operable. Corrective Actions: Engineering to evaluate the test results and determine corrective actions. The licensee will notify the NRC Resident Inspector.

• * * RETRACTION TAKEN ON 5/6/04 @ 1534 EDT BY CROUCH FROM ELBERFELD * * *

The following information was obtained from the licensee via facsimile: The purpose of this call is to retract the notification (Event Number 40636) made by the Brunswick Steam Electric Plant, Unit No, 1, Docket No. 50-325 / License No. DPR-71, on April 3, 2004, at 0549 hours. On April 2, 2004, at 2324 hours, the High Pressure Coolant Injection (HPCI) system was declared inoperable for scheduled testing performed in accordance with 0PT-09.2, 'HPCI System Operability Test.' 0PT-09.2 includes, in part, Technical Specification (TS) Surveillance Requirement (SR) 3.5.1.7, to verify that, with reactor pressure < 1045 and > 945 psig, the HPCI pump unit could develop a flow rate > 4250 gpm against a system head corresponding to reactor pressure. The testing also includes in part, In-service Test (IST) program requirements for HPCI pump performance (to test for pump degradation). During this testing, water is circulated from the Condensate Storage Tank (CST) through the HPCI pump and back to the CST through a 'Bypass to CST' valve. Motive force for the pump is provided by reactor steam being routed through the HPCI turbine into the suppression pool. Due to the heat energy being deposited in the suppression pool, time for HPCI turbine/pump testing is limited. When tested, the HPCI pump passed the TS SR 3.5.1.7 pump pressure and flow rate test requirements. However, when HPCI turbine speed was set to the IST-required value of 2,500 rpm, as indicated by the control room indicator 1-E41-C002-4 (the preferred indication), the IST required system flow of 4,550 gpm could not be attained. Turbine speed was then adjusted, using a portable speed indicator, to attain 4,550 gpm system flow. The portable speed indicator read 2530 rpm, high, outside the acceptable range of 2,485 to 2,515 rpm. The unsatisfactory test indicated potential pump degradation. The IST program requires the equipment to be declared inoperable until unsatisfactory test results are evaluated. On April 3, 2004, at 0436 hours, the HPCI system was declared inoperable due to the unsatisfactory test. At 0549 hours, the NRC was notified (Event Number 40636) in accordance with 10 CFR 50.72(b)(3)(v)(D) as a condition that at the time of discovery could have prevented the fulfillment of the safety function of a system needed to mitigate the consequences of an accident. During the testing with the portable speed indicator, it was noted that the control room indicator 1-E41-C002-4 was reading high (i.e., 1-E41-C002-4 was reading 2,600 rpm compared to 2,500 rpm on the portable speed indicator). Turbine speed indicator 1-E41-C002-4 was adjusted back to within required accuracy in accordance with Work Order 306977. After the initial test, a thorough review of pump data, instrument calibration data, and IST program guidance was conducted. It was determined that there was no indication of pump degradation and no indication of a flow indicator problem. Having corrected a speed indicator problem, sections of 0PT-09.2 were performed on April 5, 2004, to test for pump degradation using the preferred speed indicator 1-E41-C002-4. Test results were satisfactory and demonstrated that the pump performance met the IST program requirements. The HPCI system was declared operable on April 5, 2004, at approximately 0521 hours. Investigation of this condition is documented in the corrective action program in Action Request (AR) 123551. NUREG-1022, Rev. 2, Section 3.2.7 (page 56) lists types of events or conditions that are generally not reportable under 10 CFR 50.72(b)(3)(v) and 10 CFR 50.73 (a)(2)(v) criteria. The list of not-reportable conditions includes: - Removal of a system or part of a system from service as part of a planned evolution for maintenance or surveillance testing when done in accordance with an approved procedure and the plant's TS (unless a condition is discovered that could have prevented the system from performing its function) On April 2, 2004, the HPCI system was removed from service for testing in accordance with an approved procedure 0PT-09.2. The system was declared inoperable due to the test results discussed above, and since the HPCI system is a single train safety system, an ENS notification was made. However, no condition was discovered that could have prevented the HPCI system from performing its functions. Carolina Power & Light Company, doing business as Progress Energy Carolinas, Inc., has determined that this event does not meet the 10 CFR 50.72 or 10 CFR 50.73 reporting criteria and the notification for Event Number 40636 is retracted. The resident inspector has been notified.