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| Site | Quarter | Title | Description | |
|---|---|---|---|---|
| 05000354/FIN-2018003-04 | Hope Creek | 2018Q3 | Enforcement Action (EA)-18-044: EGM on Dispositioning BWR Licensee Noncompliance With TS Containment Requirements During Operations With A Potential For Draining The Reactor Vessel (EGM-11-003) | From April 19 through April 29, 2018, HCGS performed OPDRVs without establishing secondary containment integrity. An OPDRV is an activity that could result in the draining or siphoning of the reactor pressure vessel water level below the top of fuel, without crediting the use of mitigating measures to terminate the uncovering of fuel. TS 3.6.5.1, Secondary Containment Integrity, requires that secondary containment integrity be maintained, and is applicable during OPDRVs. The required action for this specification without secondary containment integrity in this condition of applicability is to suspend OPDRVs. As reported in LER 05000354/2018-001, HCGS conducted the following OPDRVs during the period of secondary containment inoperability: Control rod drive mechanism replacements; Local power range monitor replacements; and Cavity let down via Reactor Water Clean Up system. Additionally, an unplanned OPDRV occurred due to RHR system relief valves seat leakage. NRC EGM 11-03, EGM on Dispositioning BWR Licensee Noncompliance With TS Containment Requirements During Operations With A Potential For Draining The Reactor Vessel, Revision 3, provides, in part, for the exercise of enforcement discretion only if the licensee demonstrates that it has met specific criteria during an OPDRV activity. The inspectors assessed that HCGS adequately implemented these criteria. In accordance with EGM 11-003, in order to continue to receive enforcement discretion, a license amendment request (LAR) must be submitted and accepted for review within 12 months of the NRC staffs publication of the generic change that occurred on December 20, 2016. The inspectors verified that PSEG submitted the required LAR on September 20, 2017 (ADAMS Accession No. ML17265A847), and that it was subsequently accepted by the NRC for review by a letter dated October 25, 2017 (ADAMS Accession No. ML17299A009). Corrective Action: PSEG submitted an LAR to adopt TS Task Force Traveler 542, Reactor Pressure Vessel Water Inventory Control, on September 20, 2017, that was subsequently accepted by the NRC for review on October 25, 2017. (After the end of the inspection period, on October 30, 2018, the NRC staff responded (ML18260A203) to PSEGs LAR dated September 20, 2017, and issued License Amendment No. 213 that revised the technical specifications to adopt TSTF-542, Revision 2. Corrective Action Reference: 20792923 15 Enforcement: Violation: TS 3.6.5.1, Secondary Containment Integrity, requires that secondary containment integrity be maintained, and is applicable during OPDRVs. The required action for this specification without secondary containment integrity in this condition of applicability is to suspend OPDRVs. Contrary to the above, from April 19 through April 29, 2018, HCGS performed OPDRVs without secondary containment integrity. Therefore, set and maintain secondary containment integrity during OPDRVs without suspending the operation was considered a condition prohibited by TSs as defined by 10 CFR 50.73(a)(2)(i)(B). Basis for Discretion: The NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy because all criteria described in EGM 11-003 were met and enforcement discretion was previously authorized by EA-2017-071; therefore, no enforcement action will be issued for this violation. The disposition of this violation closes LER 05000354/2018-001-00. |
| 05000387/FIN-2018002-04 | Susquehanna | 2018Q2 | EGM on Dispositioning BWR Licensee Noncompliance With TS Containment Requirements During Operations With A Potential For Draining The Reactor Vessel (EGM-11-03) | From April 2 through April 24, 2018, Susquehanna performed OPDRVs without establishing secondary containment integrity. An OPDRV is an activity that could result in the draining or siphoning of the reactor pressure vessel water level below the top of fuel, without crediting the use of mitigating measures to terminate the uncovering of fuel. TS 3.6.4.1, Secondary Containment, requires that secondary containment be operable, and is applicable during OPDRVs. The required action for this specification if secondary containment is inoperable in this condition of applicability is to initiate actions to suspend OPDRVs immediately. As reported in LER 05000387/2018-001, Susquehanna conducted the following OPDRVs during the period of secondary containment inoperability: Recirculation system maintenance and pump replacement; Reactor water cleanup system flushes and maintenance; RHR system maintenance; Hydraulic control unit and control rod drive system maintenance; Local power range monitor replacements, including Intermediate Range Monitor 1E Dry Tube replacement; Control rod drive mechanism replacements; and Core spray instrument line flush. NRC EGM 11-03, EGM on Dispositioning BWR Licensee Noncompliance With TS Containment Requirements During Operations With A Potential For Draining The Reactor Vessel, Revision 3, provides, in part, for the exercise of enforcement discretion only if the licensee demonstrates that it has met specific criteria during an OPDRV activity. The inspectors assessed that Susquehanna adequately implemented these criteria. In accordance with EGM 11-003, in order to continue to receive enforcement discretion, a license amendment request (LAR) must be submitted and accepted for review within 12 months of the NRC staffs publication of the generic change, which occurred on December 20, 2016. The inspectors verified that Susquehanna submitted the required LAR on September 20, 2017 (ADAMS Accession No. ML17265A434), and that it was subsequently accepted by the NRC for review by a letter dated October 16, 2017 (ADAMS Accession No. ML17290A024).Corrective Action: Susquehanna submitted an LAR to adopt TS Task Force Traveler 542, Reactor Pressure Vessel Water Inventory Control, on September 20, 2017.Corrective Action Reference: AR-2015-01733 Enforcement: Violation: TS 3.6.4.1, Secondary Containment, requires that secondary containment be operable, and is applicable during OPDRVs. The required action for this specification if secondary containment is inoperable in this condition of applicability is to initiate actions to suspend OPDRVs immediately. Therefore, failing to maintain secondary containment operability during OPDRVs without initiating actions to suspend the operation was considered a condition prohibited by TSs as defined by 10 CFR 50.73(a)(2)(i)(B). Contrary to the above,from April 2 through April 24, 2018, Susquehanna performed OPDRVs without establishing secondary containment integrity. Basis for Discretion: The NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy because all criteria described in EGM 11-003 were met, enforcement discretion was previously authorized by EA-2017-089, and the licensee submitted an LAR on September 20, 2017 which was subsequently accepted by the NRC for review on October 16, 2017, and, therefore, will not issue enforcement action for this violation. The disposition of this violation closes LER 05000387/2018-001-00. |
| 05000286/FIN-2018002-01 | Indian Point | 2018Q2 | Reactor Pressure Boundary Leakage Due to Weld Failure in Reactor Vessel Head Penetration #3 | A self-revealing Severity Level IV NCV of Technical Specification (TS) 3.4.13.a, Reactor Coolant System Operational Leakage, was identified when Entergy operated the reactor in Mode 1 with pressure boundary leakage for a period of time longer than the allowable limiting condition of operation. Specifically, a leak in the J-weld around reactor pressure vessel (RPV) head penetration #3 occurred during the last operating cycle and was not identified until after the reactor was shutdown for a refueling outage. |
| 05000416/FIN-2018002-07 | Grand Gulf | 2018Q2 | Loss of Shutdown Cooling | A self-revealed,Green non-cited violation of Technical Specification 5.4, Procedures,for the licensees failure to follow written procedures was identified when the residual heat removal (RHR) system automatically isolated due to an inadvertent emergency core cooling system (ECCS) actuation. While the plant was shut down with the RHR system in decay heat removal mode, maintenance personnel inadvertently opened an incorrect valve during a transmitter calibration activity, which caused a false low reactor pressure vessel (RPV) water level signal, an ECCS actuation, and a loss of decay heat removal for approximately 31 minutes |
| 05000458/FIN-2018012-06 | River Bend | 2018Q2 | Failure to Provide Adequate Procedures for Post-Scram Recovery | The inspectors reviewed a self-revealed, non-cited violation of Technical Specification 5.4.1.a for the licensees failure to establish, implement and maintain a procedure required by Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978. Specifically, Procedure OSP-0053, Emergency and Transient Response Support Procedure, Revision 22, which is required by Regulatory Guide 1.33, inappropriately directed operations personnel to establish feedwater flow to the reactor pressure vessel using the main feedwater regulating valve as part of the post-scram actions. This resulted in the main feedwater regulating valves being operated outside their design limits. This resulted in catastrophic failure of the main feedwater regulating valve variseals and subsequent damage to multiple fuel assemblies. |
| 05000219/FIN-2018001-02 | Oyster Creek | 2018Q1 | Enforcement Action (EA)-18-007: No. 2 Emergency Diesel Generator Ring Lug Failure | On October 9, 2017, during a routine surveillance load test, the No. 2 emergency diesel generator failed approximately 5 minutes into the run due to a broken ring lug on a current transformer. Laboratory analysis of the broken ring lug determined that the ring lug failed due to fatigue cracking that was initiated due to stresses caused by bending and twisting of the electrical lug. Exelon last conducted a load surveillance on the No. 2 emergency diesel generator on September 25, 2017. Corrective Actions: Corrective actions included replacement on the broken ring lug on the No. 2 emergency diesel generator, extent of condition inspections on the No. 1 and No. 2 emergency diesel generators for additional bent or twisted ring lug connectors, and revision to the electrical ring lug installation and emergency diesel generator procedures to include inspection for bent or twisted ring lugs. Corrective Action Reference(s): Issue report 4060815 Enforcement:Violation: Oyster Creek Technical Specification 3.7.C.2.b states, in part, that if one diesel generator becomes inoperable during power operation, the reactor may remain in operation for a period not to exceed 7 days. Contrary to the above, on October 9, 2017, it was recognized that one diesel generator was inoperable for greater than the technical specification allowed outage time of 7 days, and Oyster Creek continued power operation. Specifically, on October 9, 2017, No. 2 emergency diesel generator failed to run during a routine surveillance test due to a broken ring lug on a current transformer, which resulted in a total inoperability time of 6.5 months.Severity/Significance: For violations warranting enforcement discretion, Inspection Manual Chapter 0612 does not require a detailed risk evaluation, however, safety significance characterization is appropriate. A Region I Senior Reactor Analyst (SRA) performed a best estimate analysis of the safety significance using the Oyster Creek Standardized Plant Analysis Risk (SPAR) model, Version 8.50 and Systems Analysis Programs for Hands-On Integrated Reliability Evaluations (SAPHIRE). The evaluation estimated the total (internal and external events risk) increase in core damage frequency (CDF) to be in the mid to high E-6/yr range, or a low to moderate safety significance. The SRA evaluated the internal events risk contribution due to the inoperability of the No. 2 emergency diesel generator for an approximate 6.5 month exposure time. The exposure time relative to when the No. 2 emergency diesel generator was no longer capable of meeting its 24 hour mission time is uncertain due to the effect of vibration induced fatigue, and therefore the method prescribed within the RASP handbook guidance was used. 9 The analyst used the guidance in Section 2.5 of the Handbook, Revision 2.0, to estimate the exposure time of 6.5 months based on the cumulative 24 hour summation of the No. 2 emergency diesel generator surveillance test proven run time. This approach is appropriate for periodically operated components that degrade during operation (i.e. vibration induced fatigue only occurs while the emergency diesel generator is in-service/operating). Given this approach, the dominant internal events, loss of offsite power were evaluated for the estimated internal risk increase. This contribution was estimated at 2E-6/yr increase in CDF. The dominant sequences involved loss of offsite power events with a concurrent failure of the No. 1 emergency diesel generator, failure of the combustion turbines, and failure to recover offsite power or recover an emergency diesel generator prior to core damage.The SRA performed various modeling changes after a review of revised calculations for DC battery life:Analysis noted that Oyster Creek Generating Station recirculation pump seals are similar in design to those tested in reports generated for Nine Mile Point Unit 1 with the use of CAN2A seals. Therefore, the failure probability of the seals in the station blackout sequence wasadjusted from 0.1 to 5E-2 similar to Nine Mile Point Unit 1 SPAR model 8.50.The failure to load shed action (DCP-XHE-XM-LSHED) in the model was calculated using the SPAR-H method and revised to 1.2E-2 versus being assumed to always fail (TRUE).Failure probabilities for 1, 2, or 3 stuck open electromatic relief valves were revised to be consistent with the previous model version 8.22 because of the isolation condenser design at Oyster Creek Generating Station which limits cycling and significantly reduces the probability of a failed open electromatic relief valve due to isolation condensers controlling pressure.The depressurization function using electromatic relief valves, if required, was calculated through SPAR-H to be 1E-2 for sequences where total seal failure is assumed (DEPSEALFAIL) (conservatively assumed limited time available).The diesel driven firewater pumps are both available and were set to calculated fault tree failure probabilities instead of always failed in the previous model. These are 2,000 gallons per minute pumps with a large supply of water and relatively simple operator actions to inject to the reactor pressure vessel. The firewater was assumed to fail at 0.1 when a total recirculation seal failure occurs due to assumed time constraints.The offsite power and the emergency diesel generator required recovery time events were increased to 24 hours for events where DC load shedding was successful, without seal failures and isolation condenser success along with diesel driven firewater success.The SRA noted the No. 2 emergency diesel generator was recoverable. In fact, the diagnosis of the failed condition was performed in a nominal 8-10 hours from the failure. Therefore, a probability of failure to recover event for the conditional case was developed. The SRA used SPAR-H as simple guidance, which conservatively supported a reasonable assumption of a 0.10 conditional probability of failure to recover the emergency diesel generator within 24 hours. The base case utilized a calculation within SPAR of 0.33 failure to recover probability for 24 hour sequences. To estimate the external risk contribution, the SRA identified that the most significant external risk contribution was from fire events. Seismic, external flooding, and high wind events were not significant contributors for the issue. From discussions with Oyster Creek Fire probabilistic risk analysts and a review of this failure condition, the increase in CDF due to the failed No. 2 emergency diesel generator for the assumed 6.5 month exposure time was estimated at 4.5E-6/yr ((8.5E-5/yr-4.5E-5/yr) x (6.5/12 months) x 0.2).The DC safety-related battery life would be at least a nominal 14 hours and longer if DC bus stripping occurred, this allows for extended isolation condenser or electromatic relief valve function, with injection from diesel driven firewater. Given the time considerations and characteristics of the failure, an assumed recovery at a failure probability of 0.2 (slightly higher than internal due to less time) was applied for the No. 2 emergency diesel generator, which was a best estimate determined through SPAR-H insights. The dominant fire sequence was a fire affecting the A and B 4kV switchgear rooms, where combustion turbine support would be lost, with failure of the No. 1 emergency diesel generator breaker to close, and failure of locally operating the isolation condenser due to eventual loss of power. The SRA noted that FLEX credit was not quantified and would result in a lower risk estimation likely in the low E-6/yr range. Combining internal and external risk contributions, the total increase in CDF was 6.5E-6/yr, or low to moderate safety significance. The SRA determined that Exelon uses a Large Early Release Frequency (LERF) factor value of 8E-2. This value takes into consideration operator action for those relevant high pressure vessel breach scenarios (fuel-coolant interaction, liner-melt-through, and direct containment heating). This also credits procedure strategies where other mitigating actions are taken such as flooding the drywell. The SRA review of the dominant sequences and time to core damage affirmed that LERF did not increase the risk over that determined from the increase in CDF.Basis for Discretion: The inspectors determined that the ring lug failure was not within Exelons ability to foresee and prevent. As a result, no performance deficiency was identified. The inspectors assessment considered:1. Exelons review of emergency diesel maintenance performed in 2015 checked allconnections of the current transformer for tightness. The inspectors did not identify any gaps or deficiencies in the 2015 inspections. Inspectors also reviewed completed biennial inspections of the connection dating back to 1991 and did not identify any gaps.2. At the time of the failure, the current transformer connections did not have a time directed replacement frequency recommended by the Emergency Diesel Generator Owners Group. The inspectors did not identify any additional vendor or industry recommendations specific to the failed component or considerations specific to the failed component that existed prior to the failure.3. Industry operating experience information available to Exelon did not identify the potential for the fatigue cracking of the bent wire ring lug that was experienced.4. The bent ring lug failure was not the result of a failure on the part of Exelon staff; no standards existed on bending of the lug during installation and is considered skill of the craft.The NRC determined that it was not reasonable for Exelon to have been able to foresee and prevent this violation of NRC requirements, and as such, no performance deficiency existed. Therefore, the NRC has decided to exercise enforcement discretion in accordance with Sections 2.2.4 and 3.10 of the NRC Enforcement Policy and refrain from issuing enforcement action for the violation of technical specifications (EA-18-007). Further, because Exelons actions did not contribute to this violation, it will not be considered in the assessment process or the NRC Action Matrix. Exelons equipment corrective action program evaluation report (ECAPE) determined that the ring lug failed on the No. 2 emergency diesel generator as a result of fatigue cracking, which was initiated due to excessive stress caused by bending and twisting of the ring lug beyond limits specified in industry guidelines. The inspectors noted that the ECAPE did not provide supporting information regarding how the ring lug was bent and twisted beyond industry guidelines. Specifically, industry guidance states that ring lugs can be bent up to 90 degrees. The broken ring lug found in the No. 2 emergency diesel generator was bent at approximately 45-55 degrees per the ECAPE, which was within industry guidelines. Additionally, the ECAPE did not include specific guidance on twisting allowances for ring lugs. Exelon documented the inspectors observation in Issue Report 4089829. As a result of the inspectors observation, Exelon revised the ECAPE to say the ring lug failed on the No. 2 emergency diesel generator as a result of fatigue cracking, which was initiated due to excessive stress caused by bending and twisting of the ring lug. |
| 05000440/FIN-2017002-02 | Perry | 2017Q2 | Implementation of Enforcement Guidance Memorandum 11003, Revision 3 | From March 17, 2017, to March 24, 2017, Perry Nuclear Power Plant (PNPP) performed Operations with the Potential to Drain the Reactor Vessel (OPDRV) while in Mode 5 without an operable primary and secondary containment. An OPDRV is an activity that could result in the draining or siphoning of the reactor pressure vessel water level below the top of fuel, without crediting the use of mitigating measures to terminate the uncovering of fuel. Secondary containment was required by TS 3.6.4.1 to be operable during OPDRVs. Primary containment was required by TS 3.6.1.10 to be operable during OPDRVS. The required action for these specifications was to suspend OPDRV operations. Therefore, entering the OPDRV without establishing primary and secondary containment integrity was considered a condition prohibited by TS as defined by 10 CFR 50.73(a)(2)(i)(B).The NRC issued Enforcement Guidance Memorandum (EGM) 11003, Revision 3, on January 15, 2016, to provide guidance on how to disposition boiling water reactor licensee noncompliance with TS containment requirements during OPDRV operations. The NRC considers enforcement discretion related to secondary containment operability during Mode 5 OPDRV activities appropriate because the associated interim actions necessary to receive the discretion ensure an adequate level of safety by requiring licensees immediate actions to (1) adhere to the NRC plain language meaning of OPDRV activities; (2) meet the requirements which specify the minimum makeup flow rate and water inventory based on OPDRV activities with long drain down times; (3) ensure that adequate defense in depth is maintained to minimize the potential for the release of fission products with secondary containment not operable by (a) monitoring RPV level to identify the onset of a loss of inventory event, (b) maintaining the capability to isolate the potential leakage paths, (c) prohibiting Mode 4 (cold shutdown) OPDRV activities, and (d) prohibiting movement of irradiated fuel with the spent fuel storage pool gates removed in Mode 5; and (4) ensure that licensees follow all other Mode 5 TS requirements for OPDRV activities.The inspectors reviewed licensee event report (LER) 201700100 for potential performance deficiencies and/or violations of regulatory requirements. The inspectors also reviewed the stations implementation of the EGM during OPDRVs:The inspectors observed that the OPDRV activities were logged in the control room narrative logs, the log entry appropriately recorded the standby source of makeup water designated for the evolutions, and that defense in-depth criteria were in place.The inspectors noted that the reactor vessel water level was maintained at least 22 feet and 9 inches over the top of the reactor pressure vessel flange as required by TS 3.9.6. The inspectors also verified that at least one safety-related pump was the standby source of makeup designated in the control room narrative logs for the evolutions. The inspectors confirmed that the worst case estimated time to drain the reactor cavity to the reactor pressure vessel flange was greater than 24 hours.The inspectors reviewed Engineering Change documents which calculated the time to drain down during these activities and the feasibility of pre-planned actions the station would take to isolate potential leakage paths during these periods of time. The inspectors verified that the OPDRVs were not conducted in Mode 4 and that the licensee did not move irradiated fuel during the OPDRVs. The inspectors noted that PNPP had in place a contingency plan for isolating the potential leakage path and verified that two independent means of measuring reactor pressure vessel water level were available for identifying the onset of loss of inventory events.The inspectors verified that all other TS requirements were met during the March 17, 2017, to March 24 2017, OPDRVs with primary and secondary containment inoperable.Technical Specification 3.6.4.1 required, in part, that secondary containment shall be operable during OPDRV. Technical Specification 3.6.4.1, Condition C, required the licensee to initiate action to suspend OPDRV immediately when secondary containment is inoperable. Technical specification 3.6.1.10 required, in part, that primary containment shall be operable during OPDRV. Technical specification 3.6.1.10, Condition A, required the licensee initiate action to suspend OPDRV immediately when primary containment is inoperable. From March 17, 2017, to March 24, 2017, PNPP performed OPDRV activities while in Mode 5 without an operable primary or secondary containment. Specifically, the station performed the following OPDRV activities without an operable primary or secondary containment:draining of reactor recirculation loop B; replacement of 18 control rod drive mechanisms (unbolt and install);replacement of six instrument dry tubes;replacement of reactor recirculation pump B seal;replacement of reactor recirculation loop B flow control valve actuator;plugging of drain line appendages on reactor recirculation pump B; andlocal leak rate testing of the reactor water cleanup suction line containment isolation valves.The failure to perform OPDRV activities with operable primary and secondary containments is a violation of TS 3.6.1.10 and TS 3.6.4.1. Because the violation occurred during the discretion period described in EGM 11003, Revision 3, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation.In accordance with EGM 11003, Revision 3, each licensee that receives discretion must submit a license amendment request within 12 months of the NRC staffs publication in the Federal Register of the notice of availability for a generic change to the standard TS to provide more clarity to the term OPDRV. The inspectors observed thatPNPP is tracking the need to submit a license amendment request as commitment PYL1712101.This LER is closed. This inspection constituted one event follow-up sample as defined in IP 7115305. |
| 05000282/FIN-2017001-01 | Prairie Island | 2017Q1 | Failure to Evaluate Changes to NRC Approved Methodology | Severity Level IV/Green. The inspectors identified a Green finding and associated Severity Level IV Violation of Title 10 of the Code of Federal Regulations (10 CFR) 50.59(d)(1), for the licensees failure to perform a written evaluation which provided the bases for t he determination that a change in the NRC approved Westinghouse methodology referenced in the Updated Safety Analysis Report (USAR) for evaluating the acceptability of reactor pressure vessel internals baffle former bolting distributions did not require a license amendment. This finding was entered into the licensees Correction Action Program ( CAP ) as CAP documents 1539487, Documentation Missing in 50.59 Screening 4443, dated October 26, 2016; 1552331, BFB Screen Referenced Eval for SER Limitation 4 No n-Existent, dated March 6, 2017; and 1552314, BFB Screening Lacks Documentation for SER Limitation 3, dated March 6, 2017. The licensee performed an operability determination and determined the baffle bolts were operable. The inspectors reviewed the operability determination and no performance deficiencies were identified in this determination. The inspectors determined that the licensees failure to perform a written evaluation, providing the bases for the determination that a change in the NRC approved Westinghouse methodology for evaluating the acceptability of baffle former bolting distributions did not require a license amendment, was a performance deficiency. This finding was also evaluated using traditional enforcement because it had the potential for impacting the NRCs ability to perform its regulatory function. The performance deficiency was determined to be more -than -minor because it was associated with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, compliance with the NRC approved methodology of WCAP 15029 PA ensured the baffle former assembly maintained its structural integrity, avoiding a failure or excessive deflection of the baffle plates, and hence the primary concern of ensuring the emergency core cooling system could continue to perform its design function of cooling the reactor core. The inspectors determined the finding could be evaluated using the Significance 3 Determination Process (SDP) in accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At -Pow er, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, for the Mitigating Systems cornerstone. The finding screened as having very- low safety significance (Green) because the emergency core cooling system maintained its operability , specifically with respect to performing its safety function of ensuring adequate core cooling. As such, the finding corresponded to a Severity Level IV Violation in accordance with Example 6.1.d.2 of the NRC Enforcement Policy. The inspectors did not identify a cross cutting aspect because the performance deficiency was from 2013, and hence the issue did not represent current performance |
| 05000354/FIN-2017001-03 | Hope Creek | 2017Q1 | Operations with a Potential to Drain the Reactor Vessel (OPDRV) Without Secondary Containment | On October 23, 24, and 31, 2016, during a planned refueling outage with the reactor cavity flooded up in Mode 5, Hope Creek conducted multiple OPDRVs without an operable secondary containment. The conduct of an OPDRV without establishing secondary containment integrity is a condition prohibited by TS as defined by 10 CFR 50.73(a)(2)(i)(B). Secondary containment is required by TS 3/4.6.5.1 in Operational Condition (*), which is a condition when recently irradiated fuel is being handled during an OPDRV. The required action for this specification is to suspend handling recently irradiated fuel and OPDRV operations. In this case, the specific OPDRVs were control rod drive mechanism replacements (8:40 a.m. on October 23, 2016, through 10:50 p.m. on October 23, 2016), local power range monitor replacements (10:50 p.m. on October 23, 2016, through 8:07 a.m. on October 24, 2016), additional control rod drive mechanism and local power range monitor replacements (8:07 a.m. on October 24, 2016, through 8:23 a.m. on October 25, 2016), and the fill and vent for the A and B RRP seal (11:21 a.m. on October 31, 2016, through 12:02 p.m. on November 1, 2016). The OPDRVs were completed in accordance with PSEG procedure OP-HC-108-102, "Management of Operations with the Potential to Drain the Reactor Vessel (OPDRV)," Revision 5, dated October 6, 2016. These OPDRVs were completed and exited at 12:02 p.m. on November 1, 2016. The NRC issued EGM 11-003, Revision 3, Enforcement Guidance Memorandum on Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential For Draining the Reactor Vessel, on January 15, 2016, which provides, in part, for the exercise of enforcement discretion only if the licensee demonstrates that it has implemented specific interim actions during any OPDRV activity. The inspectors determined that PSEGs implementation of these specific interim actions during these OPDRV activities were adequate and met the intent of EGM 11-003, Revision 3. The inspectors assessments of PSEGs implementation of these criteria during each of the multiple OPDRV activities are described below: The inspectors observed that, as required by the EGM, the OPDRV activity was logged in the control room narrative logs and that the log entry appropriately recorded the safety-related pump (B RHR) that was the standby source of makeup designated for the evolution. The inspectors noted that the reactor vessel water level was maintained at least 22 feet and 2 inches over the top of the reactor pressure vessel (RPV) flange in compliance with the minimum water level allowed by Hope Creek TS limiting condition for operation (LCO) 3.9.8 applicability. The inspectors also noted that at least one safety-related pump was the standby source of makeup designated in the control room narrative logs for the evolution with the capability to inject water equal to, or greater than, the maximum potential leakage rate from the RPV for a minimum time period of 4 hours. PSEG reported that the worst case estimated time to drain the reactor cavity to the RPV flange was 36.6 hours, which met the EGM criteria of greater than 24 hours. The inspectors verified that the OPDRV was not conducted in Mode 4 and that PSEG did not move recently irradiated fuel during the OPDRV. The inspectors noted that PSEG had in place a contingency plan for isolating the potential leakage path. The inspectors verified that two independent means of measuring RPV water level (one alarming) were available for identifying the onset of loss of inventory events with sufficient time to close secondary containment before reactor water level reached the top of the RPV flange. Technical Specification 3.6.5.1 is applicable in Operational Conditions 1, 2, 3 and (*). This TS requires that secondary containment integrity shall be maintained. Operational Condition (*) is defined, in part, as being during OPDRV. TS 3.6.5.1, action b, states, in part, in operational condition (*) suspend operations with a potential for draining the reactor vessel. Contrary to the above, between 8:40 a.m. on October 23, 2016, and 12:02 p.m. on November 1, 2016, Hope Creek Generating Station did not maintain secondary containment integrity while conducting OPDRV activities. Because the violation was identified during the discretion period described in EGM 11-003 Revision 3, the NRC is exercising enforcement discretion in accordance with NRC Enforcement Policy Section 2.2.4, Exceptions to Using Only the Operating Reactor Assessment Program, and Section 3.5, Violations Involving Special Circumstances, and, therefore, will not issue enforcement action for this violation. In accordance with EGM 11-003 Revision 3, each licensee that receives discretion must submit a license amendment request within 4 months of the NRC staffs publication in the Federal Register of the notice of availability for a generic change to the STS to provide more clarity to the term OPDRV. The inspectors observed that PSEG is tracking the need to submit a license amendment request in its CAP as NOTF 20559547 (Order 70138857). No findings were identified. This LER is closed. |
| 05000298/FIN-2016004-01 | Cooper | 2016Q4 | Failure to Maintain Reactor Vessel Assembly Procedure to Ensure Adequate Moisture Separator Shielding | The inspectors reviewed a self-revealed, non-cited violation of Technical Specification 5.4.1.a for the licensee's failure to ensure sufficient radiological work controls were in place when the reactor pressure vessel moisture separator was installed during vessel reassembly. Specifically, the licensee failed to maintain sufficient detail in Station Procedure 7.4Reassembly, Reactor Vessel Reassembly, Revision 13, to ensure that the moisture separator had adequate water shielding during lifts, such that radiation fields were appropriately controlled. The licensee took immediate corrective action to ensure resubmergence of the radiologically significant sections of the moisture separator and restore the requisite water shielding, thereby restoring ambient refuel floor radiological conditions. The licensee entered this deficiency into the corrective action program as Condition Report CR-CNS-2016-07552. The licensee's failure to ensure sufficient radiological work controls were in place when the reactor pressure vessel moisture separator was lifted during vessel reassembly, in violation of Technical Specification 5.4.1.a, was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the program and process attribute of the Occupational Radiation Safety Cornerstone and adversely affected the cornerstone objective to ensure adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Specifically, the failure to have sufficient procedural guidance to maintain adequate water shielding on the moisture separator resulted in unanticipated elevated dose rates on the refuel floor and unplanned radiological exposures to workers in the immediate work area. Using Inspection Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, dated August 19, 2008, the inspectors determined that the violation had very low safety significance (Green) because: (1) it was not an as low as reasonably achievable (ALARA) finding; (2) there was no overexposure; (3) there was no substantial potential for an overexposure; and (4) the ability to assess dose was not compromised. The inspectors determined that the finding had a cross-cutting aspect in the area of human performance associated with avoiding complacency. Specifically, the licensee failed to recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes and failed to implement appropriate error reduction tools (H.12). |
| 05000282/FIN-2016004-01 | Prairie Island | 2016Q4 | Baffle Former Bolting Acceptance Criteria | From October 17November 28, 2016, the inspectors conducted a review of the implementation of the licensees inservice inspection (ISI) program for monitoring degradation of the reactor coolant system (RCS), risk-significant piping and components and containment systems. This inspection constituted one ISI sample (see Sections 1R08.1, 1R08.3 and 1R08.5 below), as defined in IP 71111.0805. .1 Piping Systems Inservice Inspection a. Inspection Scope The inspectors either observed or reviewed records of the following Non-Destructive Examinations (NDEs) mandated by the American Society of Mechanical Engineers (ASME), Section XI Code, to evaluate compliance with the ASME Code Section XI and Section V requirements, and if any indications and defects were detected, to determine if these were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement. Ultrasonic examination of tubesheet to shell for steam generator (SG) 11; Magnetic particle examination of an integral attachment support rod for SG 11; Visual examination of reactor vessel nuts and washers (1 through 16); and Unit 1 metallic containment liner visual examination in 2012. During non-destructive surface and volumetric examinations performed since the previous refueling outage, the licensee had not identified any recordable indications. Therefore, no NRC review was completed for this inspection procedure attribute. The inspectors either observed or reviewed the following pressure boundary welds completed for risk-significant systems since the beginning of the last refueling outage to determine if the licensee applied the preservice NDEs, and acceptance criteria required by the Construction Code and ASME Code, Section XI. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedures were qualified in accordance with the requirements of Construction Code and ASME Code Section IX. Unit 1 reactor coolant pump (RCP) seal replacements. b. Findings No findings were identified. .2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities a. Inspection Scope The licensee did not perform any welded repairs to vessel head penetrations since the beginning of the preceding outage for Unit 1. Therefore, no NRC review was completed for this inspection procedure attribute. For the Unit 1 vessel head, no examination was required pursuant to Title 10 of the Code of Federal Regulations (10 CFR), Part 50.55a(g)(6)(ii)(D) for the current refueling outage. Therefore, no NRC review was completed for this inspection attribute. b. Findings No findings were identified. .3 Boric Acid Corrosion Control a. Inspection Scope The inspectors performed an independent walkdown of the RCS and related lines in the containment, which had received a recent licensee boric acid walkdown, and verified whether the licensees boric acid corrosion control visual examinations emphasized locations where boric acid leaks can cause degradation of safety significant components. The inspectors reviewed the following licensee evaluations of RCS components with boric acid deposits to determine if degraded components were documented in the CAP. The inspectors also evaluated corrective actions for any degraded RCS components to determine if they met the ASME Section XI Code. 11 RCP seal bowl. The inspectors reviewed the following corrective actions related to evidence of boric acid leakage to determine if the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B, Criterion XVI. CAP 1465567; 12 RCP Seal Leakage. b. Findings No findings were identified. .4 Steam Generator Tube Inspection Activities a. Inspection Scope The licensee did not perform in-situ pressure testing of SG tubes. Therefore, no NRC review was completed for this inspection attribute. For the Unit 1 SGs, no examination was required pursuant to the TSs during the current refueling outage. Therefore, no NRC review was completed for this inspection procedure attribute. b. Findings No findings were identified. .5 Identification and Resolution of Problems a. Inspection Scope The inspectors performed a review of ISI/SG-related problems entered into the licensees CAP, and conducted interviews with licensee staff to determine if: the licensee had established an appropriate threshold for identifying ISI/SG-related problems; the licensee had performed a root cause evaluation (if applicable) and taken appropriate corrective actions; and the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity. The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI requirements. Documents reviewed are listed in the Attachment to this report. b. Findings (1) Baffle Former Bolting Analysis Acceptance Criteria Introduction: The inspectors identified an Unresolved Item (URI) concerning the analysis that demonstrated the design adequacy of the baffle former bolting under design and licensing basis loading conditions. Description: The inspectors reviewed WCAP 17586P, Determination of Acceptable Baffle-Barrel Bolting for Prairie Island Units 1 and 2, Revision 0; WCAP15030NPA, Westinghouse Methodology for Evaluating the Acceptability of Baffle-Former-Barrel Bolting Distributions under Faulted Load Conditions, dated March 2, 1999; and Safety Evaluation by the Office of Nuclear Reactor Regulation of WCAP15029, Westinghouse Methodology for Evaluating the Acceptability of Baffle-Former-Barrel Bolting Distributions Under Faulted Load Conditions, dated November 10, 1998. The inspectors were concerned that the licensee had evaluated the baffle former bolting using acceptance criteria different than what was reviewed and approved by the Office of Nuclear Reactor Regulation. In WCAP15030NPA, Section 4.3.2 stated that the stress allowable for primary membrane and bending of irradiated bolt material is taken to 0.9 times Sy (yield stress of baffle bolt material) for the faulted load condition. The stress allowable used in WCAP 17586P was based on ASME, Section III, Appendix F, specifically: (minimum of (0.9 times Su) ultimate stress of baffle bolt material), maximum of (0.67 times Su, Sy + 1/3 (Su - Sy)). The inspectors also reviewed 10 CFR 50.59 Screening No. 4443, Determination of Acceptable Baffle-Barrel Bolting, dated January 24, 2013, to determine whether the licensee performed a 50.59 evaluation for the use of ASME, Section III, Appendix F acceptance criteria. However, the inspectors identified that the change for the use of ASME, Section III, Appendix F acceptance criteria in lieu of the acceptance criteria contained in Section 4.3.2 of WCAP15030NPA was not explicitly reviewed in 50.59 Screening No. 4443. In response to the inspectors concern, the licensee initiated CAP 1539487, Documentation Missing in 50.59 Screening 4443, dated October 26, 2016. This issue is an URI pending evaluation of these concerns by the licensee, subsequent inspector review, and discussion with the licensee and Office of Nuclear Reactor Regulation (URI 05000282/201600401; 05000306/201600401; Baffle Former Bolting Analysis Acceptance Criteria). |
| 05000219/FIN-2016004-01 | Oyster Creek | 2016Q4 | E EMRV Failureto Stroke Due to Incorrect Reassembly | The NRC identified a preliminary White finding and associated apparent violation of Technical Specification 6.8.1, Procedures and Programs, and Technical Specification 3.4.B, Automatic Depressurization System, because Exelon failed to implement a procedure related to the maintenance of safety related equipment. Specifically, Exelon personnel did not follow electromatic relief valve (EMRV) reassembly instructions that required personnel to reinstall previously removed lock washers from the E EMRV cut-out switch lever. The incorrect reassembly caused excessive friction between the solenoid frame and the cut-out switch lever, which led to the E EMRVs failure to perform its safety function. This resulted in one inoperable EMRV for greater than the Technical Specification allowed outage time. The issue was entered into the corrective action program as issue report 2722109, and Exelons immediate corrective actions include installing new cut-out switch lever plates with increased clearances, replacing star lock washers with split ring lock washers for additional clearance, and verifying the five EMRV solenoid actuators being installed into the drywell following the most recent refueling outage were correctly assembled. The finding is more than minor because it adversely affects the human performance quality attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the missing lock washers due to the incorrect EMRV lever plate reassembly caused excessive friction between the solenoid frame and the cut-out switch lever, causing the cut-out switch lever to become bound in the energized position. This led to the E EMRVs failure to perform its safety function. The inspectors screened this issue for safety significance in accordance with Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, and determined a detailed risk evaluation was required because the E EMRV had potentially failed or was unreliable for greater than the Technical Specification allowed outage time. A detailed risk evaluation concluded that the increase in core damage frequency (CDF) related to the failure of the E EMRV is 5.4E-6/year; therefore, this finding was preliminary determined to have a low to moderate safety significance (White). Due to the nature of the failure, no recovery credit was assigned. The dominant core damage sequences involve loss of main feedwater events with operator errors resulting in failure to make-up to the 4 isolation condensers or otherwise maintain reactor vessel level and the loss of reactor pressure vessel depressurization capability (due to common cause failure of the remaining four EMRVs). The finding has a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because Exelon personnel did not follow station processes. Specifically, Exelon did not follow written instructions when reassembling the E EMRV. The missing lock washers resulted in excessive friction between the solenoid frame and cut-out switch lever, causing the cut-out switch lever to become bound in the energized position, which led to the E EMRVs failure to perform its safety function. (H.8) |
| 05000354/FIN-2016003-03 | Hope Creek | 2016Q3 | Inadequate Procedure Adherence Resulted in a Loss of Shutdown Cooling | A self-revealing non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, occurred when PSEG did not follow procedure during the transition from Cold Shutdown to refueling operations while filling up the reactor pressure vessel (RPV) to support RPV head cooling in preparation for reactor disassembly. This resulted in an automatic isolation of the operating residual heat removal (RHR) pump while it was providing decay heat removal in shutdown cooling. PSEG has entered this issue into their corrective action program (CAP) in notification (NOTF) 20684861, and corrective actions included performing a root cause evaluation for the event, revising the operating procedures to provide clarity, and conducting training with all operators on the lessons learned from the event. This issue was evaluated in accordance with IMC 0612, Appendix B, and determined to be more than minor since it was associated with the human performance attribute of the Initiating Events cornerstone and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations. The finding was evaluated using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process (SDP), and per Attachment 1, Exhibit 2, required a Phase 2 risk evaluation which determined the safety significance of this performance deficiency to be in the mid E-8 range, or of very low safety significance (Green). The inspectors determined this finding has a cross-cutting aspect in the area of Human Performance, Conservative Bias, in that the operator did not use decision-making practices that emphasized prudent choices over those that are simply allowable, and the operators proposed action was not determined to be safe prior to proceeding with the action. Specifically, the operator did not ensure his actions were safe prior to aligning and operating the feedwater system to fill the RPV during plant cooldown using an uncommon method. |
| 05000333/FIN-2016007-02 | FitzPatrick | 2016Q2 | Failure to adequately evaluate a procedure change impacting a PRA-credited time critical operator action | The team identified a Green finding involving Entergys inability to complete a time critical operator action within the assumed probabilistic risk assessment (PRA) credited accident mitigation time limit to prevent undesirable consequences (i.e., core damage) under a postulated scenario (i.e., using the residual heat removal service water (RHRSW) system as an alternate injection source into the reactor pressure vessel (RPV) via the residual heat removal (RHR) system during a loss of coolant accident (LOCA)). Specifically, in response to a known degraded condition impacting an RHRSW valve, Entergy did not adequately evaluate an associated temporary procedure change to EP-8, Alternate Injection Systems, to ensure operator actions could be accomplished to initiate RHRSW injection to the RPV within the PRA-credited time. Entergy entered the issue into their CAP as CR 2016-1396 and CR 2016-1429 and completed corrective actions to pre-stage a ladder for operator use and provide additional guidance to plant operators. The finding was more than minor because it was associated with the design control (plant modifications) attribute of the Mitigating Systems cornerstone and adversely affected the cornerstones objective of ensuring reliability, availability, and capability of systems and operators that respond to initiating events to prevent undesirable consequences (i.e., core damage). The team evaluated the finding in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, Exhibit 2 Mitigating Systems Screening Questions, and concluded it required a detailed risk evaluation (DRE). A Region I Senior Reactor Analyst performed the DRE and concluded that the failure of an operator action to align RHRSW for RPV alternate injection within the assumed PRA accident mitigation time limit results in an estimated increase in core damage frequency in the mid E-8/year range, or very low safety significance (Green). The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because Entergy did not thoroughly evaluate issues to ensure that resolutions address causes and extent-of-conditions commensurate with their safety significance. Specifically, Entergy did not thoroughly evaluate the effect of an alternate injection procedure change on PRA-credited time critical operator actions. (PI.2) |
| 05000341/FIN-2016001-01 | Fermi | 2016Q1 | Failure of the Plant-Referenced Simulator to Demonstrate Expected Plant Response for Safety Relief Valves | A finding of very low safety significance with an associated NCV of 10 CFR 55.46(c), Plant-Referenced Simulators, was self-revealed. The licensee failed to ensure the plant-referenced simulator demonstrated expected plant response to normal, transient, and accident conditions to which the simulator was designed to respond. Specifically, the licensee failed to maintain the simulator consistent with actual plant response when using the safety relief valves for reactor pressure control after a reactor scram. The licensee entered this issue into the corrective action program. To restore compliance, the licensee modified the simulator model to more accurately emulate actual reactor pressure vessel (RPV) water level response during manual control of reactor pressure using safety relief valves. The performance deficiency was of more than minor safety significance because it adversely affected the human performance attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the simulator provided unrealistic or negative training to licensed operators due to inaccurate modeling of the RPV level response during manual control of reactor pressure using safety relief valves as compared to the actual plant response. Although the simulator provided unrealistic or negative training to licensed operators, the inspectors concluded the unrealistic simulator training did not negatively impact licensed operator performance during the event since operators had successfully demonstrated manual control of RPV level and pressure for greater than 12 hours. Therefore, the finding was determined to be of very low safety significance. The inspectors concluded that because the discrepancy between the simulator and the plant existed since simulator use began (i.e., greater than three years ago), this issue would not be reflective of current licensee performance and no cross-cutting aspect was identified. |
| 05000440/FIN-2016001-01 | Perry | 2016Q1 | Failure to Properly Implement System Operating Instructions to Maintain Control of Reactor Pressure Vessel Level | A finding of very low safety significance and an associated non-cited violation (NCV) of Technical Specification (TS) 5.4.1., Procedures, was self-revealed on January 24, 2016, when an unplanned automatic reactor protection system (RPS) actuation occurred as a result of the licensees failure to correctly implement the steps outlined in procedure SOIC34, Feedwater Control System, Section 4.2.12.c to balance inservice flow controller outputs. Specifically, while in the process of reducing power to allow for a drywell entry to determine the location of an unidentified leak into the drywell floor drain sump, the operators failed to control reactor pressure vessel water level during shifting of feedwater pumps from a turbine-driven reactor feed pump to the motor-driven reactor feed pump, resulting in a RPS actuation initiated on reactor vessel water Level 8, shutting down the reactor. Following the reactor scram, the licensee took immediate actions to restore and maintain RPV water level in accordance with procedure ONIC711, Reactor Scram, Revision 20. The issue was entered into the licensees corrective action program as CR 201601063. The licensees failure to properly implement the steps in the procedure was a performance deficiency that was determined to be more than minor and thus a finding, because it was associated with the Initiating Events cornerstone attribute of human performance and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The finding was determined to be of very low safety significance because it did not result in the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding has a cross-cutting aspect in the area of human performance, resources, because the licensee failed to ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety. Specifically, the licensee failed to provide adequate, procedural guidance on when to conduct the feedwater pump shift (IMC 0310, H.1). |
| 05000333/FIN-2016001-01 | FitzPatrick | 2016Q1 | Unintended HPCI Pump Suction Transfer during Pressure Control Mode Operation | The inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for failure to maintain a condition specified in an emergency operating procedure. Specifically, while operating the high pressure coolant injection (HPCI) system in the pressure control mode, operators failed to override automatic transfer of the HPCI pump suction from the condensate storage tank (CST) to the suppression pool prior to the transfer actually occurring. As a result, operators had to revert to using the safety/relief valves (S/RVs) for pressure control, which introduced additional, unnecessary plant challenges. As immediate corrective action, operators secured HPCI, overrode the automatic HPCI pump suction transfer, realigned the pump suction to the CST, and restarted HPCI in the pressure control mode. The issue was entered into the corrective action program (CAP) as condition report (CR)-JAF-2016-00765. The finding was more than minor because it was associated with the human performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the operators failure to timely override automatic transfer of the HPCI suction to the suppression pool resulted in an additional, avoidable post-scram pressure and level transient being placed on the reactor pressure vessel (RPV) and unnecessarily reduced the thermal capacity of the suppression pool. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At- Power, the inspectors determined that this finding was of very low safety significance (Green) because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of a safety function of a single train for greater than its technical specification (TS) allowed outage time, and did not screen as potentially risksignificant due to a seismic, flooding, or severe weather initiating event. The finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because operators did not follow guidance of EOP-2 for the HPCI pump suction to be aligned to the CST by bypassing the HPCI pump suction swap to the suppression pool in a timely manner, such that the swap actually occurred (H.8). |
| 05000458/FIN-2015004-05 | River Bend | 2015Q4 | Failure to Follow Procedure Results in Inadvertent Draindown of Reactor Pressure Vessel | The inspectors reviewed a self-revealing, non-cited violation of Technical Specification 5.4, Procedures, for the licensees failure to correctly implement procedure STP-200-0605, Remote Shutdown System Control Circuit Operability Test, Revision 307. The procedure was incorrectly performed leading to an unexpected configuration in which the reactor pressure vessel was aligned to the suppression pool, and approximately 360 gallons of reactor coolant were inadvertently transferred to the suppression pool. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2015-02354. The licensee restored compliance by restoring the system to a configuration that was consistent with plant operating procedures. Corrective actions included increased management oversight of remote shutdown system operation. The performance deficiency was more than minor, and therefore a finding, because it was associated with the Initiating Events Cornerstone attribute of configuration control, and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, a loss of reactor pressure vessel inventory occurred due to the establishment of an unintended system configuration caused by the inadvertent repositioning of the reactor pressure vessel suction valve. The inspectors initially screened the finding in accordance with NRC Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process. Using Exhibit 2 of NRC Inspection Manual Chapter 0609, Appendix G, Attachment 1, Phase 1 Initial Screening and Characterization of Findings, the inspectors determined that the finding required a Phase 2 evaluation because the loss of inventory resulted in leakage to the suppression pool that if undetected or unmitigated in 24 hours or less would cause shutdown cooling to isolate. A Region IV senior reactor analyst performed a Phase 2 evaluation of this issue and determined the issue was of very low safety significance (Green) and represented a change to the core damage frequency of 3.8E-8/year. The event sequence was an actual loss of inventory which occurred after core refueling in the shutdown. Risk was mitigated by prompt operator recovery action to stop the loss of inventory along with the operating plant configuration, which had two residual heat removal pumps aligned for automatic injection, one control rod drive pump in operation at the time of the event, and all manual injection paths fully available to mitigate the event. This finding has a cross-cutting aspect in the area of human performance associated with avoid complacency because the licensee failed to ensure that individuals recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. |
| 05000254/FIN-2015004-01 | Quad Cities | 2015Q4 | EAL Threshold Values Were Not Revised | An Unresolved Item (URI) was identified because additional information is required to determine whether a performance deficiency that is more than minor exists, and if a violation of 10 CFR 50.54(q)(2), which requires a licensee to develop and maintain an emergency plan that meets the requirements of 10 CFR 50.47(b), and 10 CFR Part 50, Appendix E, had occurred. The licensee identified an issue of concern when the Quad Cities General Abnormal procedures (QGAs) were revised with a new value for Minimum Steam Cooling Reactor Pressure Vessel Water Level (MSCRWL) but the associated EALs that use the MSCRWL value as an EAL threshold were not revised. On March 12, 2015, the QGAs were revised with a new value for MSCRWL. However, the site EALs that should use the revised QGA value as an EAL threshold value were not revised. The licensee scheduled the revisions of the QGAs to support implementation of changes that were associated with the diverse and flexible coping strategies (FLEX) implementation and the sites transition to new Optima2 fuel. Both of the changes were scheduled to be implemented in March 2015 during the Quad Cities Unit 1 Refueling Outage as part of a revision package. Because of the new fuel, the MSCRWL value changed from -166 inches to -190 inches. On April 28, 2015, the licensee identified the EALs were not changed to correspond with the new MSCRWL values incorporated in the QGAs. The specific EALs that are affected are MG2 and FG1, which are used to determine if a General Emergency should be declared based on the MSCRWL value. Since the value remained at -166 inches, the licensee concluded that the issue could have potentially caused, under certain conditions, the site to declare a General Emergency earlier than needed and issue an unnecessary Protective Action Recommendation (PAR) to the public. Following identification of the issue, the licensee implemented the appropriate changes to EALs MG2 and FG1 on April 30, 2015. Since there was a discrepancy between the QGAs and the EAL threshold values that could have affected the timely and accurate classification of a General Emergency, a potential performance deficiency exists. However, in order to determine if the performance deficiency is more than minor significance, additional information is needed. The URI was identified pending additional information and inspection follow-up. Specifically, additional information is required to: understand if the discrepancy in the MSCRWL values documented in the QGAs and the EALs would have led to an overclassification of a General Emergency and issuance of an unnecessary PAR; understand if there are events that could be postulated where the -166 inches could be exceeded without reaching the -190 inches; and understand the timeline from when the fuel was transitioned to Optima2 until the discovery of this issue. This information will assist the inspectors to determine if the performance deficiency is more than minor and if a violation of 10 CFR 50.54(q)(2) occurred. |
| 05000397/FIN-2015003-06 | Columbia | 2015Q3 | Implementation of Enforcement Guidance Memorandum (EGM) 11-003, Revision 2 | During Refueling Outage 22 in May June 2015, Columbia Generating Station implemented the guidance of Enforcement Guidance Memorandum (EGM) 11-003, Revision 2, Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements during Operations with a Potential for Draining the Reactor Vessel, dated December 13, 2013. Consistent with EGM 11-003, Revision 2, secondary containment operability was not maintained during operations with a potential for draining the reactor vessel activities, and required action C.2 of Technical Specification 3.6.4.1 was not completed. The inspectors reviewed this licensee event report for potential performance deficiencies and violations of regulatory requirements. The inspectors reviewed the stations implementation of the EGM 11-003, Revision 2, during operations with a potential for draining the reactor vessel. Specific observations included: 1. The inspectors observed that the operations logged all potential for draining the reactor vessel activities in the control room narrative logs, and that the log entry appropriately recorded the standby source of makeup designated for the evolutions. 2. The inspectors noted that the licensee maintained reactor vessel water level at least greater than 21 feet above the top of the reactor pressure vessel flange as required by Technical Specification 3.9.6. The inspectors also verified that at least one safety-related pump was the standby source of makeup designed in the control room narrative logs for the evolutions. The inspectors confirmed that the worst case estimated time to drain the reactor cavity to the reactor pressure vessel flange was greater than 24 hours. 3. The inspectors verified that the operations with a potential for draining the reactor vessels were not conducted in Mode 4 and that the licensee did not move irradiated fuel during the operations with a potential for draining the reactor vessels. The inspectors verified that two independent means of measuring reactor pressure vessel water level were available for identifying the onset of loss of inventory events. Technical Specification 3.6.4.1, Secondary Containment requires, in part, that secondary containment shall be operable during operations with a potential for draining the reactor vessel. Technical Specification 3.6.4.1, Condition C, requires the licensee to initiate actions to suspend operations with a potential for draining the reactor vessel immediately when secondary containment is inoperable. Contrary to the above, from May 13 - June 13, 2015, Columbia Generating Station performed a total of five operations with a potential for draining the reactor vessel activities while in Mode 5 without an operable secondary containment. These conditions were reported as conditions prohibited by Technical Specifications. The licensee entered this issue into its corrective action program as Action Request 329328. Since this violation occurred during the discretion period described in EGM 11-003, Revision 2, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy, and, therefore, will not issue enforcement action for this violation. In accordance with EGM 11-003, Revision 2, each licensee that receives discretion must submit a license amendment request (LAR) to resolve the issue for its plant which the NRC staff LAR acceptance review finds acceptable in accordance with LIC-109, Acceptance Review Procedures. The generic solution will be a generic change to the Standard Technical Specifications, and the NRC will publish a notice of availability (NOA) for the TS solution in the Federal Register. Each licensee that receives discretion must submit its amendment request within 12 months of the NRC staffs issuance of the NOA. Licensees may submit LARs to adopt the NRC-approved approach or to propose an alternative approach for their plants. This licensee event report is closed. |
| 05000458/FIN-2015009-03 | River Bend | 2015Q2 | Failure to Provide Adequate Procedures for Post-scram Recovery | The team reviewed a self-revealing, non-cited violation of Technical Specification 5.4.1.a for the licensees failure to establish, implement and maintain a procedure required by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Specifically, Procedure OSP-0053, Emergency and Transient Response Support Procedure, Revision 22, which is required by Regulatory Guide 1.33, inappropriately directed operations personnel to establish feedwater flow to the reactor pressure vessel using the startup feedwater regulating valve as part of the post-scram actions. The startup feedwater regulating valve operator characteristics are non-linear and not designed to operate in the dynamic conditions immediately following a reactor scram. To correct the inadequate procedure, the licensee implemented a change to direct operations personnel to utilize one of the main feedwater regulating valves until the plant is stabilized. This issue was entered in the licensees corrective action program as Condition Report CR-RBS-2015-00657. This performance deficiency is more than minor, and therefore a finding, because it is associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the procedure directed operations personnel to isolate the main feedwater regulating valves and control reactor pressure vessel level using the startup feedwater regulating valve, whose operator was not designed to function in the dynamic conditions associated with a post-scram event from high power, and this challenged the capability of the system. The team performed an initial screening of the finding in accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the team determined that the finding is of very low safety significance (Green) because it: (1) was not a deficiency affecting the design or qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality; (2) did not represent a loss of system and/or function; (3) did not represent an actual loss of function of at least a single train for longer than its technical specification allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time; and (4) did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program. This finding has an evaluation cross-cutting aspect within the problem identification and resolution area because the licensee failed to thoroughly evaluate this issue to ensure that the resolution addressed the cause commensurate with its safety significance. Specifically, the licensee failed to properly evaluate the design characteristics of the startup feedwater regulating valve operator before implementing the procedure to use the valve for post-scram recovery actions (P.2). |
| 05000458/FIN-2015009-04 | River Bend | 2015Q2 | Failure to Identify High Reactor Water Level as a Condition Adverse to Quality | The team identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to assure a condition adverse to quality was promptly identified. Specifically, the licensee failed to identify, that reaching the reactor pressure vessel water Level 8 (high) setpoint, on December 25, 2014, was an adverse condition, and as a result, failed to enter it into the corrective action program. To restore compliance, the licensee entered this issue into their corrective action program as Condition Report CR-RBS-2015-00620 and commenced a causal analysis for Level 8 (high) trips. This performance deficiency is more than minor, and therefore a finding, because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure to identify Level 8 (high) conditions and unplanned automatic actuations as conditions adverse to quality, would continue to result in the undesired isolation of mitigating equipment including reactor feedwater pumps, the high pressure core spray pump, and the reactor core isolation cooling pump. The team performed an initial screening of the finding in accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the team determined that the finding is of very low safety significance (Green) because it: (1) was not a deficiency affecting the design or qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality; (2) did not represent a loss of system and/or function; (3) did not represent an actual loss of function of at least a single train for longer than its technical specification allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time; and (4) did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program. This finding has an avoid complacency cross-cutting aspect within the human performance area because the licensee failed to recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Specifically, the licensee tolerated leakage past the feedwater regulating valves, did not plan for further degradation, and the condition ultimately resulted in the Level 8 (high) trip of the running reactor feedwater pump on December 25, 2014 (H.12). |
| 05000263/FIN-2015002-04 | Monticello | 2015Q2 | Failure to Fill the Reactor Cavity in Accordance with Refueling Preparation Procedure | The inspectors identified a finding of very low safety significance and an associated NCV of TS 5.4.1, Procedures, on April 15, 2015, when the licensee failed to implement procedure 9001, Reactor Well & Dryer-Separator Storage Pool Filling Procedure, for refueling preparation activities. Specifically, when faced with indications that the condensate storage tanks (CSTs) did not contain enough water inventory to complete outage critical path reactor pressure vessel (RPV) flooding activities, the licensee failed to implement 9001 procedure steps for using prescribed equipment and methods to fill the reactor cavity. With the proceduralized methods unavailable, operators used the site decision-making process to utilize demineralizer water hoses to fill the cavity rather than processing required 9001 procedure changes. This issue was entered into the licensees CAP (CAP 1474891). Immediate corrective actions included action to initiate the procedure change process for 9001 and department communication to Operations regarding the incident, emphasizing that the decision making process is not a substitute for the procedure change process. The inspectors determined that the failure to fill the reactor cavity in accordance with the 9001 reactor well filling procedure was a performance deficiency requiring evaluation. The inspectors evaluated IMC 0612, Appendix E, and did not find any similar examples of minor issues. The inspectors determined that the finding was more than minor in accordance with IMC 0612, Appendix B, because if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Specifically, the operations crews use of the decision-making process to support outage critical path by bypassing proceduralized steps and performing activities using methods contrary to the procedure could lead to a more significant safety concern. In addition, if performed incorrectly (i.e. without flushing the hoses prior to use), the use of demineralizer hoses could introduce foreign material into the core and challenge the integrity of the fuel cladding barrier. The inspectors evaluated the finding using IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, which required an analysis using IMC 0609 Appendix G, the Shutdown Operations SDP since the reactor was in Mode 5 (refueling). The finding was assessed in accordance with IMC 0609 Appendix G, Attachment 1, Exhibit 4 for Barrier Integrity and determined to have very low safety significance. The inspectors concluded that this finding was cross-cutting in the Human Performance, Conservative Bias aspect because of the failure of the individuals to use decision-making practices that emphasize prudent choices over those that are simply allowable, and the failure to ensure that proposed actions are determined to be safe in order to proceed, rather than unsafe in order to stop (H.14). |
| 05000219/FIN-2015001-01 | Oyster Creek | 2015Q1 | Post Maintenance Test Results Were Not Evaluated to Assure that Technical Specifications Requirements Were Satisfied | The inspectors identified an NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, when Exelon did not document and adequately evaluate test results to assure that test requirements had been satisfied. Specifically, Exelon did not perform the proper post maintenance test procedure to assure that the requirements of Technical Specification 4.5.G.3 were satisfied following installation of a temporary modification to secondary containment. Exelon entered this issue into the corrective action program for resolution as issue report (IR) 2440643. Corrective actions include revising the process to perform the correct post maintenance test to ensure Technical Specification 4.5.G.3 is met. This finding is more than minor because it is associated with the configuration control (Standby Gas Trains) attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the finding using IMC 0609.04, Initial Characterization of Findings, issued June 19, 2012, and IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process: Phase 1 Initial Screening and Characterization of Findings, issued May 9, 2014. Because the finding degraded the ability to close or isolate secondary containment, the inspectors were required to further assess the finding using IMC 0609, Appendix H, Containment Integrity Significance Determination Process, issued May 6, 2004. The inspectors determined that this finding is of very low safety significance (Green) because the decay heat values were low, given that the unit had been shut down for approximately three days, and reactor water level was greater than that required for movement of irradiated fuel assemblies within the reactor pressure vessel. This finding has a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because Exelon personnel did not perform the post maintenance test specified by the work order. |
| 05000387/FIN-2015001-06 | Susquehanna | 2015Q1 | Licensee-Identified Violation | 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires activities affecting quality be prescribed by documented procedures which include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. On February 6, 2014, PPL identified that the startup and shutdown procedures for both Units 1 and 2 were inadequate such that they allowed operation of the RPV at a vacuum. This resulted in twenty-seven separate violations of TS 3.4.10, Reactor Coolant System Pressure and Temperature Limits, which requires RPV pressure to be maintained within limits at all times. The limits specified by TS 3.4.10 do not permit operating the RPV at a vacuum. Contrary to these requirements, on multiple occasions during startup and shutdowns over the past 3 years, PPL operated the RPV at a vacuum. PPL entered this issue into the corrective action program as CR-2014-06949. The inspectors determined that the finding was more than minor because it was associated with the procedure quality attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The inspectors determined through a review of IMC 0609.04, Initial Characterization of Findings, and Exhibit 3 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, that the finding required a detailed risk evaluation since it was associated with the reactor coolant system boundary (e.g., pressurized thermal shock). Inspectors determined the finding to be of very low safety significance (Green) based on a qualitative assessment that there was no appreciable effect on the reactor pressure vessel as a barrier. Specifically, this conclusion was based on review of PPLs evaluation of acceptability of the RCS for continued operation, which determined that the stresses on a postulated crack, when the RPV is under vacuum conditions, would be less than the stresses when the RPV is under positive pressure conditions. |
| 05000331/FIN-2015008-01 | Duane Arnold | 2015Q1 | Failure to Identify and Evaluate the Effects of Vessel OverfillScenario | The inspectors identified a finding of very-low safety significance (Green), and an associated NCV of Title 10, Code of Federal Regulations (CFR) 50.48(c), and National Fire Protection Association Standard 805, Section 2.4.3.2 for the licensees failure to address in the Fire Probabilistic Risk Assessment (PRA) the risk contribution with all potentially risk-significant fire scenarios. Specifically, the licensee did not address potential damage to safety relief valves (SRVs), or the SRV tailpipes as a result from fire induced overfill of the reactor pressure vessel. The licensee entered this issue into their Corrective Action Program to review the multiple spurious operations Expert Panel report, and properly disposition the scenario. The inspectors determined that the performance deficiency was more than minor because the finding was associated with the Mitigating Systems cornerstone attribute of Protection against External Factors (i.e., fire), and it affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the missed failure mechanism for the SRVs had the potential to impact the ability to achieve safe and stable conditions. In accordance IMC 0609, Appendix F, Fire Protection SDP, Attachment 1, Step 1.6.1, Screen by Licensee PRA-Based Safety Evaluation, the inspectors were able to use the Licensees PRA to evaluate the safety significance of the finding. The increase in core damage frequency (CDF) as a result of the identified scenario was found to be approximately 2.6E-7 per year; therefore, the inspectors concluded that this finding was of very-low safety significance (Green). This finding did not have a cross-cutting aspect because it was not representative of current licensee performance. |
| 05000255/FIN-2015009-01 | Palisades | 2015Q1 | Failure to Determine the Cause of Head Penetration Nozzle J-Groove Weld Cracking | The inspector identified a finding of very-low safety significance with an associated NCV of Title 10, Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to establish measures to assure that the cause of the ultrasonic examination leakage path indications and crack indications identified in the J-groove welds of the reactor pressure vessel head penetration nozzles 29 and 30 (a significant condition adverse to quality) was determined. Specifically, the licensee did not complete adequate causal investigations to assure the cause of this significant condition adverse to quality was determined. The licensee entered this issue into the Corrective Action Program (CAP), and initiated an action to conduct a root cause investigation for this issue. The issue was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because it adversely affected the Initiating Events cornerstone attribute of equipment performance and procedure quality. The inspector also answered Yes to the more than minor screening question, If left uncorrected, would the performance deficiency have the potential to lead to a more significant safety concern? Specifically, the inspector determined that this issue was more than minor because, if left uncorrected, the licensee would have reduced the frequency of reactor vessel head nozzle penetration examinations which could result in the failure to detect primary water stress corrosion cracking (PWSCC). Undetected PWSCC could increase the risk for through-wall leakage and design basis events such as a loss-of-coolant accident (LOCA). The inspector determined that the finding was of very-low safety significance based on answering No to the IMC 0609, Appendix A, Exhibit 1-Initiating Events Screening Questions for LOCA Initiators. Although this performance deficiency occurred more than 10 years ago, it was representative of current licensee performance because in the November 19, 2014, Licensee Event Report Cancelation Letter, the licensee again failed to assure that the cause of the reactor pressure vessel nozzle crack indications in the J-groove welds was determined. Therefore, the finding had a cross-cutting aspect in the area of Problem Identification and Resolution because the licensee failed to assure the cause was determined for the reactor pressure vessel nozzle crack indications in the J-groove welds, and this decision was not consistent with an organization that thoroughly evaluates issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. |
| 05000255/FIN-2015009-02 | Palisades | 2015Q1 | Unqualified Non-Destructive Examinations of J-Groove Welds 29 and 30 | The inspector identified a finding of very-low safety significance with an associated NCV of 10 CFR Part 50, Appendix B, Criterion IX Control of Special Processes, for the licensees failure to use qualified personnel and procedures for the dye penetrant (PT) examinations of the J-groove welds at nozzles 29 and 30 used to characterize crack indications. Consequently, no quality records existed to validate or confirm the size or extent of the cracking identified in these welds. The licensee documented the use of the unqualified PT examination for characterizing the reactor pressure vessel nozzle J-groove weld cracks in the CAP, and was developing corrective actions at the conclusion of the inspection. The issue was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because it adversely affected the Initiating Events cornerstone attribute of equipment performance and procedure quality. Further, if left uncorrected, it would become a more significant issue. Specifically, the licensee had based the risk evaluation of the nozzle cracking on the results of the unqualified PT examination, and if this result was not correct, the risk significance of past plant operation with these cracks may have been greater than assumed. Additionally, the licensee had considered the results from this PT examination, as part of the evaluations identified in their November 19, 2014, letter that concluded the flaws identified were caused by embedded weld defects, and not PWSCC. Based upon this revised cause determination, the licensee had elected to reduce the scheduled vessel head examinations, and this reduced inspection schedule may not be adequate to identify PWSCC prior to experiencing a through-wall leak. The inspectors determined that the finding was of very low safety significance based on answering No to the IMC 0609, Appendix A, Exhibit 1-Initiating Events Screening Questions for LOCA Initiators. The finding did not have a cross-cutting aspect because it was not indicative of current licensee performance due to the age of the performance deficiency. |
| 05000259/FIN-2015001-08 | Browns Ferry | 2015Q1 | Licensee-Identified Violation | Unit 1 Technical Specification 3.4.3, Safety/Relief Valves, required that twelve of thirteen main steam safety relief valves (MSRVs) lift at a setpoint within plus or minus three percent of a specified value. Contrary to Technical Specification 3.4.3, for the time period of October 2012 to October 2014, the lift setpoints of two MSRVs exceeded the plus or minus three percent TS allowed pressure band. This TS violation was entered into the licensees CAP as PER 962223. The finding was determined to be of very low safety significance because the as-found lift setpoint conditions of the Unit 1 MSRVs were evaluated and determined to meet the design basis criteria for the most limiting reactor pressure vessel over-pressurization events. |
| 05000366/FIN-2015001-02 | Hatch | 2015Q1 | Failure to perform complete analysis of air samples | An NRC-Identified non-cited violation (NCV) of TS 5.4.1 was identified for the failure of the licensee to perform complete quantitative analysis of air samples using approved counting equipment as required by the licensees procedures. NMP-HP-301, Step 5.6, provides guidance for quantitative evaluation of air samples. On February 16, and 25, 2015, air samples for work activities in the Reactor Pressure Vessel head (RPV) and the Reactor Water Cleanup (RWCU) System heat exchanger were not quantitatively analyzed or evaluated for alpha activity even though the areas had been identified as having elevated alpha contamination levels. The licensee entered the issue into their corrective action program (CAP) as CR 10034556. The finding was more than minor because it was associated with the Occupational Radiation Safety Program attribute of exposure control and affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from airborne radioactive material during routine civilian nuclear reactor operation. Failure to identify potentially significant contributors to internal dose could lead to unmonitored occupational exposures. The finding was determined to be of very low safety significance (Green) because it did not involve: (1) an as low as is reasonably achievable finding, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose related to As Low As Reasonably Achievable (ALARA) Planning and the ability to assess dose was not compromised during this instance. The cause of this finding was directly related to the cross-cutting aspect of following processes, procedures, and work instructions in the Procedure Adherence component of the Human Performance area. |
| 05000331/FIN-2014005-07 | Duane Arnold | 2014Q4 | Ineffective Radiological Engineering Controls Resulted in Unplanned and Unintended Radiological Intakes to Workers | A finding of very-low-safety significance and an associated non-cited violation of Title 10 of the Code of Federal Regulation, Section 20.1701 was self-revealed during work activities associated with the failure to implement effective radiological engineering controls during reactor pressure vessel (RPV) disassembly that resulted in personal contaminations and unplanned and unintended radiological intakes to workers. Specifically, on October 5, 2014, several individuals working on the refuel floor were contaminated and several received small intakes of radioactive material while venting the RPV head. The licensee entered the issue into the Corrective Action Program as condition report 01996216. Corrective actions included revising applicable procedures for RPV flood-up with the RPV vented to atmosphere on the refuel floor. The finding was more than minor because it impacted the program and process attribute of the Occupational Radiation Safety cornerstone and adversely affected th cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation. Specifically, the failure to implement effective radiological engineering controls during RPV disassembly resulted in personal contaminations and low dose intakes to several workers. The inspectors also concluded that the radiological hazards had the potential to result in higher exposures to the individuals had the circumstances been slightly altered. The finding was determined to be of very-lowsafety significance because it was not an ALARA planning issue; there was neither overexposure nor a substantial potential for an overexposure; and the licensees ability to assess dose was not compromised. This finding was associated with the crosscutting aspect of operating experience in the area of Problem Identification and Resolution because the licensee did not systematically implement relevant external operating experience in a timely manner. (P.5) |
| 05000220/FIN-2014007-03 | Nine Mile Point | 2014Q4 | Deficient Design Control of Protective Device Sizing for Unit 1 Core Spray Injection Motor-Operated Valves | The team identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, because Exelon did not verify the design adequacy of Nine Mile Point Unit 1 electrical power to safety-related MOVs to support their design function during design basis events. Specifically, Exelon did not verify that the thermal/magnetic breaker (TMB) protection on core spray (CS) loop injection MOV circuits 1V-40-01, 1V-40-09, 1V-40-10, and 1V-40-11 were properly sized to support the design function of repetitive MOV operation (throttling) in response to a design basis loss-of-coolant accident (LOCA). Routine throttling operation of the CS injection valves could potentially cause a TMB trip and loss of power to the MOV leading to the valve failing in an indeterminate position and not being capable of performing its design function to control reactor pressure vessel (RPV) level. Immediate corrective action included guidance to control room operators to close three of the MOVs when required to maintain RPV level and only use MOV 1V-40-09 which had a TMB tripping design of 17 seconds Exelon entered this issue into its corrective action program as issue report 2393386. The finding was more than minor because it is associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team determined that the finding was of very low safety significance (Green) because it was a design deficiency confirmed not to result in loss of operability or functionality. The team determined that the central cause of this finding was not reflective of current performance or current plant modification processes. Therefore no cross-cutting aspect was assigned. |
| 05000298/FIN-2014005-02 | Cooper | 2014Q4 | Implementation of Enforcement Guidance Memorandum 11-003, Revision 2, Causes Conditions Prohibited by Technical Specifications | During Refueling Outage 28, Cooper Nuclear Station performed Operations with a Potential for Draining the Reactor Vessel (OPDRV) activities while in Mode 5 without an operable secondary containment. An OPDRV is an activity that could result in the draining or siphoning of the reactor pressure vessel water level below the top of fuel, without crediting the use of mitigating measure to terminate the uncovering of fuel. Secondary containment is required by TS 3.6.4.1 to be operable during OPDRV. The required action for this specification is to suspend OPDRV operations. Therefore, entering the OPDRV without establishing secondary containment integrity was considered a condition prohibited by TS as defined by 10 CFR 50.73(a)(2)(i)(B). The NRC issued Enforcement Guidance Memorandum (EGM) 11-003, Revision 2, on December 13, 2013, to provide guidance on how to disposition boiling water reactor licensee noncompliances with TS containment requirements during OPDRV operations. The NRC considers enforcement discretion related to secondary containment operability during Mode 5 OPDRV activities appropriate because the associated interim actions necessary to receive the discretion ensure an adequate level of safety by requiring licensees immediate actions to: (1) adhere to the NRC plain language meaning of OPDRV activities, (2) meet the requirements which specify the minimum makeup flow rate and water inventory based on OPDRV activities with long drain down times, (3) ensure that adequate defense in depth is maintained to minimize the potential for the release of fission products with secondary containment not operable by (a) monitoring RPV level to identify the onset of a loss of inventory event, (b) maintaining the capability to isolate the potential leakage paths, (c) prohibiting Mode 4 (cold shutdown) OPDRV activities, and (d) prohibiting movement of irradiated fuel with the spent fuel storage pool gates removed in Mode 5, and (4) ensure that licensees follow all other Mode 5 TS requirements for OPDRV activities. The inspectors reviewed this Licensee Event Report for potential performance deficiencies and/or violations of regulatory requirements. The inspectors reviewed the stations implementation of the Enforcement Guidance Memorandum 11-003, Revision 2, during operations with a potential for draining the reactor vessel. Specific observations included: 1. The inspectors observed that the operations with a potential for draining the reactor vessel activities were logged in the control room narrative logs, and that the log entry appropriately recorded the standby source of makeup designated for the evolutions. 2. The inspectors noted that the reactor vessel water level was maintained at least greater than 21 feet above the top of the reactor pressure vessel flange as required by Technical Specification 3.9.6. The inspectors also verified that at least one safety-related pump was the standby source of makeup designed in the control room narrative logs for the evolutions. The inspectors confirmed that the worst case estimated time to drain the reactor cavity to the reactor pressure vessel flange was greater than 24 hours. 3. The inspectors verified that the operations with a potential for draining the reactor vessels were not conducted in Mode 4 and that the licensee did not move irradiated fuel during the operations with a potential for draining the reactor vessels. The inspectors verified that two independent means of measuring reactor pressure vessel water level were available for identifying the onset of loss of inventory events. Technical Specification 3.6.4.1 requires, in part, that secondary containment shall be operable during operations with a potential for draining the reactor vessel. Technical Specification 3.6.4.1, Condition C, requires the licensee to initiate actions to suspend operations with a potential for draining the reactor vessel immediately when secondary containment is inoperable. Contrary to the above, from October 3, 2014 to October 22, 2014, Cooper Nuclear Station performed operations with a potential for draining the reactor vessel activities while in Mode 5 without an operable secondary containment. Specifically, the station conducted the following seven operations with a potential for draining the reactor vessel activities without an operable secondary containment: Draining reactor recirculation pump without the jet pump plugs fully installed Control rod drive maintenance Removal of jet pump plugs associated with reactor recirculation pump B maintenance Venting the control rod drives Defeating the scram function for two control rod drives and support IVVI inspections Reactor recirculation pump A seal maintenance Control rod drive freeze seal These conditions were reported as conditions prohibited by Technical Specifications. The licensee entered this issue into its corrective action program as Condition Reports CR-CNS-2014-06293. Since this violation occurred during the discretion period described in EGM 11-003, Revision 2, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy, and, therefore, will not issue enforcement action for this violation. In accordance with EGM 11-003, Revision 2, each licensee that receives discretion must submit a license amendment request within 4 months of the NRC staffs publication in the Federal Register of the notice of availability for a generic change to the standard TS to provide more clarity to the term OPDRV. The Licensee Event Report is closed. |
| 05000219/FIN-2014005-01 | Oyster Creek | 2014Q4 | Reactor Head Cooling Spray Piping Flange Misalignment | The inspectors identified an NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because Exelon did not promptly correct a condition adverse to quality associated with the reactor head cooling (RHC) spray line 2-inch upper flange which was installed in a configuration that exceeded the allowable acceptance criteria. Specifically, Exelon staff identified a misaligned flange condition in IR 845395 but did not correct the deficiency by evaluation, repair or replacement during the 1R22 refueling outage in 2008 or subsequently during the 1R23 and 1R24 refueling outages. Exelon staff completed corrective actions to replace the flange during the 1R25 refueling outage after the NRC inspector questioned the acceptability of this condition. Exelon staff entered this issue into their corrective action program as IR 2385501. The finding is more than minor because it is associated with the equipment performance attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, misalignment of the RHC spray line flange was greater than that provided in Oyster Creek pipe specifications and resulted in additional stresses in the flange weld. This condition was identified by Exelon staff as a possible contributor to the occurrence of a through wall crack and leak in the N7B upper flange socket weld joint that was identified and repaired in November 2012, but the misalignment was not corrected at that time. The inspectors screened this issue using IMC 0609.04, Phase 1 Initial Screening and Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, and determined this finding was of very low safety significance (Green). The inspectors determined that this finding had a Problem Identification and Resolution cross-cutting aspect because Exelon did not evaluate and take timely corrective actions to address the long-standing repetitive flange alignment issue of the reactor head cooling spray piping flange connection to reactor pressure vessel head N7B nozzle. |
| 05000388/FIN-2014008-01 | Susquehanna | 2014Q3 | Inadequately Maintained Procedures for Plant Shutdown to Hot Standby led to Reactor Water Level and Power Transients | A self-revealing Green NCV of Technical Specification (TS) 5.4.1, Procedures, was identified because PPL did not adequately maintain operating procedures for plant shutdown to hot standby. Specifically, the general operating procedure for plant shutdown to minimum power and the reactor feed pump (RFP) operating procedure were revised, and the technical reviews did not adequately verify the functional and technical adequacy of the procedures. The technical reviews did not identify a valve lineup conflict existed between the two procedures. The conflict resulted in an improper feed lineup to the reactor pressure vessel (RPV) causing two level transients and corresponding power transients of approximately five percent on March 20, 2014. PPLs corrective actions included mitigating the pressure vessel level transients, collecting personnel statements, revising the general operating procedure to remove the valve conflict, initiating an apparent cause evaluation to determine the cause of the level transients, resetting the Operations Department human performance clock due to operator performance issues during the event, reviewing the event with every Operations Department shift crew, performing a standdown for the Operations Department to compare operator performance issues between this event and the December 19, 2012 scram event, as well as entering the events of March 1, 2014, and March 20, 2014, into the corrective action program as condition report (CR)-2014-08941 and CR-2014-10388. The inspectors determined that PPLs inadequate maintenance of procedures for plant shutdown to hot standby was more than minor, because it is associated with the procedure quality attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the inadequate technical reviews associated with the revision of procedures for placing standby RFPs into service in startup level control and valve control (manual), and procedures for placing standby RFPs into service in the flow control mode (FCM) and valve control (manual) mode, resulted in two reactor power transients up to five percent and two significant reactor vessel water level transients which challenged the stability of the plant. Additionally, this issue is similar to Example 4b described in IMC 0612, Appendix E, Examples of Minor Issues, which states that issues are not minor if procedure issues cause a reactor trip or other transient. The inspectors evaluated the finding using Attachment 0609.04, "Initial Characterization of Findings," worksheet to IMC 0609, Significance Determination Process, issued June 2, 2011. The attachment instructs the inspectors to utilize IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, issued June 19, 2012. The inspectors determined this finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of feedwater) and is therefore of very low safety significance (Green). A cross-cutting aspect was assigned in the area of Human Performance, Change Management, because leaders did not use a systematic process for evaluating and implementing change so that nuclear safety remained the overriding priority. Specifically, PPL did not maintain a clear focus on nuclear safety when implementing changes to the general operating procedure for shutdown to minimum power and this resulted in an unintended procedure discrepancy (H.3). |
| 05000458/FIN-2014004-05 | River Bend | 2014Q3 | Licensee-Identified Violation | Title 10 CFR 20.1501(a) requires that each licensee make, or cause to be made, surveys that may be necessary for the licensee to comply with the regulations in 10 CFR Part 20 and that are reasonable under the circumstances to evaluate the extent of radiation levels, concentrations or quantities of radioactive materials, and the potential radiological hazards that could be present. Pursuant to 10 CFR 20.1003, a survey means an evaluation of the radiological conditions and potential hazards incident to the production, use, transfer, release, disposal, or presence of radioactive material or other sources of radiation. Title 10 CFR 20.1201(c) states, in part, the assigned deep-dose equivalent must be for the part of the body receiving the highest exposure. Contrary to this requirement, the licensee did not make or cause to be made surveys that were necessary for the licensee to comply with the regulations of 10 CFR 20.1201(c). Specifically, licensee representatives did not perform surveys to evaluate the radiation dose gradient in the reactor cavity, caused by placement of the reactor pressure vessel head, during work on March 15 and 16, 2013. The failure to provide dose gradient surveys was identified by the outage control center radiation protection representative while reviewing radiation survey records. Licensee personnel documented the failure to survey for radiation dose gradients in Condition Report CR-RBS-2013-02426 and performed an apparent cause evaluation. During follow-up actions, licensee personnel identified an example in which a worker received 104 millirem of unplanned radiation dose and reported it as an occupational exposure control effectiveness performance indicator occurrence. Using Inspection Manual Chapter 0609, Appendix C, "Occupational Radiation Safety Significance Determination Process," the inspectors determined the violation had very low safety significance because: (1) it was not an as low as is reasonably achievable (ALARA) finding, (2) there was no overexposure, (3) there was no substantial potential for an overexposure, and (4) the ability to assess dose was not compromised. |
| 05000341/FIN-2014007-01 | Fermi | 2014Q3 | Incorrect Valve Location in Procedure | The inspectors identified a finding of very low safety significance (Green) and associated NCV of Technical Specifications (TS) Section 5.4.1.a for the licensees failure to maintain Procedure 20.000.23, High RPV (Reactor Pressure Vessel) Water Level to address an RPV overfill event. Specifically, the licensee provided an incorrect location of a manual valve in the Standby Feedwater (SBFW) system. The procedure described the valve as being located in the turbine building basement, while the valve was actually located in a locked high radiation area in the north heater room. The licensee revised the procedure to include the correct location of the valve. The inspectors determined that the issue was more than minor because a reactor overfill event could impair the RCIC and HPCI systems during a fire in fire zone RW. The finding affected the Mitigating Systems cornerstone. The finding was determined to be of very low safety significance based on a detailed risk-evaluation. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution because the licensee did not take effective corrective actions to address a potential reactor pressure vessel overfill event. |
| 05000354/FIN-2014002-05 | Hope Creek | 2014Q1 | Failure to Maintain B.5.b Equipment in a State of Readiness to Support Mitigation Strategies per 10 CFR 50.54(hh)(2) | The inspectors identified a Green NCV of 10 CFR 50.54(hh)(2), Conditions of Licenses. Specifically, PSEG failed to adequately assess the functionality of the B.5.b portable gas generator on multiple occasions and implement adequate corrective actions in response to repeated failures of the B.5.b portable gas generator. This resulted in an unrecoverable and unavailable individual mitigating strategy associated with the remote operation of safety relief valves (SRV) with reactor pressure vessel (RPV) injection for approximately two and half months while the portable gas generator was unavailable. PSEGs corrective actions include repairing the B.5.b portable gas generator and returning it to an available, standby condition as well as performing a validation of all B.5.b equipment and associated mitigating strategies. The inspectors determined the performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). The inspectors determined that this finding was of very low safety significance using NRC IMC 0609, Appendix L, B.5.b Significance Determination Process, Table 2 - Significance Characterization, dated December 24, 2009, as specified for 10 CFR 50.54(hh) findings by IMC 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, because the finding affected the Mitigating Systems cornerstone while the plant was at power and resulted in an unrecoverable unavailability of an individual mitigating strategy. Specifically, because the B.5.b portable gas generator was not functional for approximately 2.5 months with no compensatory actions in place, the Remote Operation of SRVs with RPV Injection mitigation strategy per Hope Creek procedure HC.OP-AM.TSC-0024, Revision 8, was determined to be unrecoverable and unavailable during this time. The inspectors noted that the reactor core isolation cooling (RCIC) system remained functional during this time period and as such the finding did not represent an unrecoverable unavailability of multiple mitigating strategies such that injection to RPV could not have occurred. The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting aspect of Problem Identification and Resolution, Evaluation, because PSEG failed to thoroughly evaluate equipment deficiencies related to the B.5.b portable gas generator to ensure that the resolutions addressed causes and extent of conditions commensurate with the B.5.b equipments safety significance. |
| 05000416/FIN-2013005-01 | Grand Gulf | 2013Q4 | Failure to comply with Technical Specification 3.4.11 (Section 1R20) | The inspectors identified a non-cited violation of Technical Specification 3.4.11 for the failure to comply with the Reactor Coolant System (RCS) Pressure and Temperature Limits Report (PTLR) during plant cold startups. Specifically, the PTLR had a lower limit of zero psig, and the licensee operated the reactor pressure vessel (RPV) below zero psig during the plant start-up that commenced on November 2, 2013. A review of plant data showed that the RPV pressure was maintained below zero psig for approximately 2 hours. The licensee performed an engineering evaluation and determined that the maximum compressive stress experienced by the RPV did not exceed the maximum yield strength of RPV. Immediate corrective action included revising Procedure 03-1-01-1, Cold Shutdown to Generator Carrying Minimum Load, to ensure the RPV is pressurized prior to opening the main steam isolation valves (MSIVs) and providing training on the procedural changes to all the operating crews. The licensee entered this issue into the corrective action process under Condition Report CR-GGN-2013-07021. The failure to comply with the RCS Pressure and Temperature Limits Report specified in Technical Specification 3.4.11 was a performance deficiency. The performance deficiency was determined to be more than minor, and therefore a finding, because it was associated with the human performance attribute of the Barrier Integrity Cornerstone and had the potential to adversely affect the associated cornerstone objective of providing reasonable assurance that a physical design barrier (reactor coolant system) protects the public from radionuclide release caused by accidents or events. Specifically, without NRC review and approval of revised pressure and temperature limits that include operating the RPV below zero psig, the inspectors did not have reasonable assurance the RPV would not be adversely affected. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, June 19, 2012, the inspectors determined that the issue affected the Barrier Integrity Cornerstone. Using NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At-Power, June 19, 2012, Exhibit 3, the inspectors determined that since this finding involved the reactor coolant system boundary, a detailed risk evaluation was required. The Senior Reactor Analyst reviewed the finding and determined that a detailed risk evaluation was not required. The licensee performed an engineering evaluation and concluded that there was no impact to the reactor vessel. As a result, the Senior Reactor Analyst concluded that there was no change in risk due to the performance deficiency. The inspectors determined that since the procedural steps to perform Attachments VIII and X concurrently had been in place since 1994, this was a latent issue; therefore no cross-cutting aspect was assigned. |
| 05000440/FIN-2013007-01 | Perry | 2013Q4 | Failure To Comply With Technical Specification 3.4.11 | The inspectors identified a finding of very low safety significance (Green) and associated Non-Cited Violation of Technical Specification 3.4.11, RCS Pressure and Temperature (P/T) Limits, for failure to comply with reactor pressure vessel pressure/temperature limits. Specifically, in 2011 the inspectors identified the pressure/temperature limits in Technical Specification 3.4.11 only contained values for reactor pressure vessel pressures greater than 0 pounds per square inch gauge. However, between June 2011 and July 2013, the licensee operated the plant with a vacuum in the reactor pressure vessel during 5 cold startups and 1 cooldown. The licensee entered the finding into its corrective action program as Condition Report CR 2013-18689. The performance deficiency was determined to be more than minor because the finding was associated with the area of Routine Operations Performance within the Human Performance attribute of the Barrier Integrity Cornerstone and had the potential to adversely affect the associated cornerstone objective of providing reasonable assurance that a physical design barrier (reactor coolant system) protects the public from radionuclide releases caused by accidents or events. The finding screened as very low safety significance because it was determined that there was no change in risk due to the performance deficiency. This finding has a cross-cutting aspect in the area of human performance, resources. Specifically, complete, accurate, and up-to-date procedures were not available to operators to ensure operations within the requirements of Technical Specification 3.4.11. |
| 05000456/FIN-2013008-02 | Braidwood | 2013Q4 | Inaccurate/Incomplete Information For Exemption Request From 10 CFR 50.60 | The inspectors identified a finding of very low safety significance (Green) and an associated Severity Level IV Violation of 10 CFR 50.9 Completeness and Accuracy of Information, for the licensees failure to provide information to the NRC that was complete and accurate in all material respects. Specifically, in Letter RS-05-103 License Amendment Request Regarding Reactor Coolant System Pressure and Temperature Limits Report and Request for Exemption from 10 CFR 50.60, the licensee stated that WCAP-16143 provides a valid basis for changing the reactor pressure vessel (RPV) closure head flange limit and maintains the relative margin of safety commensurate with that which existed at the time the 10 CFR Part 50, Appendix G requirement was issued. However, the analysis documented in WCAP-16143 demonstrated adequate vessel margins based upon the original closure head flange configuration and did not represent the modified closure head configuration (53 head studs) applicable to the Unit 2 reactor vessel. Therefore, this analysis did not provide a valid basis for changing the Unit 2 RPV closure head flange limits in 10 CFR Part 50, Appendix G. The licensee entered this issue into the Corrective Action Program (AR 01558067), performed an operability evaluation, and was evaluating several options for corrective measures. The corrective actions under consideration by the licensee included: completing a calculation to validate the Westinghouse Electric vendor letter, revision to WCAP-16143, installation of a 54th head stud, submittal of a license amendment request with a revised WCAP-16143, or negate the existing exemption methodology and return to the pressure temperature limit curves based upon 10 CFR Part 50, Appendix G requirements. The inspectors determined that this issue was more than minor because it adversely affected the Barrier Integrity Cornerstone attribute of Design Control. The inspectors also answered yes to the More-than-Minor screening question, If left uncorrected, would the performance deficiency have the potential to lead to a more significant safety concern? Specifically, the inspectors determined that this issue was more than minor because, if left uncorrected, the failure to provide complete and accurate information for the Unit 2 vessel head stud configuration could have resulted in non-conservative pressure temperature limit curves that allowed operation in an unacceptable region that would increase the possibility of vessel failure during a pressurized thermal shock event. The inspectors performed a Phase I SDP screening using IMC 0609, Attachment 0609 Appendix A, Exhibit 3-Barrier Integrity Screening Questions, and selected the box under the Reactor Coolant System Boundary (e.g., pressurized thermal shock issues), which required a detailed risk-evaluation. A Region III Senior Reactor Analyst performed a detailed risk-evaluation of this finding. A potential increase in the probability for vessel failure would exist if the plant was operated in the unacceptable pressure temperature regions and a pressurized thermal shock event occurred. Based on the licensee and supporting vendor assessments which concluded that no substantial increase in vessel stresses will occur due to operation with 53 head studs, the driving force for crack propagation (e.g., K1) will remain essentially unchanged. However, to bound the delta risk-evaluation, it was assumed that the initiating event frequency for a reactor vessel failure increased by 10 percent. From the Braidwood Standardized Plant Analysis Risk Model Version 8.21, the initiating event frequency for reactor vessel failure from any cause was 1E-7/yr. Core damage is expected to occur if reactor vessel failure occurs. The exposure time for the finding was the maximum of one year. Thus, a bounding risk-assessment yields a delta risk of 1E-8/yr. Therefore, based on the detailed risk-evaluation, this finding is of very low risk significance (Green). Because the failure to provide complete and accurate information to the NRC had the potential to impede or impact the regulatory process, the finding was also evaluated in accordance with NRC Enforcement Policy for traditional enforcement. This violation was similar to an example of a Severity Level III violation identified in Section 6.9.c.1 of the NRC Enforcement Policy. However, after consideration by NRC management, and with the approval of the Director of the Office of Enforcement, it was determined that a Severity Level IV Cited Violation was appropriate. This decision was based upon the very low safety significance (Green) of the associated finding. The inspectors concluded that no cross-cutting aspect was applicable as the performance deficiency was not reflective of current performance because the issue was in excess of three years old. |
| 05000280/FIN-2013005-01 | Surry | 2013Q4 | Application of ASME Section XI, Table IWB 2500-1, Item B10.10, Inspection Requirements and Note 1 Exemptions | The inspectors identified an unresolved item related to the inspection of the reactor pressure vessel (RPV) component supports as required by ASME BPVC Section XI, for which additional information is needed to determine if the issue of concern represents a performance deficiency or a violation of the regulatory requirements. The code of record for the current ISI program at Surry Power Station Unit 1 is the 1998 Edition of the ASME BPVC Section XI with the 2000 addenda. This Code edition includes inspection requirements for both nuclear class 1 piping and vessel supports (Subsection IWF) and their attachment welds (Subsection IWB). Subsection IWB, Table IWB-2500-1, item number B10.10, describes the examination requirements for welded attachments for vessels, piping, pumps, and valves. Note 1 of Table IWB- 2500-1 states that attachment welds (weld buildup) on nozzles that are in compression under normal load conditions and provide only component support are excluded from the surface examination requirements. The note also provides additional conditions to identify what type welded attachment configurations require inspection. Table IWB- 2500-1 also references Figures IWB-2500-13, -14 and -15 to further describe the examination requirements. The inspectors noted that the scope of the Surry Unit 1 ISI program for the inspection of the nuclear class 1 RPV supports did include the requirements for the IWF portion of the ASME Section XI code required inspections. However, the inspectors identified that the licensee excluded the surface examination requirements for the RPV support attachment welds required by Table IWB-2500-1, item number B10.10 based on the exemptions provided by Note 1 of the table. The licensees position was that the surface examinations are not required based on the exclusion criteria provided in Note 1 for attachment welds under compressive loads during normal conditions and the configurations described in Figures IWB-2500-13, -14 and -15. The inspectors reviewed design basis documents for the Unit 1 RPV supports and identified that the normal loading conditions of the supports included both compressive and shear loads. The inspectors determined that additional information and discussion with the NRC Office of Nuclear Reactor Regulation (NRR) staff was required, in order to determine if the licensees interpretation and implementation of the exemptions in Table IWB-2500-1 were in compliance with the ASME BPVC Section XI. Therefore, the NRR and Region II staff agreed to submit a Task Interface Agreement (TIA), which could involve the submittal of a formal inquiry to the applicable ASME BPVC committee to request an interpretation of the examination requirements and exemptions in Table IWB- 2500-1 for welded attachments for vessels and piping. The NRC initiated TIA-2014-02 to determine the staffs position on whether the configuration of the RPV supports at Surry meets the exclusion criteria in ASME BPVC Section XI. This issue remains unresolved until the resolution of TIA-2014-02 to determine if the issue of concern represents a performance deficiency or a violation of regulatory requirements. This issue is identified as URI 05000280/2013005-01, Application of ASME Section XI, Table IWB 2500-1, Item B10.10, Inspection Requirements and Note 1 Exemptions. |
| 05000458/FIN-2013005-03 | River Bend | 2013Q4 | Operations Prohibited by Technical Specifications for Operations with a Potential to Drain the Reactor Vessel | On March 2, 2013, with the plant in a refueling outage, the licensee performed maintenance to replace the pump seals and the flow control valve packing in the A loop of the reactor recirculation system. The maintenance constituted an operation with a potential to drain the reactor vessel (OPDRV). Technical Specification 3.6.1.10 requires an operable primary containment during an OPDRV. The licensee did not take the actions to establish an operable primary containment during the maintenance window for the reactor recirculation system. Instead the licensee met the alternative requirements as described in NRC Enforcement Guidance Memorandum (EGM) 11-003, Dispositioning Boiling Water Reactor License Noncompliance with Technical Specification Containment Requirements during Operations with a Potential for Draining the Reactor Vessel, Revision 1. The alternative requirements that the licensee complied with include the following: 1) The inspectors verified that the licensee declared, in the control room logs, that the plant was in an OPDRV activity. In addition, the licensee took actions to ensure water inventory was maintained and that a defense-in-depth criteria, was in place prior to entering the OPDRV activity. 2) During the OPDRV activities, the reactor vessel water level was maintained at or above 23 feet over the top of the reactor pressure vessel flange. 3) The OPDRV was not conducted in Mode 4 and the licensee did not move recently irradiated fuel during the OPDRV. 4) The licensee evaluated that during the OPDRV activity, the time to drain down the water inventory from 23 feet over the top of the reactor pressure vessel flange, to the reactor pressure vessel flange was greater than 72 hours. This was based on the calculated maximum leak rate of OPDRV activities. 5) The capability to isolate the potential leakage path during OPDRV activities before the inventory reached the reactor pressure vessel flange was maintained. 6) During OPDRV activities, more than one safety-related pump was available that was aligned to a makeup water source with the capability to inject water at greater than the maximum potential leakage rate from the reactor pressure vessel, for a minimum time period of 4 hours. 7) The inspectors verified that the licensee maintained two independent means of monitoring the reactor pressure vessel water level in an effort to identify the onset of a loss of inventory event during the OPDRV activity. These monitoring methods were in accordance with the requirements stipulated in EGM 11-003 Technical Specification 3.6.1.10 is applicable during movement of recently irradiated fuel assemblies in the primary containment and/or during an OPDRV. This technical specification requires that primary containment shall be maintained operable during the applicable conditions. If containment operability is not maintained, then immediate actions should be taken to suspend either of the applicable conditions (fuel movement/OPDRVs). Contrary to the above, between 2:48 p.m. CST on March 2, 2013, and 8:30 a.m. CST on March 7, 2013, the licensee did not maintain primary containment in an operable status while conducting an OPDRV. This is a violation of NRC requirements. Because the violation was identified during the discretion period described in EGM 11-003, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation. The inspectors reviewed this licensee event report and the actions taken by the licensee. No problems were noted. This licensee event report is closed. |
| 05000397/FIN-2013007-07 | Columbia | 2013Q3 | Failure to Include ECCS Pumps NPSH Limits in the Emergency Operating Procedures | The team identified a Green non-cited violation of Technical Specification 5.4.1(b) which states, in part, Written procedures shall be established, implemented, and maintained covering the following activities: The emergency operating procedures required to implement the requirements of NUREG-0737 and NUREG- 0737, Supplement 1, as stated in Generic Letter 82-33. Specifically, from 1997 to August 21, 2013, the licensee failed to revise emergency operating procedures for reactor pressure vessel control and primary containment control when it was determined that the required net positive suction head for the emergency core cooling pump were no longer bounded by the pumps vortex limits. This violation was entered into the corrective action program as Action Request 292153. On August 21, 2013, the licensee implemented a night order giving guidance to monitor the pumps for cavitation and take actions to prevent degraded operation until the procedures were revised. The team determined that the failure to maintain emergency operating procedures which included appropriate net positive suction head limits in accordance with Technical Specification 5.4.1(b) was a performance deficiency. The performance deficiency was determined to be more than minor, and therefore a finding, because it was associated with the design control attribute of the Mitigating System cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the finding was more than minor because the procedures were in a condition that would adversely affect the licensees response to an emergency. Using the Manual Chapter 0609, Appendix A, Exhibit 2, the team determined the finding represented a loss of safety system function; therefore, the senior reactor analyst performed a bounding detailed risk evaluation. The analyst determined that the bounding change to the core damage frequency was less than 1.8E-8 per year (Green). Since the change in core damage frequency was less than 1E-7 per year, the finding was not significant to the larger early release frequency. This finding did not have a crosscutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance. |
| 05000263/FIN-2013004-03 | Monticello | 2013Q3 | Loss of Accurate Level Indication During Partial RCS Drain Down | A self-revealed finding of very low safety significance and non-cited violation of Technical Specification (TS) 5.4.1.a, Procedures, occurred on June 3, 2013, due to the licensees failure to implement procedures regarding maintenance or operations activities for draining and refilling the reactor vessel. Specifically, the licensee failed to follow Step 10 of Operations Manual B.02.02-05, Reactor Water Cleanup System Operation, Section G.1, Reactor Vessel Draining during Cold Shutdown Conditions, to adequately monitor water levels in the reactor during the reactor pressure vessel (RPV) partial draining process. While relying on a temporary installed level instrument, operators performed an RPV drain down which introduced pressure related inaccuracies into the temporary instrument and prevented operators from adequately monitoring vessel level. This resulted in a loss of positive configuration control of reactor coolant system (RCS) level during an infrequently conducted risk-significant evolution, and for four days thereafter. Corrective actions included transferring from the temporary level instrument to the flood up level instrument and enhancing RPV reassembly and temporary vessel installation procedures. This issue is more than minor because it is associated with the configuration control shutdown equipment lineup attribute of the Initiating Events Cornerstone and impacted the cornerstone objective to limit the likelihood of those events that challenge critical safety functions during shutdown operations. In addition, if left uncorrected, the reliance on inaccurate RPV level instrumentation could lead to a more significant safety issue because it constitutes a loss of positive control of reactor vessel level during a risk significant RCS drain down. Using IMC 0609, Appendix G, for shutdown operations, the inspectors determined that the finding had very low safety significance because it did not represent an inadvertent loss of two feet of RCS inventory or inadvertent RCS pressurization, and it did not adversely affect core heat removal, inventory control, power availability, containment control, or reactivity guidelines. The inspectors determined that this finding was cross-cutting in the Human Performance, decision making area, and involved aspects associated with using conservative assumptions in decision making and adopting a requirement to demonstrate that the proposed action is safe in order to proceed rather than a requirement to demonstrate that it is unsafe. |
| 05000387/FIN-2013004-01 | Susquehanna | 2013Q3 | Inadequate Procedural Guidance for Maintaining RPV Level During Anticipated Transient Without Scram | The inspectors identified a Green NCV of TS 5.4.1, Procedures, because PPLs emergency operating procedure step for terminating injection sources during a rapid depressurization required for an anticipated transient without scram (ATWS) was inadequate to ensure that cold unborated water was not injected into the core. Specifically, PPLs emergency operating procedure (EOP) does not terminate injection from the high pressure coolant injection (HPCI) system during the transient and procedural guidance is insufficient to ensure that operators will maintain level in the prescribed ATWS band while injecting with HPCI. In addition to entering the issue into the CAP as CRs 1708885 and 1745775, PPLs immediate corrective actions included issuance of Operations Directive 13-02 which states that HPCI must be controlled, up to and including overriding injection, to ensure that reactor pressure vessel water level is maintained in the prescribed ATWS band during the duration of the rapid depressurization. Planned corrective actions include requiring termination of HPCI injection prior to initiation of a rapid depressurization (Action Request 1719605). The performance deficiency is more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone and affected the objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the inadequate procedure for terminating injection prior to rapidly depressurizing the reactor during an ATWS could have resulted in operators failing to control level in the prescribed EOP band, potentially resulting in cold unborated water being injected into the core. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent actual loss of a safety function of a single train for greater than its Technical Specification (TS) allowed outage time, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The finding is related to the cross-cutting area of problem identification and resolution (PI&R), in that PPL did not identify a performance issue completely, accurately, and in a timely manner commensurate with the safety significance. Specifically, PPL failed to identify that guidance in EOP basis document was insufficient to ensure that operators maintained level in the EOP band. |
| 05000400/FIN-2013010-02 | Harris | 2013Q2 | Licensee-Identified Violation | The licensee identified a violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, which requires, in part, that measures shall be established to assure that conditions adverse to quality, such as deficiencies, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to this requirement, while performing ultrasonic examinations on the reactor pressure vessel head during the spring 2012 refueling outage as required by 10 CFR 50.55a(g)(6)(ii)(D), the licensee failed to identify an unacceptable indication in Nozzle 49 that overlapped the J-groove weld and exhibited characteristics of primary water stress corrosion cracking. This finding was determined to be of very low safety significance because subsequent visual and volumetric examinations performed did not detect any leakage and sizing of the indication determined that structural integrity of the vessel head was not compromised. Additionally, the licensee reanalyzed 100% of the spring 2012 inspection data and did not discover any further missed indications. The licensee entered this condition in their corrective action program as Action Request 00606317. |
| 05000321/FIN-2013003-02 | Hatch | 2013Q2 | Operation with Potential to Drain Reactor Pressure Vessel in Mode 5 Without Secondary Containment | A violation of Unit 2 TS 3.6.4.1 was identified. However, the licensee performed actions to ensure water inventory was maintained and defense in-depth criteria were place prior to performing activities with the potential to drain the reactor vessel as described in Enforcement Guidance Memorandum 11-003. In addition, the violation occurred during the discretion period stated in Memorandum. Therefore, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation, subject to a timely license amendment request being submitted. |
| 05000395/FIN-2013002-01 | Summer | 2013Q1 | Failure to Perform Examinations of Reactor Pressure Vessel Supports | The inspectors identified a non-cited violation (NCV) of Code of Federal Regulation (CFR) 10 CFR Part 50.55a, Codes and Standards, involving the licensees failure to include the reactor pressure vessel supports in the scope of the V. C. Summer Inservice Inspection Program (ISI) program. 10 CFR 50.55a requires that licensees develop an Inservice Inspection (ISI) program and update that program every 10 years in accordance with the approved edition of American Society of Mechanical Engineers (ASME) Section XI in effect 12 months prior to the beginning of the 10 year interval. The inspectors identified that the nuclear Class 1 reactor pressure vessel supports were not included in the scope of the V. C. Summer Unit 1 ISI Program for the third interval. The licensees ISI program was prepared in accordance with the 1998 Edition of the ASME Section XI Code, with addenda through 2000, as modified by 10 CFR 50.55a. As required by Article IWF 1000, Table 2500-1, Examination Category Item Number F1.40, the Reactor Pressure Vessel (RPV) supports are required to be periodically VT-3 visually examined. Also as required by Subsection IWB of Section XI, Table IWB-2500- 1, Examination Category B-K, Item No. B10.10, the support integral attachment weld is to be periodically subjected to a surface examination. This issue was entered into the licensees corrective action program as Condition Report (CR) 13-00138 and CR-13- 00737. The licensee took action and performed an operability determination and conducted remote visual examinations to assess the condition of the reactor vessel supports. The failure to include the RPV supports in the scope of the ISI program and the failure to conduct the required examinations was a performance deficiency that was within the ability of the licensee to foresee and correct. This finding was of more than minor significance because it was associated with the Design Control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, examinations of the RPV supports provide assurance that the structural boundary of the reactor coolant system remains capable of performing its intended safety function. The inspectors used IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 Initial Screening and Characterization of Findings, and determined that the finding was of low safety significance (Green) because it did not represent an actual failure of the RPV supports. The cause of the finding involved the cross-cutting area of problem identification and resolution, the component of operating experience (OE), and the aspect of implements and institutionalizes OE through changes to station process, procedures and programs, P.2(b). Specifically, the licensee failed to implement and institutionalize OE for RPV supports into station processes and procedures |
| 05000220/FIN-2013002-02 | Nine Mile Point | 2013Q1 | Test Conditions Not Properly Established | A self-revealing finding (FIN) was identified for the failure of Constellation Energy Nuclear Group, LLC (Constellation), maintenance personnel to ensure appropriate conditions were established during a surveillance test to confirm the lockup valves for flow control valve (FCV)-29-137 were properly functioning at Unit 1. As a result, a failure associated with the lockup valves was not detected during surveillance testing activities conducted in March 2011. This undetected failure led to an unexpected injection of water into the reactor pressure vessel (RPV) on November 6, 2012, during an unplanned outage, resulting in an increase in RPV water level, turbine trip signal, and initiation of the highpressure coolant injection (HPCI) logic. Constellation entered this issue into their corrective action program (CAP) as condition report (CR)-2012-010141. This finding is more than minor because it is associated with the human performance attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, because maintenance personnel did not properly implement procedure N1-IPM-029-010, Calibration of Feedwater FCV-29-134, FCV-29-137, and FCV-29-14, Revision 00603, the lockup valves for FCV-29- 137 were not adequately tested, and as a result, degraded valve performance was not detected during a March 2011 surveillance test. Consequently, on November 6, 2012, FCV- 29-137 unexpectedly failed partially open when instrument air was removed from the valve which caused a subsequent increase in RPV level, creation of a turbine trip signal, and initiation of the HPCI injection logic. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency did not cause a reactor trip, and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable, shutdown condition. This finding has a cross-cutting aspect in the area of Human Performance, Work Practices, because Constellation maintenance personnel did not effectively use human error prevention techniques such as peer and self checking to ensure plant conditions and system status were adequate to perform an air drop test on the lockup valves for FCV-29-137. Specifically, Constellation personnel failed to ensure the actuating cylinder for FCV-29-137 was pressurized prior to commencing the test. As a result, the air drop test was not properly conducted, and the degraded condition of the lockup valves was not identified, |