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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000352/FIN-2018010-01 | 2018Q3 | Limerick | Minor Violation | During this inspection, the team reviewed the details and status of Exelons corrective actions. Relative to EDG voltage, the TSs specified a lower limit of 4160 Vac; however, Exelons existing analysis determined the lower EDG voltage limit should be 4235 Vac. Exelon determined that this higher voltage value was necessary in order to ensure full EDG operability and qualification when considering a specific criteria (voltage drop during the loading sequence) as per NRC Regulatory Guide 1.9, Application and Testing of Safety-Related Diesel Generators in Nuclear Power Plants. The team determined that there was not an operability concern because Exelon determined that, although the voltage drop during the starting of the largest electrical load was slightly below the Regulatory Guide 1.9 value, all required loads would, in fact, successfully start and run as designed when started at the 4160 Vac level. Further, the EDG voltage regulators are designed and calibrated to operate the EDGs at 4235 Vac. Notwithstanding, the team identified that the associated EDG surveillance procedures did not contain the higher, administrative limit of 4235 Vac as an acceptance criterion (4160 Vac was specified). The team reviewed this issue using Inspection Manual Chapter 0612, Appendix B, Issue Screening, and determined that the use of non-conservative acceptance criterion was a minor procedure violation because the EDGs were controlled and operated to maintain voltage at 4235 Vac (and 4160 Vac does not render the EDGs inoperable), and EDG reliability or availability were not adversely affected. Exelon entered this minor violation in their corrective action program as IR 4164579 to document and correct this deficiency. For EDG frequency, the TSs allowed an acceptance band (58.8 61.2 Hertz), which is a range typical of EDG transient loading conditions. However, as described in WCAP-17308-NP, and as determined by Exelon engineering staff, a more narrow band (59.9 60.2 Hertz) is the appropriate operating range for steady state EDG operation. Exelon has appropriately maintained the narrow band as the acceptance criteria in the associated EDG surveillance procedures (compensatory action until TSs are revised). However, during this inspection, the team identified that in 2016, Exelon had slightly widened the acceptable band a one-tenth hertz to 59.8 60.2 Hertz. Further review by the team identified that this change was not properly evaluated in accordance with Exelons procedure change process. In particular, the procedure change received a less rigorous review than a 10 CFR 50.59 screen would have provided; and the team concluded that this screen should have been performed. In response, Exelon evaluated past surveillance results and analyzed the lower frequency value of 59.8 Hertz, and determined there to be no adverse consequence at 59.8 Hertz. The team reviewed Exelons analysis and similarly concluded that there was no adverse safety impact. The team reviewed this issue using Inspection Manual Chapter 0612, Appendix B, Issue Screening, and determined that the improper procedure change was a minor procedure violation because there were no adverse consequences and EDG reliability or availability were not adversely affected. Exelon entered this minor violation in there corrective action program as IR 4160819 and IR 4161542 to document and correct this deficiency. |
| 05000334/FIN-2017007-01 | 2017Q4 | Beaver Valley | Non -Conservative Differential Pressure Value Used in Low Head Safety Injection Motor -Operated Valve Design Analysis | The NRC team identified a finding of very low safety significance (Green) involving a non- cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, because FENOC staff did not establish measures to assure that the design bases were correctly translated into specifications, drawings, procedures, and instructions. Specifically, for the recirculation phase following a postulated small break loss -of-coolant accident, engineering staff determined the maximum differential pressure fo r motor- operated valves MOV -1SI -863A and MOV -1SI -863B to be the low head safety injection pump shutoff head, but the actual configuration could have resulted in a higher differential pressure at the valve due to allowable reactor coolant system leakage past downstream pressure isolation valves . In response, FENOC staff initiated corrective action program condition report s and assessed the deficiency , and concluded that affected motor -operated valves remained functional although with reduced valve thrust design margin . This finding was more than minor because it was associated with the Design Control 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. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At -Power, the team determined that this finding was of very low safety significance (Green) because it was a design deficiency confirmed not to result in the loss of operability or functionality. This finding was not assigned a cross -cutting aspect because the issue did not reflect current licensee performance. |
| 05000293/FIN-2017007-02 | 2017Q3 | Pilgrim | Inadequate Design Verification of Emergency Diesel Generator Under- Frequency Alarm Setpoint | The team identified a finding of very low safety significance (Green) involving an NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, in that Entergy did not adequately verify that the emergency diesel generator (EDG) under-frequency alarm setpoint was in accordance with design basis requirements. Specifically, the EDG under- frequency alarm was set at a value less than the prescribed industry standard to protect equipment, and station procedures did not contain instructions to address the EDG under- frequency condition. In response, Entergy staff evaluated and confirmed current EDG operability and initiated actions to correct the under-frequency range in the alarm setpoint and to provide appropriate operator response guidance in operating procedures. 3 This finding was more than minor because it was associated with the design control 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. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, the team determined that this finding was of very low safety significance (Green) because it was a design deficiency confirmed not to result in the loss of operability or functionality. The team determined that this finding had a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because Entergy did not plan for the possibility of latent issues while processing a plant modification where the bases for EDG alarm functions were incorrect. |
| 05000293/FIN-2017007-01 | 2017Q3 | Pilgrim | Failure to Incorporate the Correct Design Limit for the Condensate Storage Tank Water Temperature | The team identified a finding of very low safety significance (Green) involving a non- cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, in that Entergy did not translate the design basis limit for nil ductility transition (NDT) temperature into plant procedures. Specifically, Entergy specified in their procedures and tank heating setpoint calculation the low temperature limit for the two condensate storage tanks (CSTs) to be a non-conservative value, because it was based on the concern of CST freezing rather than the more limiting material service temperature of the downstream safety-related piping. In response, Entergy staff evaluated and confirmed current operability of the CST, and planned to evaluate and revise the affected procedures and tank heating setpoint calculation. This finding was more than minor because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, the minimum CST temperature value stated in procedures, based on an incorrect tank freezing assumption, could potentially result in not providing the full margin of protection against brittle fracture behavior in safety-related piping leading to the reactor vessel. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, the team determined the issue screened as having very low safety significance (Green) because it did not represent an actual loss of safety function of the system or train, did not result in the loss of one or more trains of non- technical specification (TS) equipment, and did not screen as potentially risk significant due to seismic, flooding, or severe weather. This finding was not assigned a cross-cutting aspect because the issue did not reflect current licensee performance. |
| 05000272/FIN-2017001-01 | 2017Q1 | Salem | Loss of Unit 1C 4kV Vital Bus due to Inadequate Activity Risk Screening | A self-revealing Green finding (FIN) was identified when PSEG did not screen the risk associated with replacing the Unit 1C emergency diesel generator (EDG) output breaker in accordance with WC-AA-105, "Work Activity Risk Management." Specifically, on December 14, 2016, the Unit 1C 4 kilovolt (kV) vital bus was inadvertently de-energized when the Unit 1 C EDG output breaker, which was removed without adequate risk mitigation actions, made contact with the switchgear (SWGR) cubicle door containing relays for bus differential current protection. PSEG entered this issue into their corrective action proggram (CAP) as NOTF 20751669 and performed apparent cause evaluation (ACE) 70191319. PSEG's corrective actions (CA) included inspecting the involved relay and re-energizing the vital bus. The finding was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerston's objective of ensuring the availability, reliability, and capability of systems relied upon to mitigate the consequences of an accident. The inspectors evaluated the finding in accordance with IMC 0609, Appendix A, Exhibit 2, and determined the finding was Green because it did not affect the design of qualification of a mitigating SSC, and did not represent an actual loss of function or system. The finding had a cross cutting aspect in the area of Human Performance, Work Management, because the work process did not include the identification and management of risk commensurate to the work and the need for coordination with different groups or job activities. Specifically, PSEG did not identify the level of medium risk associated with the work activity, did not manage the level of risk commensurate wiht the work, and did not coordinate appropriate mitigating actions with different work groups. |
| 05000272/FIN-2017001-02 | 2017Q1 | Salem | Inadequate Fire Risk Assessment and Management | Inspectors identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(a)(4) when PSEG did not adequately assess and manage the risk of online maintenance activities associated with the 13 and 23 charging (CV) positive displacement pumps (PDPs) and the 16 service water (SW) pump. Consequently, this resulted in the approval of hot work and the introduction of unaccounted for transient combustibles into a restricted fire area. PSEG wrote notifications (NOTFs) 20758370, 20759221, and 20761411 to document the observations and fire risk program gaps. On March 9, a roving fire watch was implemented as previously planned by PSEG. The finding was more than minor given its similarity to IMC 0612, Appendix E, example 7.e, in that had an adequate risk assessment been performed, it procedurally would have required additional risk management actions (RMAs). Additionally, this finding was more than minor because it adversely impacted the protection against external factors (fire) attribute of the Initiating Events cornerstone objective to limit the likelihood of events that upset plan stability and challenge critical safety functions during shutdown as well as power operations. The inspectors evaluated the finding in accordance with IMC 0609, Attachment 4 and Appendix K, since it involved a maintenance rule (MR) risk assessment. Since the performance deficiency was related to maintenance activities affecting structures, systems, and components (SSCs) needed for fire mitigation, Appendix K directed the significance to be determined by an internal NRC management review using risk insights. A Senior Reactor Analyst used risk insights from IMC 0609, Appendix F and its Attachment 2, to inform the significance and determined the issue screened to Green given that the combustible conditions and quantities were predominantly representative of a Low degradation rating. |
| 05000272/FIN-2017001-03 | 2017Q1 | Salem | Failure to Conduct Post-Maintenance Testing Required by Procedure and Work Order Resulting in Inoperable Containment Fan Coil Units | Green. A self-revealing Green non-cited violation (NCV) of Technical Specification (TS) 6.8.1, Procedures and Programs; TS 3.6.2.3, Containment Cooling Fans; TS 3.6.1.1, Primary Containment Integrity; and TS 3.0.4, Applicability, was identified. Specifically, PSEG did not perform a specified post-maintenance test (PMT) after replacing the air supply valve for service water (SW) system accumulator discharge valve 11SW535. As a result, valve 11SW535 failed its subsequent technical specification (TS) required stroke time to close surveillance, and rendered two of the five containment fan coil units (CFCUs) inoperable. PSEG entered this issue in the corrective action program (CAP) as NOTF 20736868 and completed corrective actions (CAs) included coaching the senior operator involved in closing the work order (WO) without ensuring the PMT was completed and a review of similar retest activities (no additional deficiencies identified). This issue was more than minor because it was associated with the human performance attribute of the Mitigating Systems corner stone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the incomplete PMT resulted in a delay in identifying a degraded stroke time and resultant inoperability of two CFCUs. The inspectors determined that this finding was Green in accordance with IMC 0609, Appendix A, Exhibit 2, because the finding did not result in an actual loss of function of a system or train. The finding had a cross-cutting aspect in the area of Human Performance, Work Management, because the organization did not implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. Specifically, PSEG did not execute WO instructions to conduct the appropriate PMT following maintenance on an air supply valve for SW accumulator discharge valve 11SW535, which resulted in 11SW535 stroking closed too fast and required declaring two CFCUs inoperable. (H.5) |
| 05000272/FIN-2017001-04 | 2017Q1 | Salem | Licensee-Identified Violation | TS LCO 3.3.2.1 requires the ESFAS instrumentation channels and interlocks shown in Table 3.3-3 shall be operable. Table 3.3-3, Function 1.d, pressurizer pressure-low, requires that with the number of operable channels one less than the total number of operable channels in Modes 1, 2, and 3 (at and above the P-11 setpoint, or 1925 psig), startup and/or power operation may proceed provided that the inoperable channel is placed in the tripped condition within 6 hours. TS LCO 3.3.3.1 requires the reactor trip system instrumentation channels and interlocks of Table 3.3-1 shall be operable. Table 3.3-1, Functions 7 (OTDT), 8 (pressurizer pressure low), and 9 (pressurizer pressure high), require that with the number of operable channels one less than the total number of operable channels in Modes 1 and 2, startup and/or power operation may proceed provided that the inoperable channel is placed in the tripped condition within 6 hours. TS LCO 3.4.3 requires, in part, that two PORVs shall be operable in Modes 1, 2, and 3. Action b requires, in part, that with one PORV inoperable, within 1 hour either restore the PORV to operable status or close its associated block valve and remove power from the block valve; restore the PORV to operable status within the following 72 hours or be in hot standby within the next 6 hours and in hot shutdown within the following 6 hours TS 3.0.4, Applicability, states, in part, that when a limiting condition for operation is not met, entry into a Mode or other specified condition in the Applicability shall only be made when the associated Actions to be entered permit continued operation in the Mode or other specified condition in the Applicability for an unlimited period of time; or after performance of a risk assessment addressing inoperable systems and components and establishment of risk management actions |
| 05000336/FIN-2017001-01 | 2017Q1 | Millstone | Failure to Maintain CST Temperature in Accordance with Procedural Requirements | Green. The inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to adequately implement Operating Procedure (OP) 2319B, Condensate Storage and Surge System. Specifically, Dominion failed to maintain the Millstone Unit 2 condensate storage tank (CST) temperature above procedural requirements. Dominion has documented this condition within their corrective action program (CAP) as condition report (CR) 1066291. The inspectors determined this finding was more than minor as it adversely affected the protection from external factors attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The reliability of the mitigating systems heat removal function was challenged based upon the reasonable doubt of lost operability of the CST to provide a sufficient supply of water to the auxiliary feedwater (AFW) system. There was reasonable doubt of lost operability due to indications of CST water temperature below OP 2319B prescribed limitations, winter temperatures falling, and an inability to restore CST recirculation system in a timely manner. The finding was determined to be of very low safety significance (Green), when all screening questions were answered No as the conditions discussed in the Dominion engineering evaluation, approved on January 7, 2017, were capable of showing that no safety systems or functions were lost. This finding has a crosscutting aspect in the Problem Identification and Resolution, Resolution, in that Dominion did not take effective corrective actions or corrective maintenance to address CST recirculation pump degradation in a timely manner, prior to the onset of winter, commensurate with their safety significance such that operations could maintain CST water temperature above procedurally defined limitations. (P.3) |
| 05000423/FIN-2017001-02 | 2017Q1 | Millstone | Change of C Charging Pump Testing Requirements Contrary to ASME OM | Green. The inspectors identified a Green NCV of 10 CFR 50.55a(f) because Dominion did not perform all required inservice testing (IST) of the Unit 3 C charging pump, 3CHS*P3C, in accordance with the American Society of Mechanical Engineers (ASME) Operation and Maintenance (OM) Code. Specifically, from April 15, 2016, to the end of the inspection period, Dominion stopped the required Group A quarterly surveillances which could result in a condition where degradation of the charging pump would remain undetected by IST testing. Dominion entered this issue into their CAP as CR 1064337. 4 This finding was more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, as it adversely affected the Equipment Performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Eliminating quarterly IST surveillance tests could challenge the reliability of the C charging pump and allow degradation of the equipment remaining undetected. In accordance with IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, and IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, Section A, Mitigating Systems, Structures or Components and Functionality, the finding screened to be of very low safety significance (Green), when the deficiency affecting the design or qualification whereupon the component maintains operability or functionality question was answered yes. The C charging pump has not yet experienced any failures. This finding has a cross-cutting aspect in Human Performance, Change Management, in accordance with IMC 0310, Aspects within the Cross-Cutting Areas, where leaders use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority. Specifically, Dominion evaluated this change to the IST program without requesting relief from the ASME Code requirements. (H.3) |
| 05000336/FIN-2017001-03 | 2017Q1 | Millstone | Licensee-Identified Violation | As discussed in Section 4OA2.2 of this report, the inspectors concluded that the ECCS minimum flow recirculation check valves should have been characterized as Category A valves, and should have been leak rate tested as per the IST Program. The associated LER is discussed in Section 4OA3.1. Title 10 CFR 50.55a, Codes and Standards, Section (f)(4), required in part, that throughout the service life of a pressurized water-cooled nuclear power facility, valves that are classified as Class 1, 2, or 3 must meet the IST requirements set forth in the ASME OM Code. Dominions Code of Record, ASME OM Code - 2001 Edition, Subsection ISTC-1300, Valve Categories, required that valves within the scope of Subsection ISTC-1300 shall be placed in one or more of the following categories, which included Category A (those valves for which seat leakage is limited 28 to a specific maximum amount in the closed position for fulfillment of their required function). The inspectors concluded that minimum flow recirculation check valve 2- CS-6A should have been a Category A valve, and leak rate tested, to assure fulfillment of its safety function (to mitigate the dose consequences of a postulated accident). Contrary to the above, since 1975, when the check valve 2-CS-6A was initially categorized, Dominion failed to appropriately categorize the subject valve and therefore did not meet the ASME OM Code requirements and 10 CFR 50.55a requirements. Specifically, failure to categorize the check valve as a Category A resulted in the valve not being subject to leak rate testing. This issue is more than minor because it was associated with the equipment performance 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 inspectors determined that the finding was of very low safety significance because it did not result in the loss of operability or functionality of a system or train, and the actual leakage through the check valve would not have resulted in a radiological dose in excess of regulatory requirements. Dominion entered the issue into the CAP as CR 582112 and CA 3013009. Because Dominion identified this issue of very low safety significance and it has been entered into their CAP, this finding is being treated as a licensee-identified NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. This item was considered licensee-identified because it was identified by Dominion as a result of deliberate observation by licensee personnel, and was entered into their CAP. |
| 05000277/FIN-2016004-01 | 2016Q4 | Peach Bottom | Failure to Identify and Remove FM in CAD System Piping | Green. The inspectors identified a finding of very low safety significance (Green) involving a non-cited violation (NCV) of 10 CFR 50 Appendix B Criterion XVI, Corrective Action, because Exelon did not adequately identify and correct a condition adverse to quality associated with the containment atmospheric dilution (CAD) piping system. Specifically, in 2012, Exelon did not adequately identify the source of foreign material (FM) and implement corrective actions to remove the FM from the CAD piping which resulted in the failure of the CHK-2-07C-40145 containment isolation valve to close in 2016. Exelon documented the issue in issue report (IR) 2735344 and promptly replaced the valve and restored the valve to operable. As an interim corrective action, Exelon plans to increase the local leak-rate test (LLRT) frequency and replacement of the check valve to maintain reasonable assurance of operability. Exelon is implementing a detailed troubleshooting plan to identify the source of FM and perform corrective actions to address the condition adverse to quality. The performance deficiency (PD) is more than minor because it was associated with the containment barrier performance attribute of the barrier integrity cornerstone and it adversely impacted the cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Characterization of Findings, and Appendix A, The SDP for Findings at-Power, Exhibit 3, and the inspectors determined this finding to be of very low safety significance (Green) because the degraded condition did not represent an actual open pathway in the physical integrity of containment, and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The inspectors determined that a cross cutting aspect does not apply because the performance deficiency occurred greater than three years ago and is not indicative of current plant performance. |
| 05000333/FIN-2016004-01 | 2016Q4 | FitzPatrick | Failure to Ensure Proper Configuration Control of a PCIV During Planned Maintenance | Green. The inspectors identified a Green NCV of Technical Specification (TS) 5.4, Procedures, because Entergy staff did not implement procedure AP-12.06, Equipment Status Control, as required. Specifically, Entergy personnel did not recognize the impact of a change associated with the tagout of a C residual heat removal (RHR) system primary containment isolation valve (PCIV). This resulted in motor operated valve 10MOV-13C being electrically isolated in the open position without being recognized as a PCIV and without proper entry into TS 3.6.1.3. Entergy restored the valve to operable status, entered this issue into their corrective action program (CAP) as condition report (CR)-JAF-2016-4419, and conducted meetings with each operating crew to discuss the event and reinforce standards for equipment status control and maintaining a questioning attitude. Training was also provided to operators to review the scenario and discuss requirements associated with PCIVs. This finding is more than minor because it was associated with the configuration control attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. Specifically, Entergy staff did not recognize the impact of a change associated with the tagout of a containment isolation valve. The change in the tagout resulted in a failure to isolate the containment isolation valve and enter TS 3.6.3.1 prior to maintenance. The finding was similar to Example 3.j in Appendix E of IMC 0612, Examples of Minor Issues, issued August 11, 2009. Since the PCIV was in an open position with power removed, a reasonable doubt of operability existed due to the valves inability to close to perform its containment isolation function. The inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings, issued October 7, 2016; Exhibit 3 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012; and Appendix H of IMC 0609, Containment Integrity Significance Determination Process, issued May 6, 2004. Using Exhibit 3 of IMC 0609, Appendix A, Section B, Reactor Containment, the finding directed the use of IMC 0609, Appendix H because it represented an actual open pathway in the physical integrity of reactor containment (i.e. valve). Using IMC 0609, Appendix H, the finding was classified as a Type B finding because it was related to a degraded condition that had potentially important implications for the integrity of containment, without affecting the likelihood of core damage (i.e. containment isolation was precluded by the isolation valve being failed in the open position, however the low pressure coolant injection function remained 4 available). Using Table 6.1, Phase 1 Screening-Type B Findings at Full Power, for a boiling water reactor, Mark 1 Containment, the inspectors were directed to perform a Phase 2 Assessment because the structure, system, and component (SSC) affected by the finding was a containment isolation valve. Using Table 6.2, Phase 2 Risk Significance-Type B Findings at Full Power, the inspectors determined that the failure of the containment isolation valve critical to suppression pool integrity/scrubbing was less than 3 days, and therefore was of very low safety significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Challenge the Unknown, because Entergy failed to maintain a questioning attitude to identify an improper configuration associated with a PCIV tagout during maintenance planning and execution. Specifically, a tagout writer modified the configuration for a containment isolation valve, which was not challenged or questioned during subsequent reviews. This resulted in the PCIV being tagged out in the open position, a condition that rendered the valve inoperable. (H.11) |
| 05000443/FIN-2016007-01 | 2016Q3 | Seabrook | Inadequate Corrective Actions to Preclude Repetition of a Significant Condition Adverse to Quality | The team identified a finding of very low safety significance, involving a non-cited violation of Title 10 of the Code of Federal Regulations, Part 50, Appendix B, Criterion XVI, Corrective Action, for not performing corrective actions to preclude repetition of a significant condition adverse to quality. Specifically, in 2008, two of four primary component cooling water (PCCW) pump motors failed within a four month period due to a manufacturing defect. NextEra established but did not perform a corrective action to replace all four motors with re-wound motors, free of the identified manufacturing defect. Subsequently, in 2015, a third motor failure occurred due to the same manufacturing defect. NextEras immediate corrective actions included entering this issue into their corrective action program (AR 2153536), implementing an electrical testing program that would provide an early indication of further degradation of the manufacturing defect until motor replacement, and completing a prompt operability determination to assess current PCCW system operability. This finding was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during power operations. 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, the team screened the finding for safety significance and determined that a detailed risk evaluation (DRE) was required because the finding involved a partial loss of a support system (PCCW pump B) that would increase the likelihood of an initiating event and impacted mitigating equipment (Item C - Support System Initiators of Exhibit 1). The DRE, performed by a Region I senior reactor analyst (SRA), concluded that the performance deficiency resulted in a change in core damage frequency of high E-7/yr, or very low safety significance (Green). The finding had a cross-cutting aspect in Problem Identification and Resolution (Resolution), because NextEra did not take effective corrective actions to address this issue in a timely manner commensurate with its safety significance. Specifically, NextEra did not perform motor replacements for susceptible installed PCCW motors within a reasonable due date as specified by the 2009 corrective action to preclude repetition (CAPR); and plant procedures, programs and resources were available for the decision-making process to schedule the motor replacement. |
| 05000443/FIN-2016007-03 | 2016Q3 | Seabrook | Failure to Perform Required ASME InService Testing of Manual Isolation Valves for the Atmospheric Steam Dump Valve Block Valves | The team identified a finding of very low safety significance, involving a non-cited violation of Seabrook Technical Specification Surveillance Requirement 4.0.5, Surveillance Requirements for In-Service Inspection and Testing of American Society of Mechanical Engineers (ASME) Code Class 1, 2, and 3 Components. Specifically, the manual isolation valves for the atmospheric steam dump valves had an active safety function to close, in order to mitigate the radiological consequences of a steam generator tube rupture (SGTR) accident, but had not been placed in the Seabrook In-Service Test Program and tested, as required by the Technical Specifications and ASME Code. As a result, degraded valve performance could go uncorrected without adequate acceptance criteria to ensure that a SGTR would not result in an unacceptable increase in the consequences of that accident (e.g., a more than minor reduction in the margin between the postulated licensing basis radiological release and the regulatory limits). In response, NextEra entered the issue into their corrective action program (AR 2153195) and performed a preliminary assessment of the valves, which concluded that they were fully operable. This finding was more than minor because it was associated with the System, Structure, or Component (SSC), and Barrier Performance attribute of the Containment Barrier Cornerstone and adversely affected the cornerstone objective of ensuring the reliability of associated risk-important SSCs. The team determined that the finding was of very low safety significance (Green) because it was a deficiency confirmed not to represent an actual open pathway in the physical integrity of reactor containment and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The finding did not have a cross-cutting aspect because it was not considered indicative of current licensee performance. |
| 05000443/FIN-2016007-02 | 2016Q3 | Seabrook | Potential Missed Evaluation and Reporting of an Adverse Condition to the NRC | Introduction: The team identified an unresolved item (URI) to further review whether NextEras evaluations associated with two PCCW pump motor failures in 2008 and one in 2015, and the associated conclusions not to report the conditions to the NRC, constituted a violation of NRC regulations. Description: As described in Section 1R21.2.1.3.1 above, the team reviewed two time periods where NextEra concluded that PCCW motor failures were the result of a manufacturing defect, however, these were not reported to the NRC. Specifically, a manufacturing defect was identified in a third-party failure analysis, dated January 21, 2009, following the failure of PCCW motors C and D in 2008. A third PCCW motor (B) failure occurred due to the same manufacturing defect in June 2015. These failures appeared to occur from one common cause. During this inspection, the team questioned whether the reporting requirements of 10 CFR Part 21 (Part 21), Reporting of Defects and Noncompliance, were satisfied, because no report was made to the NRC. In response to this concern, NextEra initiated AR 2153374, and initiated a substantial safety hazard (SSH) evaluation for the PCCW pump motor deviations in accordance with Part 21 and NextEra procedure LI-AA-102-1002, Part 21 Reporting. NextEra subsequently completed the SSH determination, and concluded that the deviation (i.e., the manufacturing defect) constituted a defect that could contain an SSH. They notified the NRC in accordance with 10 CFR 21.21(d)(3)(i) reporting requirements on October 20, 2016, via fax (Event Notification 52310). Subsequent to the onsite inspection, and while evaluating NextEras compliance with Part 21 evaluation and reporting requirements, the NRC noted that 10 CFR 21.2(c) stated, in part, that evaluation of potential defects and appropriate reporting of defects under 10 CFR 50.72 and 50.73 satisfies the evaluation, notification, and reporting obligation to report defects under Part 21. While the NRC recognized that NextEra had not made an NRC notification related to the identified PCCW motor manufacturing defect in accordance with 10 CFR 50.72, 50.73 or Part 21, the team did not review NextEras specific reportability evaluations with respect to 10 CFR 50.72 and 50.73. The team did note that NextEras Part 21 reviews, both in 2009 and 2015 did not specifically perform the evaluation specified in 10 CFR 21.21(a)(1) to determine whether the deviation in a basic component, which, on the basis of an evaluation, could create a substantial safety hazard. Since there appears to be overlapping reporting requirements among 10 CFR 50.72, 50.73 and 21.21, and the team did not specifically review NextEras reportability considerations for 10 CFR 50.72 and 50.73, additional inspection is necessary in order to determine whether there was a violation of any of the three reporting regulations. Accordingly, this issue is being treated as an unresolved item (URI) pending further inspection by the NRC staff to determine whether not evaluating and reporting the manufacturing defect associated with the PCCW motors constituted a more than minor violation of NRC reportability regulations. (URI 05000443/2016007-02, Potential Missed Evaluation and Reporting of an Adverse Condition to the NRC). |
| 05000410/FIN-2016001-01 | 2016Q1 | Nine Mile Point | Inadequate Procedure Leading to Failure to Manage Elevated Risk during Preventive Maintenance | The inspectors identified a non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, when Exelon did not assess and manage the increase in risk for online maintenance activities. Specifically on February 12, 2016, Exelon did not assess and manage risk during Unit 2 planned testing associated with the A residual heat removal (RHR) system heat exchanger (HX). The inspectors identified that although the testing would render the A RHR minimum flow valve 2RHS*MOV4A unavailable, this was not considered as part of the planned maintenance window, which resulted in an increase in risk during the unavailability of 2RHS*MOV4A. When properly calculated, plant risk should have been indicated as Yellow for the day and not Green. Exelon generated issue report (IR) 02625546 to document the inspectors concern regarding the status of the availability associated with the A RHR minimum flow valve during test setup for the A RHR HX. Exelon corrective actions included evaluating the risk management activities to be implemented when the minimum flow valves are subject to maintenance or testing activities to ensure future work is properly screened. This finding is more than minor because it is associated with the configuration control attribute of the Mitigating Systems cornerstone and adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, Exelons failure to plan for the unavailability of the A RHR minimum flow valve resulted in Unit 2 being placed in an unplanned elevated risk category (i.e., Yellow) without ensuring adequate compensatory measures were established and briefed to ensure maximum availability, reliability, and capability of the system. This issue is similar to Example 7.f of IMC 0612, Appendix E, Examples of Minor Issues, because the overall elevated plant risk placed the plant into a higher licensee-established risk category. The inspectors evaluated the finding using Phase 1, Initial Screening and Characterization worksheet in Attachment 4 and IMC 0609, Significance Determination Process. For findings within the Initiating Events, Mitigating Systems, and Barrier Integrity cornerstones, Attachment 4, Table 3, Paragraph 5.C, directs that if the finding affects the licensees assessment and management of risk associated with performing maintenance activities under all plant operating or shutdown conditions in accordance with Baseline Inspection Procedure 71111.13, Maintenance Risk Assessment and Emergent Work Control, the inspectors shall use IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, to determine the significance of the finding. The inspectors used Flowchart 1, Assessment of Risk Deficit, to analyze the finding and calculated incremental core damage probability using Equipment Out Of Service (EOOS), Exelons risk assessment tool. The inspectors determined that had this condition existed for the full duration of the Technical Specification (TS) limiting condition for operation (LCO), the incremental conditional core damage probability would have been 3.46E-9. Because the incremental core damage probability deficit was less than 1E-6 and the incremental large early release probability was less than 1E-7, this finding was determined to be of very low safety significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Work Management, because Exelon did not properly implement a process of planning, controlling, and executing the work activity such that nuclear safety was the overriding priority. Specifically, Exelon did not ensure risk was properly assessed during the planning process in accordance with WC-AA-101-1006, On-Line Risk Management and Assessment, Revision 001, prior to testing the A RHR HX, which caused unavailability of the A RHR minimum flow valve during certain periods of the test. |
| 05000410/FIN-2016001-02 | 2016Q1 | Nine Mile Point | 50.65(a)(4) Risk Evaluation Not Properly Performed Prior to Residual Heat Removal Heat Exchanger Testing | The inspectors identified a Green non-cited (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for Exelons failure to take risk management actions (RMAs) as required by procedure OP-AA-108-117, Protected Equipment Program, Revision 004, during a Unit 2, Division III, emergency switchgear electrical maintenance window on January 27, 2016. Specifically contrary to procedure OP-AA-108-117, during planned maintenance, Exelon failed to post the unit coolers in the A and B RHR pump and HX rooms, the C RHR pump room, and their associated breakers as protected equipment although their inoperability would have resulted in both trains of the standby gas treatment system (SBGT) being inoperable which would require entry into Technical Specification (TS) Limiting Condition for Operation (LCO) 3.0.3 and a short term shutdown action statement. Upon identification, Exelon generated IR 02617915 to document this issue. Corrective actions included creating an action item to evaluate Attachment 3 of N2-OP-52 and to determine the relevance of the TS LCO 3.0.3 entry requirement. The inspectors determined the performance deficiency to be more than minor because it was associated with the structure, system, and component (SSC) and barrier performance attribute of the Barrier Integrity cornerstone and adversely affected the associated cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, contrary to OP-AA-108-117, Exelon personnel failed to include the unit coolers for the Unit 2 RHR pump and HX rooms and their associated breakers, whose unavailability would have resulted in the inoperability of both trains of SBGT and necessitated entry into LCO 3.0.3. Additionally, Examples 7.e, 7.f, and 7.g from IMC 0612, Appendix E, Examples of Minor Issues, provided similar scenarios to this issue. Example 7.e details that a performance deficiency is more than minor if a failure to include accurate TS requirements in a risk assessment and if done properly, would have required RMAs, or additional RMAs under applicable plant procedures. The inspectors evaluated the finding using Phase 1, Initial Screening and Characterization worksheet in Attachment 4 to IMC 0609, Significance Determination Process. For findings within the Initiating Events, Mitigating Systems, and Barrier Integrity cornerstones, Attachment 4, Table 3, Paragraph 5.C, directs that if the finding affects the licensees assessment and management of risk associated with performing maintenance activities under all plant operating or shutdown conditions in accordance with Baseline Inspection Procedure 71111.13, Maintenance Risk Assessment and Emergent Work Control, the inspectors shall use IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, to determine the significance of the finding. The inspectors used Flowchart 2, Assessment of RMAs, to analyze the finding and calculated incremental core damage probability using EOOS, Exelons risk assessment tool, and found the result to be less than 1E-6. The inspectors determined that had this condition existed for the full duration of the TS LCO, the incremental core damage probability would have been 6.8E-7. Because the incremental core damage probability deficit was less than 1E-6 and the incremental large early release probability was less than 1E-7, this finding was determined to be of very low safety significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because Exelon failed to follow processes, procedures and work instructions. Specifically, Exelon failed to follow procedure OP-AA-108-117, which led to the failure to protect the unit coolers for the RHR pump rooms, HX rooms, and associated breakers which could have led to a TS LCO 3.0.3 entry. |
| 05000220/FIN-2016001-03 | 2016Q1 | Nine Mile Point | Inadequate Tagout Resulting in Reactor Building Closed-Loop Cooling Drain Down Event | A self-revealing Green non-cited violation (NCV) of Technical Specification (TS) 6.4.1, Procedures, was identified when a Unit 1 Exelon operator did not maintain proper configuration control of a plant system during a system tagout for planned maintenance. Specifically, on January 25, 2016, a Unit 1 non-licensed operator manipulated a reactor building closed-loop cooling (RBCLC) system drain valve out of sequence while performing a tagout for the #13 shutdown cooling (SDC) HX for planned maintenance. This resulted in unintentional draining of the operating RBCLC system, annunciation of multiple alarms in the main control room, and operators entering abnormal operating procedures to recover the RBCLC system. As part of corrective actions, proper configuration was promptly restored and the operator involved in the event was given a remediation plan for requalification and placed on an operations excellence plan. This finding is more than minor because it is associated with the configuration control attribute of the Mitigating Systems cornerstone and adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences; and if left uncorrected, the event had potential to lead to a more significant safety concern. Specifically, the failure to quickly isolate the drain down of the RBCLC system would have required a manual reactor scram, a manual trip of all five reactor recirculation pumps (RRPs), a manual isolation of the reactor water cleanup system, a loss of cooling to the spent fuel pool (SFP) cooling system, instrument air compressors, and the control room emergency ventilation system. The inspectors evaluated the finding using IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. The inspectors determined that this finding was of very low safety significance (Green) because the performance deficiency did not result in the loss of a support system, RBCLC, or affect mitigation equipment. This finding has a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because the non-licensed operator failed to follow Exelons procedures and the instructions he received at the pre job brief stop when manipulating the drain valve. Specifically, the non-licensed operator rationalized, without being the designated performer of the tagout, that it was acceptable to perform a valve manipulation out of sequence with the tagout plan. |
| 05000410/FIN-2016001-04 | 2016Q1 | Nine Mile Point | Licensee-Identified Violation | Eight-hour reports. If not reported under paragraphs (a), (b)(1), or (b)(2) of this section, the licensee shall notify the NRC as soon as practical and in all cases within eight hours of the occurrence of any of the following: (v) Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to: (C) Control the release of radioactive material. Contrary to the above, from April 2, 2014, until October 5, 2015, Exelon failed to submit an EN to the NRC within 8 hours upon discovery on a condition which could have prevented the safety function of a SSC needed to control the release of radioactivity on April 2, 2014, at 11:20 a.m. Specifically, secondary containment being declared inoperable due to both airlock doors being open at the same time in Mode 5 with an OPDRV in progress. The inspectors reviewed the violation using IMC 0612 Appendix B, Issue Screening, and the NRC Enforcement Policy. This violation impacted the regulatory process so traditional enforcement applies. Comparing this violation to the examples in the NRC Enforcement Policy Chapter 6, the violation matches Severity Level IV Example 6.9.d.9, a licensee fails to make a report required by 10 CFR 50.72 or 10 CFR 50.73. The NRC did not rely upon the information to make any regulatory decisions and the error did not result in increased scope or effort of NRC inspections. Compliance was restored when Exelon submitted LER 05000410/2014-007-01, Secondary Containment Inoperable due to Simultaneous Opening of Airlock Doors, to correct the public record and inform the NRC. Exelon staff entered the issue into its CAP. |
| 05000410/FIN-2016001-05 | 2016Q1 | Nine Mile Point | Licensee-Identified Violation | The holder of an operating license under this part shall submit a Licensee Event Report (LER) for any event of the type described in this paragraph within 60 days after the discovery of the event. (v) Any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to: (C) Control the release of radioactive material. Contrary to the above from June 2, 2014, until October 5, 2015, Exelon failed to submit an LER notification to the NRC within 60 days after discovery of a condition which could have prevented the safety function of a SSC needed to control the release of radioactivity on April 2, 2014 at 11:20 a.m. Specifically, secondary containment being declared inoperable due to both airlock doors being open at the same time in Mode 5 with an OPDRV in progress. The inspectors reviewed the violation using IMC 0612, Appendix B and the NRC Enforcement Policy. This violation impacted the regulatory process so traditional enforcement applies. Comparing this violation to the examples in the NRC Enforcement Policy Chapter 6, the violation matches Severity Level IV Example 6.9.d.9, a licensee fails to make a report required by 10 CFR 50.72 or 10 CFR 50.73. The NRC did not rely upon the information to make any regulatory decisions, and the error did not result in increased scope or effort of NRC inspections. Compliance was restored when Exelon submitted LER 05000410/2014-007-01 to correct the public record and inform the NRC. Exelon staff entered the issue into its CAP. |
| 05000317/FIN-2015007-02 | 2015Q4 | Calvert Cliffs | Failure to Verify AC Equipment Operability at Design Loading and Voltage Levels | The team identified a finding of very low safety significance (Green) involving a non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, because Exelon failed to verify, in design basis calculations, that all required Class 1E alternating current (AC) components would perform their safety functions during design basis events. Specifically, the team found multiple examples where Exelon failed to ensure AC equipment operability and functionality at maximum postulated loading levels and minimum allowable voltage levels. Specifically, the team found that during design basis events several transformers exceeded their manufacturers rating and Exelon had not performed an analysis that demonstrated voltage trip setpoints of the degraded voltage relays would ensure adequate voltage was available to supplied equipment. Exelon entered this issue into the corrective action program and performed preliminary analysis to show that there was reasonable assurance that equipment remained operable. The finding was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone design control attribute and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and was similar to Example 3j in Appendix E of the NRC IMC 0612. Using the NRC IMC 0609, Significance Determination Process, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to be of very low safety significance (Green) because it was a design deficiency confirmed not to result in the loss of operability or functionality. The team did not identify a cross-cutting aspect with this finding because it did not represent current performance. |
| 05000317/FIN-2015007-01 | 2015Q4 | Calvert Cliffs | Inadequate Verification of Offsite Power Operability Limit | The team identified a finding of very low safety significance involving a non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, "Design Control," because Exelon did not ensure the operability of offsite power in design calculations. The team determined that non-conservative assumptions caused the results of the voltage calculation to predict higher 4160 Volts, Alternating Current (VAC) switchgear post-trip voltage levels than those which could occur with existing controls. Specifically, the team found that Exelons calculation assumed a 3.2 percent switchyard voltage drop upon main generator trip, which did not bound the 5 percent alarm setting provided by the Transmission System Operator Security Analysis application. The team also determined that Exelon used a non-quantitative evaluation, which could not be verified, to adjust design basis calculation results in order to show that during a design basis event the 4160 VAC bus voltage would recover in time to reset the degraded voltage relay prior to the transient degraded voltage relay (TUR) tripping (causing a loss of offsite power). The team could not determine if offsite power would be lost during the event because these assumptions could not be validated. Exelon entered the issue into the corrective action program and performed preliminary computer modeling of the current plant configuration that showed offsite power was operable. The finding was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone design control attribute and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and was similar to Example 3j in Appendix E of the NRC IMC 0612. Using the NRC IMC 0609, Significance Determination Process, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to be of very low safety significance (Green) because it was a design deficiency confirmed not to result in the loss of operability or functionality. This finding was not assigned a cross-cutting aspect because it was a historical design issue not indicative of current performance. |
| 05000317/FIN-2015004-01 | 2015Q4 | Calvert Cliffs | Failure to Implement Procedures for the Control of Hazard Barriers During Maintenance | The inspectors identified a Green NCV of Technical Specification (TS) 5.4.1.a for Exelons failure to implement procedures as required by Regulatory Guide (RG) 1.33, Appendix A, Section 1, Administrative Procedures, during replacement of the 11 service water (SRW) pump motor, resulting in the SRW pump room door, a high energy line break (HELB) barrier, being impaired. This rendered the safety-related equipment protected by the HELB barrier inoperable. The inspectors determined that the failure to properly implement Exelon procedures EN-1-135, Control of Barriers, Revision 00202, and CC-AA- 201, Plant Barrier Control Program, Revision 11, was a performance deficiency that was reasonably within Exelons ability to foresee and prevent. Upon identification, Exelon staff entered this issue into their corrective action program (CAP) as issue report (IR) 2586773. Exelons immediate corrective actions included halting of impairing hazard barriers without considering the degraded barriers effect on equipment operability. The inspectors reviewed IMC 0612, Appendix B, Issue Screening, and determined the performance deficiency was more than minor because it adversely affected the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, Exelons actions in blocking open the HELB barrier resulted in a condition where structures, systems, and components (SSCs) necessary to mitigate the effects of a HELB may not have functioned as required; therefore, the reliability of these protected SSCs was adversely impacted. In accordance with IMC 0609, Attachment 4, Initial Characterization of Findings, issued on June 19, 2012, and IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, issued on June 19, 2012, the inspectors determined that a detailed risk evaluation was necessary to disposition the significance of this finding because the finding represented a loss of the SRW system. A regional Senior Reactor Analyst (SRA) performed a detailed risk evaluation using an exposure interval of 10 minutes as the maximum time the condition was allowed in the plant. Using these inputs yielded an initiating event frequency of 4E-9/year. From discussions with the inspectors, the analyst confirmed a list of affected equipment. The analyst bounded the scenario by assuming all mitigating equipment would be lost which gave a maximum change in core damage frequency of 4E-9/year. Since the bounded change in core damage frequency was less than 1E-6, the finding was determined to be of very low safety significance (Green). The inspectors determined that the finding had a cross-cutting aspect in the area of Human Performance, Work Management, because Exelon did not implement a process of planning, controlling, and executing work activities such that nuclear safety was the overriding priority. Specifically, Exelons process for planning and controlling maintenance did not identify the applicability of Exelon procedure CC-AA-201. |
| 05000317/FIN-2015004-03 | 2015Q4 | Calvert Cliffs | Licensee-Identified Violation | 10 CFR 55.25 states, in part, that if an operator develops a permanent physical or mental condition that causes the operator to fail to meet the requirements of 10 CFR 55.21, the facility licensee shall notify the Commission within 30 days of learning of the diagnosis, in accordance with 10 CFR 50.74(c) which states that the regional administrator shall be notified if a licensed operator develops a permanent disability or illness. Contrary to these requirements, as the result of Exelons medical examination audit completed August 8, 2014, Exelon identified four cases in which a change in licensed operator medical conditions were not communicated to the NRC within the required 30 days. The results of the medical examination audit were documented in IR 2423780 and subsequent notifications were made to the NRC. This violation is subject to traditional enforcement because of the potential impact upon the regulatory process for issuing restrictions to operators licenses. The inspectors determined that this issue meets the criteria for a Severity Level IV violation using example 6.4.d.1(a) from the NRC Enforcement Policy because no incorrect regulatory decision was made as the result of the failure of the licensee to report within 30 days. This is of very low safety significance because after NRC review of the subsequent notifications, no changes to license restrictions were required. |
| 05000317/FIN-2015004-02 | 2015Q4 | Calvert Cliffs | AFAS Channel Inoperable due to Valve Misposition | The inspectors documented a self-revealing Green NCV of TS 5.4.1.a for Exelons failure to implement procedures as required by RG 1.33, Appendix A, Section 8, Procedures for Control of Metering and Testing Equipment and for Surveillance Tests, Procedures, and Calibrations, during maintenance which resulted in a manual isolation valve (1HVFW-1804) being incorrectly placed in the closed position. This human performance error isolated the number 12 steam generator (SG) wide range level transmitter (1LT1124C) and subsequently rendered the auxiliary feedwater actuation system (AFAS) sensor channel ZF inoperable for 33 hours and 39 minutes, a condition prohibited by TS 3.3.4, Engineered Safety Features Actuation System (ESFAS) Instrumentation. The inspectors determined that the failure to properly implement procedure STP M-525AT-1 and place 1HVFW-1804 in its required position was a performance deficiency that was reasonably within Exelons ability to foresee and prevent. Upon identification, Exelon staff entered this issue into their CAP as condition report (CR)-2014-003320. Exelons immediate corrective action was to enter TS 3.3.4.A, to determine and correct the cause, and to retest the system for proper operation. The inspectors reviewed IMC 0612, Appendix B, Issue Screening, and determined the issue is more than minor because it adversely affected the configuration control attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, Exelon operated with manual isolation valve, 1HVFW-1804 closed which resulted in the inoperability of the AFAS sensor channel ZF for approximately 33 hours and 39 minutes. In accordance with IMC 0609, Attachment 4, Initial Characterization of Findings, issued on June 19, 2012, and IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, Exhibit 2, Mitigating Systems Screening Questions, issued on June 19, 2012, the inspectors determined that a detailed risk evaluation was necessary to disposition the significance of this finding because the finding represented an actual loss of function of at least a single train of AFAS for greater than its TS allowed outage time. A regional SRA performed a detailed risk evaluation. The finding was determined to be of very low safety significance (Green) because the redundant AFAS sensor was operable and functional to ensure actuation of the system if it had been required, therefore there was no loss of the system function. Additionally, the unit was in Mode 3 with very low decay heat levels during the time the ZF sensor channel was determined to be inoperable and plant procedures exist to manually start the AFW system if failure of automatic actuation were to occur. The inspectors determined that the finding has a cross-cutting aspect in the area of Human Performance, Challenge the Unknown, because Exelon did not stop when faced with an uncertain condition about the position of 1HVFW- 1804. Specifically, personnel conducting the second verification did not appropriately question the position of isolation valve 1HVFW-1804 because of the higher experience level of the personnel conducting the first verification. |
| 05000317/FIN-2015004-04 | 2015Q4 | Calvert Cliffs | Licensee-Identified Violation | 10 CFR 55.21 and 10 CFR 55.33 state, in part, that licensed operators are required to have a physical examination every two years to ensure that their medical condition and general health will not adversely affect the performance of assigned operator job duties or cause operational errors endangering public health and safety. As part of licensed operator medical evaluations, screening questions to identify potentially disqualifying medical conditions are required as specified in ANSI/ANS-3.4-1983, Medical Certification and Monitoring of Personnel Requiring Operator Licenses for Nuclear Power Plants. Contrary to this requirement, as a result of Exelons medical examination audit completed August 8, 2014, Exelon identified nine (9) licensed operators who were given an incomplete health questionnaire during their biennial medical examination. The questionnaire failed to request information about seven (7) potentially disqualifying health conditions from ANSI/ANS-3.4-1983 during a biennial medical examination. The omission of these seven potentially disqualifying conditions from the questionnaire resulted in an incomplete medical examination. Exelon identified that the cause was an incorrect revision to the sites medical examination process procedure. The revision issue was corrected in a subsequent revision and the audit documented that the nine licensed operators all completed medical evaluations with the correct screening questions within the next 18 months. The results of the medical examination audit were documented in IR 2423783. This violation is subject to traditional enforcement because of the potential impact upon regulatory process because the operators medical conditions are reviewed by the NRC when issuing or renewing operator licenses. The inspectors determined that this issue meets the criteria for a Severity Level IV violation using example 6.4.d.1(c) from the NRC Enforcement Policy because the operators who potentially did not meet ANSI/ANS-3.4, Section 5, due to an incomplete medical examination, subsequently were found to meet the health requirements for licensing. This is of very low safety significance because no incorrect regulatory decision was made as a result of the incomplete medical questionnaire and because no changes to license restrictions were required. |
| 05000352/FIN-2015007-02 | 2015Q3 | Limerick | Failure to Verify Adequate Voltage Available for DC Equipment | The team identified a finding of very low safety significance involving a non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, in that Exelons design control measures did not verify the adequacy of the design regarding adequate direct current voltage (Vdc). Specifically, Exelon did not ensure that adequate voltage existed to emergency diesel generator (EDG) relays and output breaker spring charging motors. Additionally, the team determined that the overall impact to voltage drop calculations was not adequately assessed when the temporary battery cart is used. Following identification of the issue, Exelon entered it into their corrective action program and evaluated the operability of the batteries, concluding that the affected DC components would function at the current battery capacities. The teams review of the evaluation determined it to be reasonable. The finding was more than minor because it was similar to Example 3.j of NRC IMC 0612, Appendix E, and was associated with the Design Control 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.The team determined the finding was of very low safety significance because it was a design deficiency affecting the safetyrelated batteries that did not result in the loss of operability or functionality. The team determined this finding had a cross-cutting aspect in the area of Human Performance, (Documentation, Aspect H.7) because the battery sizing calculation was revised on March 15, 2014, which provided an opportunity to identify the inaccuracies of the battery calculations. |
| 05000352/FIN-2015007-01 | 2015Q3 | Limerick | Failure to Verify Adequacy of EDG Voltage to Start Safety-Related Motors | The team identified a finding of very low safety significance involving a non-cited violation (NCV) of the 10 CFR Part 50, Appendix B, Criterion III, Design Control, in that Exelon did not verify and assure in design basis calculations, that adequate voltage would be available for starting Class 1E accident mitigating motors when the safeguards buses are powered by the emergency diesel generators (EDG). Specifically, in the calculation performed to evaluate voltage available to individual motors when they are powered by the EDGs, Exelon assumed that the generator output voltage would be 4285 Volts, alternating current (Vac), rather than the minimum voltage allowed by station technical specifications (4160 Vac). Additionally, the electrical ratings of loads powered by the EDG were not adjusted for the maximum frequency allowed by station technical specifications (61.2 hertz (Hz)). As a result, the starting voltage for some of the safetyrelated motors would not have been acceptable under EDG generator voltage and frequency limiting conditions. In response, Exelon entered the issue into their corrective action program and performed evaluation that determined that EDG actual test results demonstrated the EDGs to be operable. The team review of the evaluation determined it to be reasonable. This finding was more than minor because it was similar to Example 3.j of NRC IMC 0612, Appendix E, and was 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 the finding was of very low safety significance because it was a design deficiency confirmed not to result in a loss of safety-related motor operability or functionality. The team determined this finding had a cross-cutting aspect in the area of Problem Identification and Resolution (Identification, Aspect P.1), because during a calculation revision in 2014, Exelon did not recognize that the limits of voltage and frequency allowed by the station technical specifications affected the calculation results and, therefore, did not completely and accurately identify the issue and revise the calculation in accordance with the stations corrective action program requirements. |
| 05000293/FIN-2015002-04 | 2015Q2 | Pilgrim | Failure to Properly Ship Category 2 Radioactive Material Quantity of Concern | The inspectors identified a Green NCV of 10 CFR 71.5, Transportation of Licensed Material, and 49 CFR 172, Subpart I, Safety and Security Plans. Specifically, Entergy shipped a Category 2 Radioactive Material in Quantities of Concern (RAM-QC) on public highways to a waste processor without adhering to a transportation security plan. Prior to shipment, Entergys staff failed to recognize that the quantity of radioactive material met the definition RAM-QC. Entergy entered the issue into their CAP as CR-2015-05746 to address changes in Department of Transportation requirements. The finding was more than minor because it is associated with the program and process attribute of the Public Radiation Safety cornerstone and affected the cornerstone objective to ensure the safe transport of radioactive material on public highways in accordance with regulations. The finding was determined to be of very low safety significance (Green) because Entergy had an issue involving transportation of radioactive material, but it did not involve: (1) a radiation limit that was exceeded; (2) a breach of package during transport; (3) a certificate of compliance issue; (4) a low level burial ground nonconformance; or (5) a failure to make notifications or provide emergency information. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Identification, in that the licensee did not have a low threshold for identifying issues. Specifically, the security transportation plan requirements became effective in March 2003, had not been effectively identified by Entergy. |
| 05000293/FIN-2015002-03 | 2015Q2 | Pilgrim | Failure to Conduct Operations to Minimize the Introduction of Residual Radioactivity to the Site | The inspectors identified a Green NCV of 10 CFR 20.1406(c) in that Entergy did not conduct operations to minimize the introduction of residual radioactivity on site. Specifically, Entergy did not take action to reduce residual radioactive waste from the site in a timely manner over 14 years for areas in the Radwaste building. Entergy entered this issue into the CAP as CR-2015-5745 with actions to characterize and evaluate the adverse conditions identified by the inspector. The finding was more than minor because it is associated with the program and process attribute of the Public Radiation Safety cornerstone and affected the cornerstone objective to ensure the licensees ability to prevent inadvertent release and/or loss of control of licensed material to an unrestricted area. In accordance with IMC 0609, Appendix D, Public Radiation Safety Significance Determination Process, the finding was determined to be of very low safety significance (Green) because Entergy had an issue involving radioactive material control, but did not involve: (1) transportation; or (2) public exposure in excess of 0.005 Rem. The finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, in that Entergy did not adequately address the radioactive waste in a 14 year time period. |
| 05000293/FIN-2015002-02 | 2015Q2 | Pilgrim | Inadequate Operability Determination for the B EDG Results in TS Violation | 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, when Entergy staff performed an inadequate operability determination that assessed the X-107B emergency diesel generator (EDG) following cylinder head leakage indications during pre-start checks for a planned monthly operability run. Specifically, after engine coolant had been observed spraying from one of the open cylinder test cocks during X-107B EDG pre-start checks, operators determined that the EDG remained operable because the volume of leakage that had been observed would not have precluded a successful start of the engine. Operators did not consider that potential sources of leakage, such as a crack in the cylinder or cylinder head, could reasonably worsen during operation, such that the engine would not be able to complete its 30-day mission time, and therefore should be declared inoperable. Entergys immediate corrective actions included replacement of the X-107B EDG 9L cylinder head and sending out the damaged cylinder head for analysis by a vendor. The completion of the analysis by the vendor is being tracked by CR-2015-2109. The finding was more than minor because it was associated with the equipment 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, Entergy staff inadequately determined that the X-107B EDG was operable, which resulted in the operability of the X-107A EDG not being verified, either through determination that it was not inoperable due to a common cause failure or performing TS SR 4.5.F.1 in its entirety. This finding was evaluated 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 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 safety function, did not represent actual loss of a safety function of a single train for greater than its TS allowed outage time, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. This finding had a cross-cutting aspect in the area of Human Performance, Conservative Bias, because Entergy staff did not use decision making practices that emphasized prudent choices over those that are simply allowed. Specifically, Entergy staffs operability determination for the X-107B EDG was based on the conclusion that the as found condition would not have caused the engine to be inoperable because it would not have created a hydraulic lock; they did not consider that the condition would likely worsen during EDG operation, nor did their operability determination consider EDG mission time |
| 05000293/FIN-2015002-01 | 2015Q2 | Pilgrim | Ineffective Corrective Actions leads to Loss of Decay Heat Removal | Green. A self-revealing Green finding was identified when residual heat removal (RHR) pump B experienced cavitation during refueling and maintenance outage (RFO) 20 that was a result of inadequate corrective actions associated with equipment used to determine flow rate. Specifically, prior to placing augmented fuel pool cooling (AFPC) mode in service on April 26, 2015, Entergy did not ensure that the temporary flow transmitter was properly setup and calibrated because corrective actions from 2011 were not adequate to ensure proper setup in the future. As a result, when operators went to raise flow in accordance with their procedural requirement, RHR pump B experienced cavitation and operators secured the pump because the flow transmitter was inaccurately reading low. Entergys immediate corrective actions included entering the issue into the corrective action program (CAP) as condition report (CR)-2015-3724, re-calibrating and setting up the ultrasonic flow meter, and establishing a second ultrasonic flow meter to ensure proper flow. Inspectors performed a walkdown to ensure proper operation of the ultrasonic flow meters, and confirmed similar readings between the two flow meters on April 27, 2015. 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 events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the B RHR pump was secured from AFPC mode 2 on April 26, 2015 when the installed ultrasonic flow meter did not read properly, leading to operation of the B RHR pump outside of flow limits specified in procedure 2.2.85.2 and cavitation of the pump. This finding was evaluated in accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2, Section C.6 of IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, the inspectors determined that this finding is of very low safety significance (Green) because while the performance deficiency resulted in the B RHR pump being secured due to cavitation, it did occur when the refuel canal/cavity was flooded and did not increase the likelihood of a fire or internal/external flood that could cause an shutdown initiating event. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because Entergy staff did not thoroughly evaluate the issues associated with the ultrasonic flow meter in 2011 and 2013 to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, Entergys corrective action process did not thoroughly evaluate and develop appropriate corrective actions for CR-2011-1847 and CR-2013-2857 to ensure the cause was addressed to prevent challenges using ultrasonic flow meters during AFPC for both mode one and mode two. |
| 05000336/FIN-2015007-03 | 2015Q2 | Millstone | Inadequate Evaluation of Circuit Breaker Interrupting Capability | The team identified a finding of very low safety significance (Green) involving a non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, in that Dominion did not correctly evaluate the capability of 4.16 kV breakers to function properly during 3-phase bolted fault design condition. The team reviewed Millstone Unit 2 electrical distribution system analysis calculation (MP2- ENG-ETAP-04014E2), which evaluated adequacy of the circuit breakers for their interrupting rating in accordance with the Institute of Electrical and Electronics Engineers/American National Standards Institute (IEEE/ANSI) C37 series standards, and determined that Dominions shortcircuit fault current calculation did not assume the maximum plant operating voltage as a prefault voltage at the 4.16 kV bus and did not evaluate the plant configuration when emergency diesel generators (EDG) are operating in parallel with offsite power on the associated 4.16 kV emergency bus. The team determined this short-circuit fault current calculation was not in accordance with IEEE/ANSI C37 series standards and was non-conservative in some cases. Dominion entered the issue into their corrective action program and performed additional analysis to determine if the inability of the breaker to interrupt the fault current would result in the fault current affecting the other safety related bus. Dominion concluded that the other bus would not be affected. The team reviewed the analysis and determined it to be acceptable. The finding was determined to be more than minor because it was associated with the Mitigating Systems cornerstone Design Control attribute and adversely affected the cornerstones objective and was similar to Example 3.j in Appendix E of the NRC IMC 0612. Using the NRC IMC 0609, Significance Determination Process, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to be of very low safety significance (Green). There was no crosscutting aspect assigned to the finding because it was not an indicative of current performance. |
| 05000336/FIN-2015007-01 | 2015Q2 | Millstone | Reactor Building Closed Cooling Water System Pump Oil Leakage Results in Technical Specification Inoperability | The team identified a non-cited violation (NCV) of Millstone Power Station Unit 2, Technical Specification (TS) 3.7.3.1 the reactor building component cooling water (RBCCW) system Limiting Condition of Operation (LCO) in that Dominion failed to maintain two loops of RBCCW operable. The team found that following the identification of a degraded condition for the C RBCCW pump, Dominion incorrectly concluded the loop remained operable. Specifically, the team determined that from February 4 to February 23, 2015, the RBCCW B loop was inoperable because oil leakage from the C RBCCW outboard pump bearing would have caused the complete loss of oil to the pump bearing, without operator compensatory action, before the C RBCCW train would have completed its design basis 30-day mission time. Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, Section A, Mitigating Systems, Structures or Components and Functionality, the team determined that the finding required a detailed risk evaluation due to actual loss of function of at least a single train for greater than its TS allowed outage time. The Region I Senior Reactor Analyst (SRA) identified that because the finding involved the C RBCCW pump function to run for its mission time, the only accident events adversely impacted are the large break loss of coolant accident (LLOCA) sequences. The condition was conservatively modeled assuming an exposure period of one year with the C RBCCW pump failure to run basic event set to True. The resultant change in risk was estimated at mid E-8, or very low safety significance (Green). The dominated risk sequences involve a LLOCA with the failure of the remaining RBCCW pumps due to common cause. Since the estimated risk increase was less than 1E-8, no additional evaluation of external events contribution or change in large early release frequency (LERF) was required. The team concluded that this issue has a cross-cutting aspect in the Human Performance cross-cutting area of Conservative Bias: Individuals use decision-making practices that emphasize prudent choices over those that are simply allowable. A proposed action is determined to be safe in order to proceed, rather than unsafe in order to stop. Specifically, Dominion determined that the qualitative bubbler leak rate was acceptable without evaluation against quantified operability criteria. |
| 05000293/FIN-2015002-05 | 2015Q2 | Pilgrim | Failure to Submit an LER | The inspectors identified a Severity Level IV NCV because Entergy personnel did not provide a written report to the NRC within 60 days after discovery of the event as required by 10 CFR 50.73(a)(2)(i)(B) for a condition which was prohibited by TS 3.5.E, Automatic Depressurization System (ADS). Specifically, on January 27, 2015, Pilgrim experienced a loss of offsite power and reactor scram during a winter storm. While operators performed a reactor cooldown with manual operation of safety relief valves (SRVs), the 3C SRV twice failed to open upon demand by the operations crew. Entergy staff initiated CR-PNP-2015-0561 to document SRV 3Cs failure to open, and the valve was immediately declared inoperable. The inspectors determined that the improper operation of SRV 3C was reportable in accordance with 10 CFR 50.73(a)(2)(i)(B). Entergy has captured this issue in CR-2015-6191. The inspectors determined that Entergys failure to submit an event notification in accordance with 10 CFR 50.73 within the required time was a performance deficiency that was reasonably within Entergys ability to forsee and correct, and should have been prevented. Because the issue had the potential to affect the NRCs ability to perform its regulatory function, the inspectors evaluated this performance deficiency in accordance with the traditional enforcement process. Using example 6.9.d.9 from the Enforcement Policy, the inspectors determined that the violation was a Severity Level IV (a failure of a licensee to make a report required by 10 CFR 50.72 or 10 CFR 50.73) violation. Because this violation involves the traditional enforcement process and does not have an underlying technical violation, inspectors did not assign a cross-cutting aspect to this violation in accordance with IMC 0612, Appendix B. |
| 05000336/FIN-2015007-02 | 2015Q2 | Millstone | Failure to Provide 10 CFR 50.59 Evaluation for Interim Action Associated with Implementation of Operability Determination Procedure | The team identified a Severity Level IV, non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) 50.59, Changes, Tests, and Experiments, in that Dominion failed to perform a written evaluation to provide the bases for determining whether a change to the facility required a license amendment. Specifically, the team identified that contrary to 10 CFR 50.59, Dominion failed to properly evaluate operator compensatory actions to refill an oil bubbler on the C reactor building component cooling water (RBCCW) pump that was leaking oil at a rate that would have prevented the pump from meeting its design basis 30-day mission time. The team identified that contributing to this performance deficiency was that station procedure OP-AA-102, Attachment 1, Immediate Operability Determination Guidelines, Step 7.c., associated with the evaluation of oil and coolant leakage in order to establish operability for this type of degraded condition, incorrectly instructs the Dominion staff that the use of compensatory actions is acceptable without performing a formal operability determination. In accordance with the NRC Enforcement Policy Section 6.1, the team used IMC 0609 to inform the severity of this 10 CFR 50.59 violation. Per IMC 0609, the team determined that the finding required a detailed risk evaluation due to actual loss of function of at least a single train for greater than its TS allowed outage time. The Region I SRA identified that because the finding involved the C RBCCW pump function to run for its mission time, the only accident events adversely impacted are the LLOCA sequences. The condition was conservatively modeled assuming an exposure period of one year with the C RBCCW pump failure to run basic event set to True. The resultant change in risk was estimated at mid E-8, or very low safety significance (Green). The dominated risk sequences involve a LLOCA with the failure of the remaining RBCCW pumps due to common cause. Since the estimated risk increase was less than 1E-8, no additional evaluation of external events contribution or change in LERF was required. Accordingly, per Section 6.1.d of the NRC Enforcement Policy, the severity of the violation of 10 CFR 50.59 was determined to be Severity Level IV, as it resulted in conditions evaluated as having very low safety significance (Green) by the Significant Determination Process (SDP). There is no cross-cutting aspect associated with this violation as cross-cutting aspects are not assigned to traditional enforcement evaluations. |
| 05000293/FIN-2015007-04 | 2015Q1 | Pilgrim | Failure to Follow RCIC System Manual Restart Procedure | A self-revealing Green NCV of TS 5.4.1, Procedures, was identified because the operating crew failed to implement a procedure step to open the reactor core isolation cooling (RCIC) system cooling water supply valve during a manual startup of the system. As a result, the RCIC system was operated for over 2 12 hours with no cooling water being supplied to the lubricating oil cooler or to the barometric condenser. Entergy entered the issue into the CAP as CR-PNP-2015-0566, CR-PNP-2015-0570, and CR-PNP-2015-0952 and conducted a human performance review of the Control Room operators involved with the issue. The inspectors determined that the failure to implement Procedure 5.3.35.1, Attachment 29, RCIC Injection Manual Alignment Checklist, and the Vacuum Tank Pressure Hi Alarm, C904L-F3, alarm response procedure was a performance deficiency and was reasonably within the ability of Entergy personnel to foresee and prevent. This self-revealing finding was more than minor because it was associated with the human performance attribute of the Mitigating System cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesired consequences. Specifically, on January 27, 2015, reactor operators failed to open MO-1301-62, cooling water supply valve, during a manual restart of the RCIC system in accordance with procedure 5.3.35.1, RCIC Injection Manual Alignment Checklist. Additionally, the operating crew failed to identify the valve was out of position even after the Vacuum Tank Pressure Hi Alarm, C904L-F3, was received two minutes after the system was re-started and the alarm response procedure identified Improper Valve Lineup as a probable cause. The team evaluated the finding using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The team determined this finding was not a design or qualification deficiency and was not a potential or actual loss of system or safety function, and is therefore of very low safety significance (Green). During the period when the RCIC system was operated in this condition, no temperature limits were exceeded. The inspectors noted that in the event of a RCIC system automatic start, the cooling water supply valve would have opened automatically. This finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because Entergy licensed personnel did not implement procedure 5.3.35.1, RCIC Injection Manual Alignment Checklist , to open MO-1301-62. Additionally, Entergy licensed personnel did not implement the Vacuum Tank Pressure Hi Alarm, C904L-F3, response procedure to check for an improper valve line-up. |
| 05000293/FIN-2015007-07 | 2015Q1 | Pilgrim | Failure to Report a Major Loss of Emergency Assessment Capability | An NRC-identified SL IV NCV of 10 CFR Part 50.72(b)(3)(xiii) was identified when Entergy failed to make a required event notification within eight hours for a major loss of assessment capability. Specifically, an unplanned loss occurred of all EAL instrumentation associated with Sea Water Bay level that resulted in an inability to evaluate all EALs for an abnormal water level condition. Entergy entered the issue into the CAP as CR-PNP-2015-00949. Compliance was restored on February 5, 2015, when Entergy reported the major loss of assessment capability under Event Notification (EN) 50790. The inspectors determined that Entergys failure to submit an event notification in accordance with 10 CFR 50.72 within the required time was a performance deficiency that was reasonably within Entergys ability to foresee and correct, and should have been prevented. Since the failure to submit a required event report impacts the regulatory process, the violation was evaluated using Section 2.2.4 of the NRCs Enforcement Policy, dated July 9, 2013, instead of the SDP. Using the example listed in Section 6.9.d.9, A licensee fails to make a report required by 10 CFR 50.72 or 10 CFR 50.73, the issue was evaluated and determined to be a SL IV violation. The inspectors reviewed the condition for reactor oversight process significance. Because this NRC-identified violation involves the traditional enforcement process and does not have an underlying technical violation that would be considered more-than-minor, the inspectors did not assign a cross-cutting aspect to this violation in accordance with IMC 0612. |
| 05000293/FIN-2015007-05 | 2015Q1 | Pilgrim | Failure to Identify Condition Adverse to Quality Associated with CS Discharge Header Voiding | The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, because PNPS staff failed to identify and correct conditions adverse to quality associated with the partial voiding of the A core spray (CS) discharge header on January 27, 2015, following the loss of the keepfill system due to a LOOP. PNPS entered the issue into the CAP as CR-PNP-2015-01406 and planned procedural changes that would provide guidance to operate the affected pumps in order to prevent pump discharge piping from voiding if keepfill pressure is lost. The failure to identify, evaluate, and correct the A CS discharge header partial voiding following loss of keepfill on January 27, 2015, is a performance deficiency that was within Entergys ability to foresee and correct. Because the issue was not entered into the CAP, the condition was neither evaluated nor was corrective action taken or planned. This NRCidentified issue is more than minor because it is associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, to IMC 0609, Significance Determination Process. This finding was determined to be of very low The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, because PNPS staff failed to identify and correct conditions adverse to quality associated with the partial voiding of the A core spray (CS) discharge header on January 27, 2015, following the loss of the keepfill system due to a LOOP. PNPS entered the issue into the CAP as CR-PNP-2015-01406 and planned procedural changes that would provide guidance to operate the affected pumps in order to prevent pump discharge piping from voiding if keepfill pressure is lost. The failure to identify, evaluate, and correct the A CS discharge header partial voiding following loss of keepfill on January 27, 2015, is a performance deficiency that was within Entergys ability to foresee and correct. Because the issue was not entered into the CAP, the condition was neither evaluated nor was corrective action taken or planned. This NRCidentified issue is more than minor because it is associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using IMC 0609, Appendix A,The Significance Determination Process for Findings At-Power, to IMC 0609, Significance Determination Process. This finding was determined to be of very low. |
| 05000293/FIN-2015007-06 | 2015Q1 | Pilgrim | Failure to Implement Compensatory Measures for Out-of-Service EAL Instrumentation | The inspectors identified a Green NCV of 10 CFR 50.54(q)(2) for failing to follow and maintain an emergency plan that meets the requirements of planning standards 10 CFR 50.47(b) and Appendix E. Specifically, on January 27, 2015, following a loss of instrument air, the indications in the Control Room for Sea Water Bay level were lost, and Entergy did not implement compensatory measures, as directed by an Emergency Plan Implementing Procedure, to determine whether a Sea Water Bay level emergency action level (EAL) threshold had been exceeded. Entergy entered this issue into the CAP as CR-PNP-2015- 00948 and initiated corrective actions to identify alternative means for assessing this EAL in the event of a loss of Sea Water Bay level instruments. The inspectors determined that Entergys failure to implement compensatory measures for out-of-service EAL instrumentation was a performance deficiency that was within Entergys ability to foresee and correct and should have been prevented. Specifically, Entergy did not implement the compensatory measure listed in Attachment 9.2 of EP-IP-100.1, Emergency Action Levels, Revision 10. The inspectors determined that following a loss of instrument air, the indications for Sea Water Bay level EAL were lost, rendering those EALs ineffective such that Entergy was not able to determine whether a Sea Water Bay level EAL threshold had been exceeded and to declare an emergency based on the Sea Water Bay level. This NRC-identified performance deficiency was more than minor because it was associated with the emergency response organization performance (program elements not meeting 50.47(b) planning standards) attribute of the Emergency Preparedness cornerstone and affected the cornerstone objective of ensuring that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, the out-of-service Sea Water Bay level instrumentation could have led to an emergency not being declared in a timely manner. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012. The attachment instructs the inspectors to utilize IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, issued September 23, 2014, when the finding is in the licensees Emergency Preparedness cornerstone. The inspectors determined the finding was associated with risk significant planning standard 10 CFR 50.47(b)(4), Emergency Classification System, and corresponded to the following Green Finding example in Table 5.4-1: an EAL has been rendered ineffective such that any Alert or Unusual Event would not be declared, or declared in a degraded manner for a particular off-normal event. Therefore, using Figure 5.4-1, Significance Determination for Ineffective EALs and Overclassification, and the example in Table 5.4-1, the inspectors determined the finding was of very low safety significance (Green). The finding had a cross-cutting aspect in the area of Human Performance, Documentation, because Entergy did not maintain complete and accurate documentation. Specifically, compensatory measures associated with out-of-service EAL instrumentation are not governed by comprehensive and high-quality programs, processes, and procedures. |
| 05000293/FIN-2015007-01 | 2015Q1 | Pilgrim | Inadequate Past Operability Assessment of C Safety Relief Valve | The team identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when Entergy staff performed an inadequate past operability determination that assessed performance of the C safety/relief valve (SRV), which did not open as expected when called upon to function. Specifically, following the January 27, 2015 reactor scram, operators placed an open demand for the C SRV twice during post-scram recovery operations, but the valve did not respond as expected and did not perform its pressure reduction function on both occasions. Entergys subsequent past operability assessment for the valves operation incorrectly concluded that the valve was fully capable of performing its required functions during its installed service. In response to the teams past operability concerns, Entergy subsequently re-evaluated the past operability of C SRV and concluded that it was inoperable and placed the issue into the corrective action program (CAP) as CR-PNP-2015- 02051. The team determined the failure to adequately assess past operability of the C SRV was a performance deficiency that was reasonably within Entergys ability to foresee and correct. This NRC-identified performance deficiency is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent core damage. The team evaluated the finding using IMC 0609, Appendix 0609.04, Initial Characterization of Findings, which directed the use of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. Using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, the team determined this finding was not a design or qualification deficiency and was not a potential or actual loss of system or safety function, and was therefore of very low safety significance (Green). The finding had a cross-cutting aspect in Human Performance, Conservative Bias, because Entergy did not use decision making practices that emphasized prudent choices over those that are simply allowable. Specifically, Entergy did not appropriately evaluate unexpected and unsatisfactory performance of the C SRV in consideration of the entire pressure range that the SRV, including its automatic depressurization system (ADS) function, was required to be operable. |
| 05000293/FIN-2015007-03 | 2015Q1 | Pilgrim | Inadequate Loss of Instrument Air Abnormal Operating Procedure | A self-revealing Green NCV of TS 5.4.1, Procedures, was identified because Entergy failed to include appropriate operator actions to both recognize the effects of and recover systems and components important to safety within Procedure 5.3.8, Loss of Instrument Air, abnormal operating procedure. Entergy entered this issue into the CAP as PNP-CR-2015 0888 and issued a revision to Procedure 5.3.8 to provide additional guidance to operators during a loss of instrument air. The inspectors determined that the level of detail in Procedure 5.3.8, Loss of Instrument Air, Revision 39, was inadequate to provide appropriate operator guidance to identify and mitigate key events of January 27, 2015. This self-revealing performance deficiency was reasonably within the ability of Entergy personnel to foresee and the issue should have been prevented. The finding was more than minor because it was associated with the procedure quality attribute of the Mitigating System cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesired consequences. The lack of adequate instructions in the procedure adversely affected several operator actions and plant equipment on January 27, 2015, during the LOOP and loss of instrument air. The team evaluated the finding using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The team determined this finding was of very low safety significance (Green) because it was not a design or qualification deficiency, did not result in a loss of function of a TS required system, and did not represent an actual loss of function of one or more non-TS trains of equipment designated as a high safety-significant system. This finding had a cross-cutting aspect in the area of Human Performance, Resources, because Entergy leaders did not ensure that personnel, equipment, procedures, and other resources were available and adequate to support nuclear safety. |
| 05000293/FIN-2015007-02 | 2015Q1 | Pilgrim | Failure to Identify, Evaluate, and Correct A SRV Failure to Open Upon Manual Actuation | A self-revealing preliminary White finding and AV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, and Technical Specification (TS) 3.5.E, Automatic Depressurization System, was identified for the failure to identify, evaluate, and correct a significant condition adverse to quality associated with the A SRV. Specifically, Entergy failed to identify, evaluate, and correct the A SRVs failure to open upon manual actuation during a plant cooldown on February 9, 2013. In addition, the failure to take actions to preclude repetition resulted in the C SRV failing to open due to a similar cause following the January 27, 2015, LOOP event. Entergy entered this issue in to the CAP as CR-PNP-2015-01983, CR-PNP-2015-00561, and CR-PNP-2015-01520. Immediate corrective actions included replacing the A and C SRVs and completing a detailed operability analysis of the installed SRVs which concluded that a reasonable assurance of operability existed. Entergys failure to identify, evaluate, and correct the condition of the A SRVs failure to open upon manual actuation during a plant cooldown on February 9, 2013, was a performance deficiency. In addition, the failure to take actions to preclude repetition resulted in the C SRV failing to open due to a similar cause following the January 27, 2015 LOOP event. The self-revealing finding was within Entergys ability to foresee and correct because indications were available to determine that the A SRV valve did not open upon manual actuation. This was discovered as a result of an extent of condition review of the C SRV failing to open upon manual actuation following the January 27, 2015 LOOP event. This performance deficiency is more than minor because it could reasonably be viewed as a precursor to a significant event if two of the four SRVs failed to open when demanded to depressurize the reactor, following the failure of high pressure injection systems or torus cooling, to allow low pressure injection systems to maintain reactor coolant system inventory following certain initiating events. In addition, it is associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors screened this issue for safety significance in accordance with IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, issued June 19, 2012. The screening determined that a detailed risk evaluation was required because it was assumed that for a year period, two of the four SRVs were in a degraded state such that they potentially would not have functioned to open at some pressure lower than rated pressure and would not fulfill their safety function for greater than the TS allowed outage time. Specifically, the assumptions of failures to open were based on: a failed actual opening demand at 200 psig reactor pressure on January 27, 2015, for the C SRV; examination of the valve internals at the testing vendor (National Technical Systems); and a previous failed actual opening demand at 114 psig reactor pressure on February 9, 2013, for the A SRV. The staff determined that there wasnt an existing SDP risk tool that is suitable to assess the significance of this finding with high confidence, mainly because of the uncertainties associated with: the degradation mechanism and its rate; the range of reactor pressure at which the degraded valves could be assumed to fully function; any potential benefit from an SRV lifting at rated pressure, such that the degradation would be less likely to occur and, therefore, prevent a subsequent failure at low pressure in the near-term; the time based nature of plant transient response relative to when high pressure injection sources fail and the associated impact of reduced decay heat on the SRV depressurization success criteria; and the ability to credit other high pressure sources of water. Based on the considerations above, the risk evaluation was performed using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, issued April 12, 2012. The NRC made a preliminary determination that the finding was of low to moderate safety significance (White) based on quantitative and qualitative evaluations. The detailed risk evaluation is contained in Attachment 4 to this report. This finding does not present a current safety concern because the A and C SRVs were replaced during the outage following the January 27, 2015 LOOP and reactor trip event. Also, Entergy performed a detailed operability analysis of the installed SRVs which concluded that a reasonable assurance of operability existed. This finding had a cross-cutting aspect in 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 staff did not thoroughly evaluate the operation of the A SRV during the February 9, 2015 plant cooldown and should have reasonably identified that the A SRV did not open upon three manual actuation demands. |
| 05000293/FIN-2015007-08 | 2015Q1 | Pilgrim | Inadequate Testing of the Diesel-Driven Air Compressor | A self-revealing Green finding was identified for Entergys failure to verify that the diesel-driven air compressor (K-117) was available for service prior to the January 27, 2015 winter storm. Specifically, although K-117 was tested prior to the winter storm, the test methodology did not reveal that the capacity of the starting battery was inadequate. The failure to verify that the diesel-driven air compressor (K-117) was available for service prior to the January 27, 2015 winter storm is a performance deficiency that was within Entergys ability to foresee and correct. This resulted in a loss of instrument air during the plant trip which complicated the event response. Entergy entered the issue into the corrective action program (CAP) as condition report (CR)-PNP-2015-00559 and initiated actions to supply instrument air with a temporary air compressor. Entergy also revised the operability test for K-117 air compressor to remove the alternating current (AC) power source prior to starting the air compressor. This self-revealing issue was more than minor because it is associated with the procedure quality and design control attributes of the Initiating Events cornerstone and adversely impacted 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, failure of K-117 resulted in loss of instrument air, which adversely impacted the plant response during the January 27, 2015 winter storm. Additionally, this issue is also associated with the procedure quality and design control attributes of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating event to prevent undesirable consequences. The inspectors screened the issue under the Initiating Events cornerstone using Attachment 4 and Exhibit 1 of Appendix A to IMC 0609, Significance Determination Process, because that cornerstone was determined to be more impacted by the finding than the Mitigating Systems cornerstone. The inspectors concluded that a detailed risk evaluation would be required because the finding involved the complete loss of a support system (instrument air) that contributes to the likelihood of an initiating event and affects mitigation equipment. A senior reactor analyst performed a detailed risk evaluation of this issue. The NRC model for PNPS was adjusted to account for a loss of the instrument air compressor on a LOOP. The change in core damage frequency was very low. A review of the dominant accident sequences indicated the contribution from a large early release and from external risk contributors to be very small. Therefore, the issue was determined to be of very low risk significance (Green). The finding had a cross-cutting aspect in the area of Human Performance, Design Margins, because Entergy failed to ensure that the K-117 battery was designed with adequate margin. This finding is reflective of current performance because the inadequate design margin of the battery should have been discovered through proper testing. |
| 05000387/FIN-2014005-01 | 2014Q4 | Susquehanna | Risk Management Actions Not Implemented | The inspectors identified a Green NCV of Title 10 Code of Federal Regulations (CFR) 50.65(a)(4) due to multiple examples of not assessing and managing the increase in risk from online maintenance activities. Specifically, on November 12, 2014, a risk assessment did not identify a Yellow online risk condition during a residual heat removal system (RHR) outage. Additionally, the inspectors identified multiple examples where PPL did not implement the procedural requirements of OI-013-002, Fire Risk Management, NDAP-QA-1902, Integrated Risk Management, and NDAP-QA-0340, Protected Equipment Program such that adequate risk mitigation actions were performed. Immediate corrective actions were taken and PPL documented the issues in condition report (CR) 2014-35235 and 2014-35270. The inspectors determined the performance deficiency (PD) was more than minor because it adversely impacted the protection against external factors attribute of the Mitigating Systems cornerstone objective to ensure the capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors evaluated the finding using IMC 0612 Appendix K, Maintenance Risk Assessment and Risk Management SDP. The inspectors and the Region I Senior Risk Analyst (SRA) used Appendix K, Flowchart 2, Assessment of Risk Management Actions (RMAs), and determined that not implementing the appropriate RMAs was of very low safety significance (Green). The basis for this determination was that the short duration of the actual planned maintenance activities (62 hours and 40.5 hours) associated with the RHR Train B unavailability results in a mid E-9 calculated incremental core damage probability (ICDP), using the Susquehanna Unit 2 standardized plant analysis risk (SPAR) Model, Revision 8.21, and Systems Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE) 8. In accordance with Appendix K guidance, doubling the estimated ICDP value to reflect not implementing RMAs is a reasonable approximation of the increased risk. The resultant low E-8 ICDP deficit remains below the ICDP E-6 deficit Green-White threshold and screens this PD to Green. The finding was determined to have a cross-cutting aspect in the area of Human Performance, Work Management, in that, PPL did not control and execute activities, consistent with nuclear safety, by managing risk commensurate to the work and the need for coordination with different groups or job activities. Specifically, PPL did not recognize an elevated risk category and incorporate all RMAs into its work activities (H.5). |
| 05000387/FIN-2014005-04 | 2014Q4 | Susquehanna | EPA Breaker Under Frequency Setpoint Drift | The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, for PPL not establishing design control measures that provide for verifying or checking the adequacy of design and translating the design basis requirements into allowable values and trip set points. Specifically, PPL did not establish measures to assure the under frequency trip set point on the electrical protection assemblies (EPA) for the reactor protection system (RPS) were correctly translated into design specifications. PPL took immediate corrective actions to perform calibration of all EPA under frequency setpoints and document the condition under CR 2014-28492 and 2014-37665. The PD was determined to be greater than minor because it was associated with the Design Control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the capability of the system that respond to initiating events to prevent undesirable consequences (i.e., core damage). The item is similar to example 3.j in NRC IMC 0612, Appendix E, Examples of Minor Issues. This example states, in part, that it is not minor if the engineering calculation error results in a condition where there is now reasonable doubt on the operability of a system or component. The inspectors evaluated the finding in accordance with NRC IMC 0609, Attachment 4, "Initial Characterization of Findings," Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, and determined it affected the Reactivity Control Systems Degraded subsection of the Mitigating Systems cornerstone. Per IMC 0609, Appendix A, SDP for Findings at Power, Exhibit 2, Mitigating Systems Screening Questions, sub-paragraph C, the inspectors and a Region 1 SRA determined that a detailed risk evaluation was needed to assess the safety significance of this finding. Based upon the detailed risk evaluation, this finding was determined to be Green. The finding was determined to have a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, in that PPL did not thoroughly evaluate issues to ensure resolutions address causes commensurate with their safety significance. Specifically, PPL did not thoroughly investigate and evaluate the causes of EPA under frequency set point drift outside the technical specification (TS) allowable values after three EPAs under frequency trip set points drifted below the TS allowable value in 2013 (P.2). |
| 05000387/FIN-2014005-05 | 2014Q4 | Susquehanna | Licensee-Identified Violation | Multiple Inoperable Main Steam Safety Relief Valves On May 6, 2013, PPL determined that three main steam SRVs did not meet the setpoint criteria of +3%/-5% set forth in TS 3.4.3. PPL reported this condition under LER 05000388/2013-002. PPL determined that this had resulted in a condition prohibited by TS. Specifically, the LCO 3.4.3 states the safety function of 14 SRVs shall be operable while in Mode 1, 2, and 3. If LCO 3.4.3 is not met, action A.1 requires the reactor to be placed in mode 3 within 12 hours and mode 4 in 36 hours. With three of the sixteen main steam SRVs inoperable due to setpoints less than the -5% criteria, LCO 3.4.3 was not met. Contrary to the above, PPL had not recognized the failure of the main steam SRV setpoint criteria until removed and tested during the Unit 2 Refueling and Inspection Outage in May 2013 and, therefore had not taken the required action. Traditional enforcement applies in accordance with IMC 0612, sections 0612-09 and 0612-13 and Enforcement Policy section 2.2.4.d, because the inspectors did not identify an associated PD. Specifically, the inspectors determined that the failure of main steam SRV setpoint criteria would not have been readily apparent. This issue was considered to be an SL IV violation of TS 3.4.3 in accordance with Enforcement Policy section 6.1.d. In addition, IMC 0612, Appendix B, Figures 1 and 2, Issue Screening, were referenced in documenting this SL IV licensee-identified NCV. There was no actual safety consequence and although not considered operable for design conditions the three SRVs would have relieved pressure before exceeding +3 percent. The SRV safety function, described in UFSAR 5.2.2.1.1, to prevent over-pressurization of the reactor coolant pressure boundary, was not adversely impacted. This Severity Level IV licensee-identified NCV was entered into PPLs CAP as CR-1700379. |
| 05000387/FIN-2014005-06 | 2014Q4 | Susquehanna | Licensee-Identified Violation | Secondary Containment Door Found Ajar On February 12, 2014, PPL identified a secondary containment door (Door 612) between the HVAC room and central railroad bay wedged open by a door sign. In order for secondary containment to be operable in the as-found mode of operation, Door 612 had to be secured. PPL immediately secured the door, entered the condition into their CAP (2014-04709), and reported the condition under LER 50-387; 388/2014-002. Contrary to TS 5.4.1a, PPL did not secure the secondary containment door and maintain system operability in accordance with OP-134-002, RB HVAC Zones 1 and 3 after realignment of the secondary containment. The finding was more than minor because it adversely impacted the barrier performance attribute of barrier integrity and was determined to be of very low safety significance (Green) in accordance with IMC 0609, Appendix A, since the finding only represented a degradation of the radiological barrier function provided by standby gas treatment system. |
| 05000334/FIN-2014007-01 | 2014Q4 | Beaver Valley | Security |