Semantic search

Jump to navigation Jump to search
 QuarterSiteTitleDescription
05000352/FIN-2018002-012018Q2LimerickFailure to Conduct Adequate Radiation Surveys and Evaluate Potential Radiological HazardsA self-revealing Green finding and associated NCV of 10 CFR 20.1501, Surveys and Monitoring: General, was identified when Exelon failed to perform adequate loose surface contamination surveys of the Unit 1 RWCU isolation valve room prior to authorizing work to hang shadow shielding near the HV-051-1F017A valve, and also during the conduct of the work itself. Exelon also did not identify very high levels of loose surface contamination on overhead piping and structures which surrounded the work area. This failure resulted in unplanned internal radiation exposures to three personnel, including an RPT who was assigned to monitor the radiological aspects of the work.
05000352/FIN-2018002-022018Q2LimerickUnit 1 Core Spray Pump Failed to Start Resulting in Condition Prohibited by Technical SpecificationsThe inspectors identified a Severity Level IV NCV of Unit 1 Technical Specification 3.5.1 because one core spray subsystem was inoperable from July 17, 2017, until October 5, 2017. Specifically, the Unit 1 C core spray pump did not start upon demand during testing and was declared inoperable because the pumps associated circuit breaker closing charging springs were not charged.
05000443/FIN-2017002-012017Q2SeabrookSeabrook Station Use and Application of Technical Specifications.An Unresolved Item (URI) was identified because additional NRC review and evaluation is needed to determine whether one or more performance deficiencies and non- compliances exist. The inspectors identified an issue of concern (IOC) broadly related to Sea brooks use and application of TS s limiting conditions for operability (LCO). Specifically, performance deficiencies and non- compliances appear to exist when support systems or subsystems have not met the TS definition of operability and NextEra has not entered the associated supported systems TS LCO and applied the required actions. The industry has sometimes used the term cascading to describe the impact of a support systems inoperability on supported systems. A specific example of this IOC involves an inoperable CWT, which is the seismically qualified portion of Seabrooks ultimate heat sink (UHS). The inspectors have questioned whether an inoperable CWT renders systems that it supports (PCCW, EDG s, and RHR) inoperable. Additional information is needed to determine whether one or more performance deficiencies and TS violations exist. A Task Interface Agreement has been submitted to the NRCs Office of Nuclear Reactor Regulation (NRR) to resolve the IOCs presented below regarding the correct application of Seabrooks TSs and the impact of an inoperable CWT on its supported systems. 13 Description : Technical Specification Use and Application Concern: The Seabrook TS s are based on NUREG -0452, Standard Technical Specifications for Westinghouse Pressurized Water Reactors. Seabrook TS 1.21 defines OPERABLE OPERABILITY as a system, subsystem, train, component, or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified safety function(s), and when all necessary attendant instrumentation, controls, normal or emergency electrical power, cooling (emphasis added) and seal water, lubrication and other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its specified safety function(s) are also capable of performing their related support (emphasis added) function(s). TS 3.0.2 states that noncompliance with a specification shall exist when the requirements of the LCO and associated ACTION requirements are not met within the specified time intervals, except as provided in Specification 3.0.5. If the LCO is restored prior to expiration of the specified time intervals, completion of the ACTION requirements is not required. Seabrook TS do not contain an exception to LCO 3.0.2, similar to LCO 3.0.6 in the Improved Standard Technical Specifications (ISTS) for Westinghouse Pressurized Water Reactors (NUREG -1431). The ISTS LCO 3.0.6 states, in part, when a supported system LCO is not met solely due to a support system LCO not being met, the Conditions and Required Actions associated with this supported system are not required to be entered. Only the support system LCO ACTIONS are required to be entered. This is an exception to LCO 3.0.2 for the supported system. In this event, an evaluation shall be performed in accordance with Specification 5.5.15, Safety Function Determination Program (SFDP). Background and Licensing Basis : Seabrook Station receives circulating and SW via two large tunnels that were mined a distance of over 3 miles to the Atlantic Ocean. SW is a safety -related system that provides cooling to the safety -related EDGs, PCCW, RHR, and other systems. The tunnels were lined with reinforced concrete following excavation. However, since the tunnels were not formally, seismically -qualified, a reinforced concrete mechanical draft CWT was constructed onsite as the UHS, to provide cooling water to safety -related systems following a seismic event that blocked more than 95 percent of the tunnel water flow to ensure that the requirements of General Design Criteria (GDC) -2, Design Bases for Protection Against Natural Phenomena, are met. Seabrooks conformance with GDC- 2 is described in the UFSAR Section 3.1.1.2. The design bases safety functions of the Station SW system and the UHS are described in UFSAR Sections 9.2.1.1 and 9.2.5.1, respectively. The PCCW systems conformance with GDC -44, Cooling Water, is described in UFSAR Section 3.1.4.15. Licensing Basis Amendments : On April 7, 1993, by letter NYN -93052 (ML17191A390), the licensee submitted license amendment request (LAR) 93- 02: Service Water System/Ultimate Heat Sink OPERABILITY Requirements (TAC No. M85750). The letter stated that the purpose of the LAR was to propose changes to the Seabrook TSs to redefine the requirements for an OPERABLE SW system and to consolidate the SW requirements with the requirements for the UHS. The letter continued by stating that the Seabrook TS 3/4.7.4 (in existence in 1993) required two OPERABLE SW loops with each loop having three 14 OPERABLE pumps (two (ocean) SW pumps and one cooling tower service water (CTSW) pump) when in Modes 1, 2, 3, and 4. The letter asserted that this requirement was unnecessarily restrictive since the second SW pump in each loop is not required for normal or design basis accident conditions and the associated CTSW pump provides the required redundancy during the postulated design basis event. Specifically, the letter stated, in part, The proposed changes: (1) redefine an OPERABLE SW loop as having one OPERABLE SW pump and one OPERABLE CTSW pump;... The letter continued by stating that the consolidation (of TS LCOs 3.7.4 and 3.7.5) is proposed to reduce the potential for confusion between the specifications and to control station operation in a manner consistent with the station design basis. The inspectors identified that the TS wording changes submitted by the licensee and approved by the staff did change the actions for the SW system that consists of ocean SW and CTSW subsystems and ocean and atmospheric UHS. However, given the inspectors understanding of the application of the TS, as described in the above section titled, TS Use and Application Issue of Concern, the revised TS wording does not appear to be sufficient to relieve Seabrook from entering the applicable supported systems (EDGs and PCCW) LCOs when the associated SW subsystems are rendered inoperable. By letter dated October 5, 1994, the NRC app roved Amendment No. 32 to Facility Operating License NPF -86: Primary Component Cooling Water System Operability Requirements LAR 93- 01 and Service Water System/Ultimate Heat Sink Operability Requirements - LAR 93 -02 (TAC M85491 and M85750). The approval letter (ML011800279) states, in part, that this amendment revises the Appendix A TSs relating to the operability requirements for the SW system and the UHS. The safety evaluation report (SER) states, in part, because the tunnels between the Atlantic Ocean and the pump house are not designed to seismic Category I requirements, a seismic Category I CWT is provided to protect against their failure due to a seismic event. Therefore, to meet the design basis for the SW system , each loop must have an operable SW pump and an operable CTSW pump. In addition, the SER states, in part, that the proposed changes to TS 3/4.7.4 reflect the design basis of the SW system in that with two operable loops, each having one operable SW pump and one operable CTSW pump (given each pump's UHS is operable), the system is capable of performing its safety function for all design basis events given the worst case single active failure, including the failure of either EDG. The staff also concludes that the consolidation of the SW system (TS 3.7.4) and UHS (TS 3.7.5) specifications to one TS LCO (3.7.4) was acceptable and necessary to achieve and maintain clarity, within the specifications, of the overall requirements for system operability. The inspectors noted that the LAR and SER statements do not appear to coincide with the language in the approved Amendment No. 32, in that, the revised TS language identifies that the SW system is comprised of two subsystems with the ocean SW subsystem treated separately from CTSW subsystem. The inspectors also noted the addition of an allowed outage time (AOT) of 24 hours for two inoperable ocean SW pumps, and 72 hours for the CWT or two inoperable CTSW pumps. The inspectors noted that the LAR did not appear to identify or acknowledge that the licensing bases for Seabrook requires the CWT basin and one CTSW pump for the SW system to withstand the effects of natural phenomena such as an earthquake, without the loss of capability to perform their safety functions. Additionally, the LAR did not appear to identify or acknowledge that the licensing bases for Seabrook requires ocean SW to withstand the effects of natural phenomena such as tornadoes, without the loss of capability to perform their safety functions. Although these are low probability e vents, in a deterministic 15 licensing regime, the inspectors determined that consistent with the SER, and as detailed specifically by the licensee in the April 1993 LAR, an operable SW system should include two operable loops, with each having one operable ocean SW pump and one operable CTSW pump (given each pump's UHS is operable), such that the system is capable of performing its safety function for all design basis events, given the worst case single active failure, including the failure of either EDG. Specific Examples of the Concern : During the spring 2017 refueling outage, NextEra submitted a one -time LAR (ML17094A764) dated April 4, 2017, regarding the application of the CWT TS. Subsequently, the inspectors reviewed the records of Seabrooks CWT repair activities and OOS times since 2015 and monitored NextEras outage activities. During the review of historical records, the inspectors identified several examples of what could be interpreted as TS inoperability for PCCW and the ED Gs due to an inoperable CWT (TS 3.7.4.b) in Modes 1, 2, 3, and 4. Also, in Modes 5 and 6 during OR18, potential examples of what could be interpreted as TS inoperability were noted for the EDGs and the two RHR loops due to a non -functional CWT. It is important to note that the issue of concern associated with these examples would be based on a conclusion that the SW system / UHS LCO (3.7.4) provides a cooling water support function for both PCCW and EDG, in accordance with the TS definition (1.21) of OPERABILITY, in that the CWT is a necessary component of an OPERABLE SW / UHS due to its seismic qualification. Since the Seabrook TS do not contain an exception to LCO 3.0.2 similar to ISTS LCO 3.0.6 (NUREG 1431, Revision 4), the inspectors position is that the SSCs supported by the UHS (EDGs, PCCW and RHR) could be interpreted as inoperable due to the inoperable UHS. If it is assumed that an inoperable CWT train, a TS support system train, also renders the associated trains of its supported systems inoperable, the inspectors identified instances in the last 3 years where one or more trains of CWT SW inoperability may have exceeded the most limiting TS Action requirements for the associated supported systems. In these instances, NextEra did not enter the associated TS LCOs, and did not perform the applicable ACTIONS for the supported SSCs. Further, on the occasions that the CWT was inoperable, the supported EDG TS Surveillance Requirement 4.8.1.1.1.f(14) could not be met during the CWT maintenance. The inspectors understand that typically the application of TS Surveillance Requirement 4.0.1 would hold and LCO 3.8.1 would not be met and all applicable ACTIONS for the inoperable EDG(s) would be required to be met within the specified time intervals. Below are two specific examples of the IOC: On June 9 through June 10, 2015 (approximately 24 hours), and on October 13, 2016 (approximately 18 hours), both trains of CTSW were inoperable for CWT basin cleaning and inspection while in Mode 1. For this support system, NextEra entered the TS Action 3.7.4.c that provides an AOT of 72 hours to restore at least one train to OPERABLE status or be in hot shutdown Mode 4 within 6 hours and cold shutdown Mode 5 within the following 30 hours (108 total hours). Upon inoperability of this support system (UHS), NextEra did not declare the supported systems (PCCW and the EDGs) inoperable and enter the associated TS Actions. If determined to be applicable, TS 3.7.3 and TS 3.8.1 would have required being in Mode 3 within 7 and 8 hours, and Mode 5 within 37 and 38 hours total, respectively. On April 19, 2017, with the B EDG already inoperable, the A CWT loop was removed from service to replace portions of its CWT pump discharge piping while the 16 plant was in Mode 6 (refueling) with less than 23 feet of water above the reactor flange. LCO 3.7.4 (SW / UHS) only applies in Modes 1, 2, 3, and 4. Before the transition to Mode 6, the B EDG had been rendered inoperable for planned maintenance and testing while the plant was defueled and with no applicable operational mode. In Modes 5 and 6, LCO 3.8.1.2 requires one OPERABLE EDG and TS 3.0.4 requirements were met for entering Mode 6, in part, because of the operable A EDG. While in Mode 6, both trains of ocean SW were operable to supply cooling water. However, the inspectors have interpreted that Seabrooks current licensing basis requires each EDG to be supported by its train of seismically qualified cooling water. If it is assumed that a seismically qualified source of cooling water was required on April 19, when the A CWT loop was removed from service, its supported system, the A EDG m ay have been rendered inoperable for a period of approximately 10 hours at the same time as the B EDG was inoperable for maintenance. Additionally, the inspectors identified a second potential operability concern associated with the RHR system. Specifically, in Mode 6, LCO 3.9.8.2 requires two OPERABLE independent RHR loops while the water level is less than 23 feet above the top of the reactor vessel flange. With less than the required RHR loops OPERABLE, Action 3.9.8.2 requires immediate initiation of corrective action to return the required loops to OPERABLE status, or to establish greater than or equal to 23 feet of water above the reactor vessel flange, as soon as possible. This condition may have existed because the A CWT loop was inoperable, which could be interpreted to have resulted in the A RHR loop being inoperable for approximately 65 hours while the plant was in Mode 6 with less than 23 feet of water above the reactor flange. Issues Requiring Resolution through the T ask Interface Agreement Process : 1. Do the current Seabrook Station (50 -443) license and TSs (TS 3.0.2) require parallel/simultaneous entry into both the support system (e.g., the SW system and UHS, TS 3.7.4) and the supported systems (e.g., Electrical Power Systems, AC Sources (diesel generators), TS 3.8.1 and PCCW System, TS 3.7.3) when the definition of OPERABLE (TS 1.21) is not met for the support system? Although one example is provided, the broader question requiring an answer is whether Seabrook is required to cascade their TS. The Seabrook TS have never included nor have been amended to incorporate the non- cascading provisions of ISTS 3.0.6 or the required, accompanying SFDP. 2. Does the October 5, 1994, License Amendment No. 32 on the SW system/UHS operability requirements give NextEra the latitude to remove the entire CWT from service for 72 hours even though it is needed to support key safety -related systems with much shorter LCOs (i.e., when both trains of those systems are OOS )? 3. If Amendment No. 32 allows the flexibility to remove both loops of the CTSW or the mechanical draft CWT for 72 hours without affecting the operability of the supported systems, is the current TS language consistent with this flexibility? 4. Do the current Seabrook Station (50 -443) license and TSs (TSSR 4.8.1.1.1.f(14)) - require Seabrook to be capable of simulating each trains CWT actuation signal while the associated EDG is running at minimum accident loading when the CWT or a train of CTSW is removed from service and is inoperable for the A OT specified in TS 3.7.4 and does TS 4.0.1 need to be applied such that the failure to meet a TSSR, whether such failure is experienced during the performance of the surveillance or between 17 performances of the surveillance, shall be a failure to meet the LCO and would require taking the actions in TS 3.8.1. NextEra Position: Initially, NextEra stated its position in its April 4, 2017, one -time LAR (ML17094A764). Additional discussions with NextEra indicate that it is the licensees position that entry into the support system TS alone is sufficient to comply with Seabrook TS 3.0.2 as written even though the Seabrook TS do not include a provision similar to ISTS 3.0.6. (Note: TS 3.0.2 states that noncompliance with a specification shall exist when the requirements of the LCO and associated Action requirements are not met within the specified time intervals, except as provided in TS 3.0.5. If the LCO is restored prior to expiration of the specified time intervals, completion of the Action requirements is not required.) NextEra has since stated its position in this matter as documented in a position paper that can be found in ADAMS at ML17191A412. Specifically, NextEra asserts that the Seabrook SW system consists of two independent loops, each of which can operate with either a SW pump train or a CTSW pump train. NextEra interprets TS Amendment No. 32, approved in October 1994, as having evaluated the impact of SW TS (3.7.4) AOT for both a single and dual train unavailability of the CWT. NextEra believes that the proposed change and acceptance by the NRC staff recognized that the change was intended to redefine the requirements for both the PCCW and SW system as well as the UHS (i.e., the CWT in this case). NextEra believes that the LAR was proposed to take advantage of what the licensee believes to be a redundancy in the SW and UHS designs to provide enhanced operational flexibility. NextEras reading of the SER for the amendment can be interpreted to have stated that the NRC staff agreed with the risk -based methodology and assumptions used, and that the change in SW system unavailability due to the proposed TS amendment and the resulting increase in the total reactor core damage frequency are insignificantly small. Further, NextEra interprets the amendment to read that the staff found the consolidation of the SW system and UHS into one TS to be acceptable and necessary to achieve and maintain clarity within the specifications of the overall requirement s of system operability. (Note: NextEra remained silent regarding the need to meet the GDC requirements governing the protection against natural events for either UHS during the TS AOT.) NextEra interprets the NRCs regulations to have stated that the S ER associated with Amendment No. 32 is not actually part of the regulated licensing basis. Consequently, NextEra believes that a deterministic judgement that the current Seabrook TS was incorrectly made by the NRC via Amendment No. 32 should not be made. NextEras interpretation is that Seabrooks licensing basis remains as originally approved, notwithstanding the current regulatory approach described in Inspection Manual Chapter ( IMC ) 0326 (but not in any regulation). Therefore, NextEra interprets the c urrent TSs to allow removal of redundant portions of SW for limited time periods as recognition of the low probability for occurrence of a natural phenomenon event. Thus it is NextEras position that any new changes to the language of the TS may provide g reater clarity, but offer no substantial offsetting increase in safety. 18 Current Seabrook Administrative Controls : In accordance with Seabrooks procedure, OPMM, Operations Management Manual, Revision 107, Operations Management issued a Standing Operating Order (SOO 17- 002) to the operating department to address the concern with the use and application of TS. The order was effective on February 27, 2017, and remains effective until future resolution of the issue, and revisions to Seabrooks manuals and programs are completed, as appropriate. The order describes the correct application of TS with respect to a supporting function and its potential effect on support system operability, with the exception of the disputed issue related to the CWT- impacted LCOs. In addition, the SOO directs the operators to carefully review TS in order to determine potential operability concerns with respect to the support and supported systems as they are taken OOS . Additional corrective actions were taken to include training for the licensed operators to reinforce and ensure the correct use and application of TS in the future. Therefore, there is no immediate safety concern with respect to the issue of concern. Unresolved Item : The inspectors have coordinated with N RR through the use of the process described in NRR Office Instruction No. (COM -106), Control of Task Interface Agreements, to review this URI regarding the correct application of Seabrooks TS and the impact of an inoperable CWT on its supported systems. Pending resolution this issue is unresolved. (URI 05000443/2017002 -01, Seabrook Station Use and Application of Technical Specifications).
05000286/FIN-2016004-012016Q4Indian PointInadequate Preventive Maintenance Classification of Starting Air Relief Valve Led to FailureGreen. The inspectors identified a finding of very low safety significance because Entergy did not correctly classify relief valve DA-5-2 as a high critical component. DA-5-2 is a relief valve in the emergency diesel generator (EDG) air start system; and when it failed in service 4 due to an inadequate preventive maintenance frequency, it caused a loss of air that depressurized the air start system, rendering it inoperable. Entergy took corrective action to replace the failed relief valve and wrote CR-IP3-2016-03851 to review the classification of DA-5-2. This performance deficiency was more than minor because it was associated with the Mitigating Systems cornerstone and affected the equipment performance attribute. Specifically, the failure of the relief valve reduced the air available for starting the 32 EDG and reduced its reliability. The inspectors performed a risk screening in accordance with IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The finding was of very low safety significance (Green) because it did not represent an actual loss of function of a single train for greater than its TS allowed outage time. Specifically, the air pressure in the starting air tank was below the TS limit for less than an hour, and the allowed outage time for the starting air tank is 48 hours. The inspectors determined that there was no cross-cutting aspect associated with this finding because it is not associated with current performance. Specifically, the decision to extend the preventive maintenance frequency was made in 2010, and there had been no other failures of similar components since then that would have prompted Entergy to review the basis for that decision.
05000286/FIN-2016004-022016Q4Indian PointInadequate Operability Evaluation of Leak in Service Water Pump Discharge PipeGreen. The inspectors identified an NCV of very low safety significance of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because Entergy staff did not perform an adequate operability review under EN-OP-104, Operability, for a service water (SW) piping leak described in CR-IP3-2016-1113. Entergy based the flooding portion of the operability review on the assumption that a non-safety-related sump pump would function to prevent flooding of the room, although under accident conditions it would not have electrical power. Entergy implemented corrective actions to revise their operability evaluation and also installed a housekeeping patch that greatly reduced the leak rate. The performance deficiency was determined to be more than minor because the finding was similar to Example 3j of NRC IMC 0612, Appendix E, Examples of Minor Issues, in that incorrect assumptions of the ability of the Zurn pit sump pump to remove the water resulted in reasonable doubt regarding operability and warranted additional evaluation. This issue impacts the protection against the external factors attribute of the Mitigating Systems cornerstone and impacts its objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. Specifically, Entergy did not properly evaluate the operability impacts of an increase in the leak rate from a preexisting SW leak in the Zurn strainer pit and, therefore, did not implement compensatory measures to prevent internal flooding in the event the installed, non-safety-related sump pump failed. The inspectors determined the finding could be evaluated using the Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings. Because the finding impacted the Mitigating Systems cornerstone, the inspectors screened the finding through IMC 0609 Appendix A, The Significance Determination Process for Findings At-Power, using Exhibit 2, Mitigating Systems Screening Questions. The finding required a detailed risk evaluation because it represented the potential loss of the entire SW system. A detailed risk assessment was conducted assuming that a loss of offsite power (LOOP) could challenge the functionality of the SW system due to flooding impacts on the system strainers. The resulting change in core damage frequency was estimated to be in the mid E-6 range, Green. The inspectors concluded this finding had a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because Entergy did not recognize and 5 plan for the possibility of latent issues and inherent risk. Entergy had experienced numerous SW system leaks that remained small and did not plan for the possibility that this one would increase. Once the leak had increased significantly, Entergy did not appropriately revise the operability determination to reflect the changed circumstances and take appropriate compensatory measures to promptly restore operability. (H.12 Avoid Complacency)
05000286/FIN-2016004-032016Q4Indian PointFailure to Provide Indication of a Bypassed RPS Channel During TestingGreen. The inspectors identified a finding of very low safety significance when Entergy conducted testing on the Unit 3 reactor protection system (RPS) that was contrary to the guidance in IEEE standard 279-1968, a standard to which Indian Point Unit 3 was committed. Specifically, Entergy made temporary changes to their Unit 3 reactor coolant temperature channel functional test procedures, pressurizer pressure loop functional test procedures, and nuclear power range channel axial offset calibration procedures to use jumpers to bypass RPS trip functions, without meeting the requirement to have continuous indication in the control room when a part of RPS is bypassed for any purpose. Entergy closed the temporary modification and returned to testing without using jumpers to bypass the tested channel. The inspectors determined the finding was more than minor because this finding was associated with the procedure quality attribute of the Mitigating Systems cornerstone and affected its objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the new test method reduced the reliability of the RPS tripping the unit under conditions requiring an overtemperature delta temperature (OTDT) trip. The inspectors evaluated this finding using IMC 0609, Attachment 4, Initial Characterization of Findings. The inspectors determined that the finding affected the Mitigating Systems cornerstone and evaluated the finding using Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The finding is of very low safety significance (Green) because it did not affect both the RPS trip signal to initiate a reactor scram and the function of other redundant trips or diverse methods of reactor shutdown. The inspectors identified a cross-cutting aspect in the area of Human Performance, Conservative Bias, because Entergy did not determine the test method was safe in order to proceed. Specifically, Entergy staff rationalized that the use of jumpers was allowable because they were focused on completing the required surveillance testing. (H.14 Conservative Bias)
05000247/FIN-2016004-042016Q4Indian PointFailure to Follow RPS Logic Train B Actuation Logic TestGreen. A self-revealing NCV of Technical Specification (TS) 5.4.1(a), Procedures, was identified because Entergy did not follow procedure 2-PT-2M3A, Reactor Protection System Logic Train B Actuation Logic Test and Tadot, required by NRC Regulatory Guide 1.33, Appendix A, during planned testing on July 6, 2016, resulting in a Unit 2 reactor trip. Specifically, Entergy positioned key #183 in the channel B reactor logic key lock switch to the defeat position without procedural guidance and prior to commencing 2-PT-2M3A. 2-PT-2M3A requires that the reactor trip bypass breaker B be racked in when the channel B reactor protection logic key lock switch is taken to defeat to prevent a reactor trip. Entergy entered this issue into the corrective action program (CAP) as CR-IP2-2016-04320. The corrective actions include procedure enhancements, operations work challenges, and a site all hands meeting. This finding was determined to be more than minor because it is associated with the human 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, Entergy operated plant equipment without direction from procedural guidance which resulted in an unplanned reactor trip. This finding was determined to be of very low safety significance (Green) because it did not cause the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition, high energy line-breaks, internal flooding, or fire. This finding had a cross-cutting aspect in the area of Human Performance, Field Presence, because Entergy leaders did not reinforce standards and expectations with regard to procedure use and adherence. Specifically, Entergy did not have sufficient urgency for changing worker behaviors through the work observation program. (H.2 Field Presence)
05000289/FIN-2016004-012016Q4Three Mile IslandLicensee-Identified ViolationTechnical specification 3.2.12.1, "LTOP Protection", requires when the reactor vessel head is installed and indicated reactor coolant system temperature is 313F, high pressure injection pump breakers shall not be racked in unless injection valves (MU-V16A/B/C/D and MU-V217) are closed with their associated breakers open and that pressurizer level is maintained 100 inches, or restore pressurizer level to 100 inches within 1 hour. Contrary to technical specification 3.2.12.1, during reactor coolant system filling with the vessel head installed and temperature < 313F, high pressure injection pump breakers were racked in while pressurizer level was >100 inches for greater than 1 hour. The condition existed for 2 hours and 49 minutes until recognized by the operating crew when questioned by a senior reactor operator trainee, at which time the crew took immediate actions to reduce pressurizer level <100 inches within 1 hour. Additional corrective actions included crew remediation, additional main control room supervisory oversight, and procedure changes. Exelon entered this issue into the corrective action program as issue report 3949713. The inspectors determined that the finding was of very low safety significance (Green) in accordance with NRC IMC 0609, Appendix G, Shutdown Operations, Attachment 1, Exhibit 4, since the finding did not represent an inadvertent safety injection and did not render the power-operated relief valve (LTOP Protection) unavailable or degraded.
05000247/FIN-2016004-052016Q4Indian PointLicensee-Identified Violation10 CFR 55.53(e) requires, in part, that to maintain active status, a licensee shall actively perform the functions of an operator or senior operator on a minimum of seven 8-hour shifts or five 12-hour shifts per calendar quarter and that if a licensee has not been actively performing the functions of an operator or senior operator, the licensee may not resume activities authorized by a license issued except as permitted by 10 CFR 55.53(f). 10 CFR 55.53(f) requires, in part, that before resumption of licensed functions, an authorized representative of the facility licensee shall certify that: 1) the licensees qualification and status of the licensee are current and valid; and 2) that the licensee has completed a minimum of 40 hours of shift functions under the direction of an operator or senior operator as appropriate and in the position to which the individual will be assigned. Contrary to the above, between July 2, 2016, and July 5, 2016, Entergy did not properly ensure that the qualifications and status of an SRO was current and valid, regarding the SRO meeting the minimum of seven 8-hour or five 12-hour shifts per calendar quarter. Specifically, the SRO stood watch as a control room supervisor in July 2016 while having stood only four of the five required 12-hour proficiency watches in a creditable position in the prior quarter. In the prior quarter, the SRO stood watch as a shift technical advisor and field support supervisor. These watches are not creditable toward the proficiency requirement. The SRO was removed from shift and was properly reactivated as required by 10 CFR 55.53(f). This issue was entered in Entergys CAP as CR-IP2-2016-04440. Corrective actions taken included counseling of the SRO and the auditor. To prevent reoccurrence, a software fix was implemented to check the proficiency status of operators when logging into their shift. This violation was assessed using the traditional enforcement process because it involved an operator license condition that was not met, which impacts the NRCs regulatory process. Although this violation is similar to a Severity Level III example in the NRC Enforcement Policy, based on the circumstances surrounding the issue including a verification that there were no operational errors as a result of the violation, the issue was evaluated as a Severity Level IV.
05000219/FIN-2016002-012016Q2Oyster CreekInadequate Maintenance Procedure associated with Reactor Recirculation Pump SealA self-revealing NCV of Technical Specification 6.8.1, Procedures and Programs, was identified because Exelon did not adequately establish and maintain the reactor recirculation pump (RRP) reassembly maintenance procedures as required by NRC Regulatory Guide 1.33, Appendix A, Section 9, Procedures for Performing Maintenance. Specifically, the RRP reassembly procedure, 2400-SMM-3226.03, Reactor Recirculation Pump Mechanical Seal Rebuild Using CAN-2A Parts, did not provide critical dimensional checks for the locking plate and seal adjusting cap. This led to the incorrect reassembly of the D RRP. Exelon entered this issue into their corrective action program as issue report 2663436. The corrective actions included repairing the D RRP and revising RRP maintenance procedures to include critical dimensional information. This finding is more than minor because it is associated with the procedure quality attribute of the Initiating Events cornerstone and affected the objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown and power operation. Specifically, the incorrect reassembly of the D RRP created a leakage path, which led to an unexpected increase in reactor coolant system (RCS) unidentified leakage. As a result, the operators inserted a manual scram on April 30, 2016. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, and IMC 0609, Appendix A, Exhibit 1, Initiating Event Screening Questions. The inspectors determined that this finding is a transient initiator that did not contribute to both the likelihood of a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition, and therefore was of very low safety significance (Green). The inspectors determined that there was no cross-cutting aspect associated with this finding since it was not representative of current Exelon performance. Specifically, in accordance with IMC 0612, the causal factors associated with this finding occurred outside the nominal three-year period of consideration and were not considered representative of present performance.
05000219/FIN-2016001-012016Q1Oyster CreekFailure to Identify a Slower than Normal Scram Time of a Control Rod DriveThe inspectors identified an NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, because Exelon did not promptly identify and correct a condition adverse to quality. Specifically, Exelon did not identify that the scram time test result for control rod drive 18-47 was beyond the analyzed scram time, which resulted in a degraded control rod drive. Exelon entered this issue into their corrective action program. Immediate corrective actions included fully inserting the control rod drive and developing a casual analysis to determine the degraded condition. The performance deficiency is more than minor because it is associated with the configuration control attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency affected the reliability of control rod drive 18-47 to perform its safety function due to a slower than normal scram time. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings. The inspectors determined that this finding is a deficiency that affected the design or qualification of a mitigating structure, system, or component (SSC), when the SSC maintained its operability or functionality. Therefore, the inspectors determined the finding to be of very low safety significance (Green). The finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Identification, because Exelon did not identify issues completely, accurately, and in a timely manner in accordance with the program. Specifically, Exelon did not identify that the actual scram time of control rod drive 18-47 was beyond the analyzed scram time, resulting in a degraded control rod drive.
05000219/FIN-2016001-022016Q1Oyster CreekFailure to Use Respiratory Protection as Required in RWP/ALARA Plan for Drywell Head ReassemblyA self-revealing NCV of Technical Specification 6.8.1, Procedures and Programs was identified for Exelons failure to use respiratory protection, as required in the radiation work permit (RWP)/as low as reasonably achievable (ALARA) plan 14-406 for drywell head reassembly work on October 2, 2014. The radiation protection (RP) supervisor overseeing this work removed the respiratory protection requirement for this work contrary to the RWP/ALARA requirement and without engineering approval. As a result, two workers received an unplanned intake of radioactive material that resulted in unintended internal dose. Upon identification of the intake, Exelon stopped work on this task and subsequently reinstituted the respiratory protection requirements to complete the remaining work and entered this event into their corrective action program as issue report 2390111. This finding is more than minor because it is associated with the Occupational Radiation Safety cornerstone to ensure adequate protection of the worker from radiation exposure. Specifically, without the use of respiratory protection two workers received unintended internal dose. The inspectors evaluated the finding using inspection manual chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process. The inspectors determined that this finding is of very low safety significance (Green), because it did not result in an overexposure as defined by 10 CFR 20.1201, there was no substantial potential for an overexposure, and the ability to assess dose was not compromised. This finding has a cross-cutting aspect in Human Performance, Procedural Adherence, because Exelon did not follow procedures and work instructions. Specifically, RP supervision instructed the workers that respiratory protection was not required contrary to the applicable RWP/ALARA plan.
05000219/FIN-2016001-042016Q1Oyster CreekLicensee-Identified ViolationFrom 2010 to 2014, Oyster Creek made a total of four shipments of radioactive material which contained category 2 quantities of radioactive material. Oyster Creek did not implement a transportation security plan for any of these shipments, which is contrary to the requirements of 49 CFR 172, Subpart I, Safety and Security Plans. This performance deficiency adversely affected the Public Radiation Safety cornerstone attribute of Program and Process based on inadequate procedures associated with the transportation of radioactive materials. The finding was determined to be of very low safety significance (Green) because the transportation of radioactive material issue 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. This issue was documented in the Exelons corrective action program as IR 2484646. Corrective actions included contracting with a vendor to receive regular, prompt notifications of potentially applicable rule changes in the Federal Register.
05000286/FIN-2016001-032016Q1Indian PointInadequate Screening of Reactor Protection System Test Method ChangeThe inspectors identified that Entergy conducted testing on the Unit 3 RPS that was not described in the UFSAR without performing an adequate 50.59 evaluation, contrary to EN-LI-100, Process Applicability Determination. Specifically, Entergy made temporary changes to the Unit 3 reactor coolant temperature channel functional test procedures, pressurizer pressure loop functional test procedures, and nuclear power range channel axial offset calibration procedures to use jumpers to bypass RPS trip functions. As a result, the NRC opened an URI related to this concern. On October 21, 2014, Entergy implemented temporary procedure changes to three sets of reactor protection system surveillance procedures. These procedures were 3-PT-Q87A, B, and C, Channel Functional Test of Reactor Coolant Temperature Channel 411, 421, and 431; 3-PT-Q95A, B, and C, Pressurizer Pressure Loop P-455, 456, and 457 Functional Test; and 3-PT-Q109A, B, and C, Nuclear Power Range Channel N-41, 42, and 43 Axial Offset Calibrations. Entergy made the temporary procedures changes as an interim corrective action following a trip of Unit 3 on August 13, 2014, during reactor protection system surveillance testing when a spurious actuation signal occurred in the channel that was not being tested. Entergy was initially unable to identify and correct the cause of the spurious over-temperature delta temperature (OTDT) channel trip and, therefore, wanted to perform their TS required surveillances without risking another unit trip should another spurious actuation occur in the degraded channel not under test. In each case, the change was to install a jumper at the beginning of the testing to maintain the trip relay in an energized condition for the tested channel of the OTDT trip circuit thereby effectively bypassing the channel in test. Each quarterly test was performed three or four times over the course of approximately ten months. On July 1, 2015, Entergy determined that they had corrected the cause of the spurious OTDT channel trips and removed the temporary procedure changes from the controlled document system. Despite this, on August 12, 2015, Entergy performed the surveillances 3-PT-Q95A, B, and C, Pressurizer Pressure Loop P-455, 456, and 457 Functional Test, which incorporated the temporary procedure changes that had been discontinued. Operating experience has shown that human error has allowed jumpers to remain installed even after testing is over because there is no obvious indication that the channel is in bypass when a jumper is used. Indian Point is committed to IEEE Standard 279-1971, Criteria for Protective Systems for Nuclear Power Plants. Section 4.13, Indication of Bypass, requires that any channel placed in a bypass configuration for testing shall have continuous indication in the control room that the channel has been removed from service. These standards preclude the use of jumpers for routine testing. This commitment was further documented in the Safety Evaluation Report for TS Amendment 107 that approved the extension of surveillance testing intervals and approved the use of the bypass feature for testing. Although Unit 3 was not originally built with RPS bypass switches, New York Power Authority had planned to install bypass switches, which would comply with IPEEE 279-1971. Entergy terminated the WO for installation of these switches. Normally, during the course of RPS channel surveillance testing, the affected channel of the OTDT trip circuit would de-energize the trip relay. If one of the other three redundant RPS channels spuriously de-energized at the same time, the two of four signal RPS trip logic would be satisfied and Unit 3 would trip, as occurred on August 13, 2015. By putting the jumper in place, the affected channel trip relay would remain energized under all conditions, including actual conditions that would require a plant trip on OTDT. During testing, the use of the jumper did not increase the likelihood of a malfunction of an SSC over that previously evaluated in the UFSAR because Unit 3 had received a license amendment (Agencywide Documents Access and Management System (ADAMS) Accession No. ML003779650) that allowed testing a bypassed channel. However, the safety evaluation report for that license amendment stated that, The licensee further commits that only those instruments whose hardware capability does not require the lifting of leads or installing of jumpers will be routinely tested in bypass. When Unit 3 applied for the license amendment, the intent was to permanently install bypass switches that would allow bypassing a channel and would clearly indicate in the control room that a channel was bypassed. The risk of inadvertently leaving a jumper in place is greater than the risk of inadvertently leaving a channel bypassed using hardware that brings in an alarm in the control room, because the jumper can go unnoticed for a longer period of time since it does not result in clear indication in the control room. Per procedure EN-LI-100, Entergy performed a 50.59 screening review for these temporary procedure changes. In this screening, they incorrectly determined that the temporary procedure changes did not involve a test not described in the UFSAR, and as a result, did not perform a 50.59 evaluation. Although the UFSAR describes reactor protection system testing by bypassing channels, it specifically does not authorize the use of jumpers to do so. The UFSAR for Unit 3, chapter 7, states, Test procedures also allow the bistable output relays of the channel under test to be placed in the bypassed mode prior to proceeding with the analog channel test ... this may only be done for circuits whose hardware does not require the use of jumpers or lifted leads to be placed in bypass mode. Jumpering out the RPS trip relay in an RPS channel under test created an adverse condition because it removed the automatic trip signal from the RPS logic. Entergy was required to fully evaluate the adverse condition rather than authorize the change under an abbreviated 50.59 screening process. The inspectors concluded that not performing an adequate 50.59 evaluation was a performance deficiency that was reasonably within Entergys ability to foresee and correct and should have been prevented. Because Entergy was in the process of performing a retroactive 50.59 evaluation at the end of the inspection period, the inspectors were not able to evaluate if the performance deficiency was more than minor. The inspectors determined that the issues concerning the use of jumpers for RPS testing is an URI pending Entergy completion and NRC review of the 50.59 evaluation.
05000219/FIN-2016001-032016Q1Oyster CreekInadequate Instructions for the Flexible Coupling Hose Preventative Maintenance Resulting in an Inoperable Emergency Diesel GeneratorThe inspectors identified a preliminary White finding and associated apparent violation of Title 10 of the Code of Federal Regulations (CFR), Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because Exelon did not appropriately prescribe instructions or procedures for maintenance on the emergency diesel generator (EDG) No. 1 cooling water system to ensure the EDG cooling flexible coupling hose was maintained to support the EDG safety function. Specifically, Exelon did not have appropriate work instructions to replace the EDG cooling flexible coupling hoses every 12 years as specified by Exelons procedure and vendor information. As a result, the flexible coupling hose was in service for approximately 22 years and subjected to thermal degradation and aging that eventually led to the failure of EDG No. 1 during operation on January 4, 2016. As a consequence of this inappropriate work instruction issue, Exelon violated Technical Specification 3.7.C because EDG No. 1 was determined to be inoperable for greater than the technical specification allowed outage time of seven days. Exelons immediate corrective actions included entering the issue into their corrective action program (issue reports 2607247 and 2610027), replacing of the EDG No. 1 and No. 2 flexible coupling hoses, and initiating a failure analysis to determine the causes of the failed flexible coupling hose. This finding is more than minor because it is 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 (i.e., core damage). Specifically, the ruptured flexible coupling hose caused the failure of EDG No. 1 to perform its safety function. 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, this finding required a detailed risk evaluation (DRE) because EDG No. 1 was inoperable for greater than the technical specification allowed outage time. The DRE estimated the increase in core damage frequency was 7E-6, or White (low to moderate safety significance) for this finding. This finding does not have an associated cross-cutting aspect because the performance deficiency occurred in 2005 and is not reflective of present performance.
Retrieved from "https://kanterella.com/Special:Ask/-5B-5BCategory:Finding-5D-5D-20-5B-5BInspector::Mark-20Henrion-5D-5D/-3FQuarter/-3FSite/-3FTitle/-3FDescription/mainlabel%3D/order%3Ddescending/sort%3Dstart-20date/offset%3D0/format%3Dtable/searchlabel%3D-5BFindings-20List-5D"