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| Site | Quarter | Title | Description | |
|---|---|---|---|---|
| 05000313/FIN-2018003-04 | Arkansas Nuclear | 2018Q3 | Failure to Verify Safety-Related 4160 V Breaker Operability Following Maintenance Activities | The inspectors reviewed a self-revealed Green finding and associated non-cited violation of Arkansas Nuclear One, Unit 1, Technical Specification 5.4.1.a, for the licensees failure to properly preplan maintenance that can affect the performance of safety-related equipment. Specifically, the licensee failed to perform post-maintenance testing to demonstrate component operability for the train A safety-related 4160 V switchgear A-303 breaker that provides power to the swing service water pump B (P-4B) after the breaker was racked in. The breaker subsequently failed to close when attempting to start the pump. |
| 05000413/FIN-2018010-02 | Catawba | 2018Q3 | Operability of the VZ and RN Systems were not Assured | The team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control for the failure to assure that applicable regulatory requirements for the safety-related service water pump house environmental controls were correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee failed to translate the IEEE 279-1971 design basis and requirements for the environmental controls. |
| 05000440/FIN-2018003-01 | Perry | 2018Q3 | Application of ASME Code Case N5133 for the Emergency Service Water Piping Degradations | The inspectors identified an Unresolved Item concerning the Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Appendix B, and ASME Code requirements for the ESW piping systems with regards to the licensees application of ASME Code Case N5133, Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3 Piping, Section XI, Division 1. Updated Safety Analysis Report (USAR) Section 9.2.1 describes that the function of ESW system is to provide a reliable source of water to safety-related components required for normal and emergency reactor operation. USAR Table 3.21, Equipment Classification, delineates that the ESW piping system is safety-related and designed in accordance with the requirements of ASME Section III, Subsection ND (Class 3). The regulation in 10 CFR 50.55a(g) requires, in part, that Class 3 components and their supports meet the requirements of ASME Section XI of the ASME Boiler and Pressure Vessel (BPV) Code or equivalent quality standards. The ASME also publishes Code Cases, which provide alternatives to existing Code requirements. The NRC Regulatory Guide (RG) 1.147 identifies that Code Case N5133 provides acceptable alternatives to applicable parts of Section XI, provided it is used with any identified conditions or limitations. Code Case N5133, Section 2(d) requires that a flaw evaluation shall be performed to determine the conditions for flaw acceptance. Section 3 provides accepted methods for conducting the required analysis. In addition, Section 3 requires, in part, that nonplanar flaws shall be evaluated in accordance with the requirements in 3.2. Additionally, Section 5 requires that an augmented volumetric examination or physical measurement to assess degradation of the affected system shall be performed as follows: (a) From an engineering evaluation, the most susceptible locations shall be identified. A sample size of at least five of the most susceptible and accessible locations, or, if fewer than five, all susceptible and accessible locations shall be examined within 30 days of detecting the flaw. (b) When a flaw is detected, an additional sample of the same size as defined in 5(a) shall be examined. (c) This process shall be repeated within 15 days for each successive sample, until no significant flaw is detected or until 100 percent of susceptible and accessible locations have been examined. On June 13, 2018, a through-wall leakage on the 20 ESW piping was identified in CR 201805504. As a result, the licensee invoked the Code Case to evaluate this flaw and permit the degraded ESW piping system to remain in service for a limited period without repair/replacement. The licensees evaluation involved characterization of this flaw as nonplanar, and subsequently, the methodology as described in Section 3.2 of the Code Case was utilized for this nonplanar flaw. Additionally, the licensee identified the five most susceptible and accessible locations in the ESW system and performed examination in accordance with Section 5(a). From the examination of the five additional locations, another localized wall degradation was identified on the 8 ESW pipe elbow on July 10, 2018. The licensee initiated CR 201806205 to document this condition. The licensee characterized this degradation also as a nonplanar flaw, and this degradation represented approximately 80 percent wall loss from its nominal thickness. During the review of the licensee evaluation of this degraded pipe elbow, the inspectors identified that the methodology as described in Section 3.2 of the Code Case had not been utilized. Instead, the licensee elected to use an alternate methodology to evaluate and disposition for its acceptability. Furthermore, the inspectors identified that the licensee essentially redefined the term flaw in the Code Case to reflect the ASME Section XI, IWA9000 definition of the term defect. The ASME Section XI, IWA9000 defines a flaw as an imperfection or unintentional discontinuity that is detectable by nondestructive examination. It also defines a defect as a flaw (imperfection or unintentional discontinuity) of such size, shape, orientation, location, or properties as to be rejectable. With respect to the Code Case, the licensee essentially restricted the criteria for examination scope expansion only to the flaws that were rejectable; therefore, the licensee had not expanded the scope to perform examination of additional locations in accordance with Section 5(b). In essence, two items are to be further evaluated and addressed: (1) whether the use of methodology not described in the Code Case Section 3.2 was appropriate for evaluation of the nonplanar flaw on the 8 ESW pipe elbow, and (2) whether the stopping of scope expansion for examination as required by the Code Case Section 5(b) was appropriate based on the licensees redefining of the term flaw. In response to the inspectors concern, the licensee initiated CR 201808483, NRC ID: Code Case N5133 Interpretation, September 26, 2018. The licensee also plans to perform examination of five additional locations in November of 2018. This represents an item where the inspectors identified Code interpretation issues that resulted in a disagreement with the licensee. This will require additional review to determine whether a violation exists. Therefore, this issue is considered an unresolved item pending completion of inspector review and evaluation and discussion with the Office of Nuclear Reactor Regulation. Licensee Action: The licensee plans to perform examination of five additional locations in November of 2018. Corrective Action Reference: CR 201808483 |
| 05000336/FIN-2018003-01 | Millstone | 2018Q3 | Failure to Assure that Safety-Related Service Water Piping Conformed to the Procurement Documents | The inspectors identified a Green finding and associated non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion VII, Control of Purchased Material, Equipment, and Services, when the licensee failed to identify that a replacement service water pipe spool (JGD-1-25) was not in conformance with the American National Standards Institute (ANSI) B31.1 code, a condition of the purchase order, and was installed in the plant. |
| 05000247/FIN-2018003-03 | Indian Point | 2018Q3 | Containment Fan Cooler 24 Through-Wall Service Water Leak Caused by Inadequate Application of Epoxy Coating Resulting in Corrosion and a Safety System Functional Failure of Containment | A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when Entergy did not ensure that activities affecting quality were prescribed by documented instructions or procedures, of a type appropriate to the circumstances, and that these activities were accomplished in accordance with these instructions, procedures or drawings. Furthermore, Entergy did not ensure that the instructions or procedures included appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Specifically, Entergy did not ensure that the maintenance procedure for applying the internal EneconTM epoxy coating to the 24 fan cooler main cooler supply line elbow was adequate to ensure proper epoxy coating adherence, and Entergy did not adequately verify the coating adherence prior to placing the elbow in service. This resulted in a through-wall leak and a safety system functional failure of containment. |
| 05000247/FIN-2018003-02 | Indian Point | 2018Q3 | Containment Fan Coolers 21 and 24 Motor Cooler Elbow Through-Wall Leaks Due to Excessive Service Water Flow Rates and Safety System Functional Failures of Containment | A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified when Entergy did not ensure that measures were established for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of the structures, systems, and components. Specifically, in 1998, when the former license-holder for Unit 2 decided to replace the original-construction large-radius, butt-welded elbow joints in the service water motor cooler return lines from the Unit 2 FCUs with a new design (a short radius, socket-weld fitting), these elbow joints were not properly evaluated for suitability of application. The service water flow velocity through the modified FCU return piping was in excess of the vendor-allowable flow velocity limit, which resulted in the gradual erosion of the motor cooler elbow joints, eventually leading to through-wall leaks on an ASME class III piping system inside containment, leading to breaches of containment integrity and safety system functional failures. |
| 05000315/FIN-2018002-05 | Cook | 2018Q2 | Minor Violation | While there did appear to be a reduction in operational errors being made in the field while manipulating equipment (such as during clearance activities and in performing certain evolutions) the inspectors noted a trend in configuration control issues. Most of these dealt with some kind of operation department interface or coordination with another department. In one case, valves associated with feedwater heater level control were left closed following a project to replace some of the heaters, which contributed to a manual reactor trip due to high moisture-separator drain tank level when starting the plant following the Unit 2 refueling outage. Other examples were Chemistry and Operations department coordination on an non-essential service water (NESW) valve alignment which led to NESW being isolated to generator seal oil cooling during plant startup, poor coordination between Maintenance and Operations which resulted in a containment penetration being left open, a pressure gauge remaining isolated after the Projects department completed the heater drain pump replacements, and the failure to ensure that valve-closure tests were done following the feedwater heater replacements. Another identified trend was in the area of post-maintenance testing (PMT). During the refueling outage on Unit 2, both the NRC and the licensee identified instances of improper PMTs being scheduled for safety-related equipment. Inspectors identified work on an EDG fuel oil transfer pump that did not have an in-service test (IST) scheduled. The licensee identified the lack of a time response test following a motor-driven AFW pump motor replacement, was a repeat issue from the previous outage. The licensee also identified the lack of an IST following a seal replacement on a CCW pump. In each case, the issues were discovered and corrected before equipment was restored to fully operable status. In response to the trend, the licensee reviewed other work on safety-related equipment for the outage to confirm the proper PMTs would be done. No other issues were identified. Finally, early in the observation period, the inspectors noted a trend in procedure quality for maintenance activities on safety-related equipment. There were instances regarding Turbine-Driven Auxiliary Feedwater (TDAFW) pump linkages where better procedure direction could have precluded binding and governor-valve travel issues. Additionally, while replacing a TDAFW governor, a snap ring was inadvertently left out of a coupling due to insufficient procedure detail. Regarding the EDGs, the licensee discovered instructions for assembly of air start check valves did not contain the torque guidance that the vendor drawings stipulated. In response to this trend, the licensee started to perform deliberate reviews of OE before maintenance on some safety-related equipment, to verify maintenance instructions had up-to-date guidance before starting work. No violations or findings were identified by the inspectors. 12 Licensee management acknowledged the issues discussed by the inspectors. |
| 05000454/FIN-2018002-03 | Byron | 2018Q2 | Minor Violation | Minor Violation: The inspectors identified multiple instances of a failure to perform inservice testing in accordance with written procedures appropriate for the circumstances during this inspection period: 1. On March 30, 2018, the licensee performed 1BOSR 5.5.8.DO2, Test of the Diesel Oil Transfer System, and declared the 1B diesel oil transfer pump inoperable due to flow results being low out of specification. Subsequently, the licensee determined that the instrument setup was incorrect in that an incorrect value was entered into the flow meter for pipe diameter. The licensee declared the surveillance invalid and scheduled a time to re-perform the activity. Acceptable system flow rates were achieved a week later when the correct pipe diameter was used for the instrument setup. 2. On April 26, 2018, while observing the licensee perform 2BOSR 5.5.8.CS.52C, Comprehensive Inservice Testing (IST) Requirements for Containment Spray Pump 1CS01PB, the inspectors noted that the pump suction pressure and discharge pressure test gauges were not installed as described in the Precautions and Limitations section of the procedure. After the inspectors asked how the installed configuration satisfied the procedure requirement, the licensee suspended the test to obtain clarification. After some deliberation between engineers and operators attempting to identify the correct instrument location, the test data was recorded with the instruments at different locations for data gathering and comparison. The licensee verified that pump performance had sufficient margin, including the introduced error, to remain operable and available to perform its safety-related function as expected.3. On May 1, 2018, while observing the licensee perform 2BOSR 5.5.8.SX.51C, Comprehensive Inservice Testing (IST) Requirements for the Essential Service Water (SX) Pump 2SX01PA and Unit 2 SX Pumps Discharge Check Valves, the inspectors noted that operators were not taking data from the ultrasonic flow meter in accordance with the procedure. Specifically, the instrument was not set up to indicate time and flow so that an average flow could be determined as required by a Note in the procedure. Instead the operators were recording instantaneous flowrate. When the inspector asked for clarification and the operators and technicians deferred to their supervisors, the licensee suspended the test to obtain clarification. The test was performed again after the instrument was set up correctly and operators were briefed on how to obtain the correct data.Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions. Contrary to the above, for the diesel fuel oil transfer pump surveillance, 1BOSR 5.5.8.DO2, the procedure listed an incorrect pipe diameter value that was subsequently entered into the flow meter resulting in unacceptable test results; for the containment spray pump surveillance, 2BOSR 5.5.8.CS.52C, the licensee potentially introduced an unaccounted for error in the surveillance test method by not setting up test equipment in accordance with the procedure; and for the SX surveillance, 2BOSR 5.5.8.SX.51C, the licensee introduced a potential error in the surveillance test by not determining an average flow rate as discussed in the procedure Note.Screening: The failure to perform inservice testing in accordance with written procedures appropriate for the circumstances was a performance deficiencyin each of the listed 11 examples. The performance deficiency was determined to be minor in each case because the inspectors answered No to all of the more-than-minor screening questions in IMC 0612, Appendix B. The licensee generated the following issue reports (IRs) to document these issues:AR 04121539, Ultrasonic Flow Measurement Installation IssueAR 04122295, PCR (procedure change request) 1/2BOSR 5.5.8.DO1 AR 04131201, Engineering Clarification Needed on ASME Precaution AR 04133585, NRC ID: Potential Concerns With Execution of 2A SX Pump Surveillance Violation: These failures to comply with 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, constituted minor violations that are not subject to enforcement action in accordance with the NRCs Enforcement Policy |
| 05000458/FIN-2018002-02 | River Bend | 2018Q2 | Enforcement Action (EA)-18-053: Enforcement Discretion for Tornado-Generated Missile Protection Noncompliances | Title 10 CFR Part 50, Appendix A, General Design Criteria for Nuclear Power Plants, Criterion 2, Design Bases for Protection Against Natural Phenomena, states, in part, that systems, structures, and components (SSCs) important to safety shall be designed to withstand the effects of natural phenomena, such as tornadoes. Criterion 4, Environmental and Dynamic Effects Design Basis, states, in part, that SSCs important to safety shall be appropriately protected against dynamic effects including missiles that may result from events and conditions outside the nuclear power unit. Section 3.5.2, Structures, Systems, and Components to be Protected from Missiles, of the Updated Safety Analysis Report (USAR) details the structures that are designed to withstand tornado missile impact.On February 7, 2017, the NRC issued Enforcement Guidance Memorandum (EGM) 15-002, Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance, Revision 1 (ADAMS Accession Number ML16355A286). The EGM referenced a bounding generic risk analysis performed by the NRC staff that concluded that tornado missile vulnerabilities pose a low risk significance to operating nuclear plants. Because of this, the EGM described the conditions under which the NRC staff may exercise enforcement discretion for noncompliance with the current licensing basis for tornado-generated missile protection. Specifically, if the licensee could not meet the technical specification required actions within the required completion time, the EGM allows the staff to exercise enforcement discretion provided the licensee implements initial compensatory measures prior to the expiration of the time allowed by the limiting condition for operation. The compensatory actions should provide additional protection such that the likelihood of tornado missile effects are lessened. The EGM then requires the licensee to implement more comprehensive compensatory measures within approximately 60 days of issue discovery. The compensatory measures must remain in place until permanent repairs are completed, or until the NRC dispositions the non-compliance in accordance with a method acceptable to the NRC such that discretion is no longer needed. Because EGM 15-002 listed River Bend Station as a Group A plant, enforcement discretion expired on June 10, 2018. On May 10, 2018, River Bend Station submitted a request to extend the enforcement discretion period to June 10, 8 2020. On May 31, 2018, River Bend Station submitted asupplement to the May 10 request. On June 6, 2018, the NRC granted an extension to the enforcement discretion until June 10, 2020. The initial conditions of Design Basis Accident (DBA) and transient analyses in the USAR, Chapter 6 and Chapter 15, assume Engineered Safeguards Features (ESF) systems are operable. The AC, DC, and AC vital bus electrical power distribution systems are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, reactor coolant system, and containment design limits are not exceeded.The onsite standby power source for each 4.16 kV ESF bus is a dedicated emergency diesel generator (EDG). An EDG starts automatically on a loss of coolant accident signal (i.e., low reactor water level signal or high drywell pressure signal) or on an ESF bus degraded voltage or under voltage signal. In the event of a loss of preferred power, the ESF electrical loads are automatically connected to the EDGs in sufficient time to provide for safe reactor shutdown and to mitigate the consequences of a DBA such as a loss of coolant accident. Standby service water (SSW) is required by Technical Specification 3.7.1. The ultimate heat sink (UHS) consists of one 200 percent capacity cooling tower and one 100 percent capacity water storage basin. The UHS basin capacity is required by Regulatory Guide 1.27 and USAR 9.2.5 to maintain a minimum of 30 days inventory to mitigate the consequences of a DBA without replenishment. The UHS is designed to perform its safety function assuming a single failure coincident with a loss of offsite power and with respect to the 30 day mission time assuming a single division of SSW is in service.The safety design bases of these SSCs includes ensuring the SSCs are protected from the effects of natural phenomena, such as earthquakes, tornadoes, hurricanes, floods, and external missiles (GDC-2).On May 4, 2018, the licensee identified vulnerabilities in the EDG building, the control building, and the SSW cooling tower where tornado-born missiles could potential render safety-related equipment contained in these buildings inoperable. Potentially affected equipment included all three EDGs, Division II DC electrical power distribution subsystem, residual heat removal (RHR) pumps B and C, SSW pumps A, B, C, and D, Division I standby cooling tower fans, and multiple Division I SSW motor operated valves. These vulnerabilities were identified as part of the licensees review of Regulatory Information Summary 2015-06, Tornado Missile Protection. These issues were entered into the corrective action program as Condition Reports CR-RBS-2018-02687, 02768, and 02775.Corrective Actions: As a result of these issues, the licensee declared all three EDGs, the Division II DC electrical power distribution subsystem, RHR pumps B and C, SSW pumps A, B, C, and D, Division I standby cooling tower fans, and multiple Division I SSW motor operated valves inoperable, complied with the applicable technical specification action statements, initiated Condition Reports CR-RBS-2018-02687, 02768, and 02775, invoked the EGM discretion guidance, implemented initial compensatory measures, and returned the SSCs to an operable- degraded/non-conforming status. The licensee instituted compensatory measures intended to reduce the likelihood of tornado missile effects. These included verifying that guidance was in place for severe weather procedures, abnormal and emergency operating procedures, and FLEXsupport guidelines, verifying that training on these procedures was current, and verifying that a heightened level of awareness of the vulnerability was established.Corrective Action Reference(s) : CR-RBS-2018-02687, CR-RBS-2018-02768, and CR-RBS-2018-02775Enforcement:Violations: Technical Specification 3.8.1 requires, in part, that three diesel generators shall be operable in Modes 1, 2, and 3. Technical Specification 3.8.1.H requires entry into LimitingCondition for Operation 3.0.3 when three or more required AC sources are inoperable. Limiting Condition for Operation 3.0.3 requires that action shall be initiated within one hour to place the unit in Mode 2 within 7 hours, in Mode 3 within 13 hours, and in Mode 4 within 37 hours.Contrary to the above, prior to May 4, 2018, three diesel generators were not operable, and action was not initiated to place the unit in Mode 2 within 7 hours, in Mode 3 within 13 hours,and in Mode 4 within 37 hours. Specifically, the EDG building was not designed to withstand the effects of natural phenomena, such as tornadoes. The licensee initiated a condition report, invoked the enforcement discretion guidance, implemented initial compensatory measures, and returned the SSCs to an operable- degraded/non-conforming status. The inspectors verified through inspection sampling that the EGM 15-002 criteria were met and that the issue was documented in Condition Report CR-RBS-2018-02687. Therefore, EGM 15-002 enforcement discretion was applied to the required shutdown actions associated with this technical specification.Technical Specification 3.8.9 requires, in part, that the Division II AC and AC vital bus electrical power distribution subsystems shall be operable in Modes 1, 2, and 3. Technical Specification 3.8.9.D requires the station to take action to place the unit in Mode 3 within 12 hours when one or more AC or AC vital bus electrical power distribution subsystems have been inoperable for more than 8 hours. Contrary to the above, prior to May 4, 2018, the Division II AC and AC vital bus electrical power distribution subsystems were not operable for more than 8 hours, and action was not initiated to place the unit in Mode 3 within 12 hours. Specifically, the control building was not designed to withstand the effects of natural phenomena, such as tornadoes. The licensee initiated a condition report, invoked the enforcement discretion guidance, implemented initial compensatory measures, and returned the SSCs to an operable- degraded/non-conforming status. The inspectors verified through inspection sampling that the EGM 15-002 criteria were met and that the issue was documented in Condition Report CR-RBS-2018-02768. Therefore, EGM 15-002 enforcement discretion was applied to the required shutdown actions associated with this technical specification.Technical Specification 3.5.1 requires, in part, that each emergency core cooling system (ECCS) injection subsystem shall be operable in Modes 1, 2, and 3. Technical Specification 3.5.1.D requires the station to take action to place the unit in Mode 3 within 12 hours when two ECCS injection subsystems have been inoperable for more than 72 hours. Contrary to the above, prior to May 4, 2018, two required ECCS injection subsystems that included RHR pumps B and C were inoperable for more than 72 hours, and action was not initiated to place the unit in Mode 3 within 12 hours. Specifically, the control building was not designed to withstand the effects of natural phenomena, such as tornadoes.The licensee initiated a condition report, invoked the enforcement discretion guidance, implemented initial compensatory measures, and returned the SSCs to an operable- degraded/non-conforming status. The inspectors verified through inspection sampling that the EGM 15-002 criteria were met and that the issue was documented in Condition Report CR-RBS-2018-02768. Therefore, EGM 15-002 enforcement discretion was applied to the required shutdown actions associated with this technical specification.Technical Specification 3.7.1 requires, in part, that two SSW subsystems shall be operable in Modes 1, 2, and 3. Technical Specification 3.7.1. H requires the station to take action to place the unit in Mode 3 within 12 hours when both pumps associated with one SSW subsystem have been inoperable for more than 72 hours. Contrary to the above, prior to May 4, 2018, SSW pumps P2B and P2D, associated with SSWsubsystem B, were inoperable for more than 72 hours, and action was not initiated to place the unit in Mode 3 within 12 hours. Specifically, the SSW cooling tower was not designed to withstand the effects of natural phenomena, such as tornadoes. The licensee initiated a condition report, invoked the enforcement discretion guidance, implemented initial compensatory measures, and returned the SSCs to an operable- degraded/non-conforming status. The inspectors verified through inspection sampling that the EGM 15-002 criteria were met and that the issue was documented in Condition Report CR-RBS-2018-02775. Therefore, EGM 15-002 enforcement discretion was applied to the required shutdown actions associated with this technical specification.Severity/Significance: Not ApplicableBasis for Discretion: The NRC exercised enforcement discretion in accordance with EGM 15-00, Revision 1, because the licensee implemented initial compensatory measures in accordance with the EGM. |
| 05000272/FIN-2018002-01 | Salem | 2018Q2 | Inadequate Design Change for Service Water Pumps | A self-revealing Green non-cited violation (NCV)of Title 10 of the Code of Federal Regulations(10 CFR) Appendix B, Criterion III, Design Control, was identified because PSEG item equivalency evaluation (IEE) 80102443 did not evaluate the use of a chromium oxide spray coating for suitability of application in a brackish river water environment. Consequently, the coating material delaminated, which resulted in a failed in-service test (IST), inoperability and unavailability of the 26 service water (SW) pump as well as the subsequent unavailability of the 16, 21,and 24 SW pumps to perform replacementsof those pumps with the same coating. |
| 05000354/FIN-2018002-01 | Hope Creek | 2018Q2 | Inadequate Instructions for Station Service Water Pump Maintenance | A self-revealing Green non-cited violation (NCV)of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for PSEG providing inadequate written instructions for the performance of maintenance to ensure the station service water (SSW) system remains capable of performing its safety function. Specifically, the PSEG maintenance procedure for SSW pump and motor removal and replacement did not provide adequate instruction to prevent galvanic corrosion when connecting the B SSW pump to its seismic supports, which ultimately resulted in the pump failing its in-service test due to elevated vibration levels on February 18, 2018. |
| 05000298/FIN-2018002-01 | Cooper | 2018Q2 | Failure to Maintain Alarm Procedure for Service Water Booster Pump Ventilation Manual Actions | The inspectors identified a Green non-cited violation of Technical Specification 5.4, Procedures, when the licensee failed to maintain Procedure 2.3_R-1 with the bounding time restrictions for required manual ventilation actions identified in Engineering Evaluation NEDC 92-064, Transient Temperature Rise in SWBP Room After Loss of Cooling, Revision 3C2. As a result, the licensee relied on procedure guidance that contained an incorrect, less restrictive allowance of 13 hours for completion of manual actions rather than the bounding 5.8-hour allowance described in NEDC92-064. |
| 05000461/FIN-2018002-01 | Clinton | 2018Q2 | Failure to Perform an Operability Determination for Suspected Leakage Past Shutdown Service Water Isolation Valves | The inspectors identified a Green finding for the failure to perform an operability determination in accordance with Procedure OPAA108115, Operability Determinations (CM1). Specifically, the licensee failed to determine and document the operability status of the shutdown service water system and the ultimate heat sink after the discovery of leakage past the 1CC075A and 1CC076A isolation valves. |
| 05000461/FIN-2018002-02 | Clinton | 2018Q2 | Failure to Establish Adequate Leak Rate Test Procedures for Shutdown Service Water Isolation Valve Testing | The inspectors identified a Green finding and a Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for the failure to ensure testing of the shutdown service water (SX) isolation valves was performed with procedures which: (1) incorporated the requirements and acceptance limits contained in applicable design documents; and (2) included provisions for assuring that all prerequisites for the given test had been met. Specifically, the licensee failed to establish leak rate test procedures for SX boundary valves 1CC075A and 1CC076A that included provisions for ensuring the required differential test pressure was met during testing. |
| 05000298/FIN-2018011-04 | Cooper | 2018Q2 | Incorrect Classification of Potential Safety-Related Components | An NRC-identified, Green, Non-cited Violation of Title 10, Code of Federal Regulations Part 50, Appendix B, Criterion III, Design Control, occurred for failure to assure that applicable regulatory requirements and the design basis were correctly translated into specifications, drawings, procedures, and instructions. Specifically, the inspectors identified three examples of the licensees failure to properly classify potential safety-related components in the emergency diesel generator ventilation system and RHR service water booster pump room cooling systems. |
| 05000298/FIN-2018011-02 | Cooper | 2018Q2 | Failure to Ensure Adequate Design Control Measures are in Place Associated with RHR Service Water Booster Pump Room Cooling | An NRC-identified, Green, Non-cited Violation of Title 10, Code of Federal Regulations Part 50, Appendix B, Criterion III, Design Control, occurred for failure to assure that applicable regulatory requirements and the design basis were correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee failed to incorporate malfunctions of the residual heat removal (RHR) service water booster pump (SWBP) room cooling temperature switch, which could cause environmental changes leading to functional degradation of system performance, into the design basis to verify the necessary protection system action be retained. |
| 05000338/FIN-2018001-01 | North Anna | 2018Q1 | Failure to Assure Service Water Pump Sheds from Emergency Bus upon LOOP or SBO | A self-revealing Greennon-cited violation (NCV) of Technical Specification (TS)5.4.1.a, was identified for the licensees failure to have adequate written procedures for assuring proper configuration control in areas affected by maintenance or plant modifications. Specifically, the licensee failed to detect and correct a disconnected lead from contact C1 on 1-SW-62-1SWEB03. This directly led to the failure of the 1B service water (SW) pump to shed from the 1J emergency bus during performance of maintenance procedure 1-PT-83.2 on March 11, 2018. |
| 05000395/FIN-2018010-05 | Summer | 2018Q1 | Potential High Radiation Dose Areas with Unqualified Components | The NRC opened a URI to determine if a performance deficiency exists. The licensee did not perform analysis to determine the radiation exposure to shielded components adjacent to electrical and blank penetrations on the outboard side through containment. As a result, many mild environment components may be adversely affected. The inboard side of the penetrations is exposed to rad levels approaching 9X107 rads and the out board side is shielded by thin steel plates with electrical pass-thru holes. The inspectors noted that there were many areas of the plant identified as mild environments with unanalyzed penetrations. For example, the inspectors observed that the two trains for the plant service water were adjacent to unanalyzed penetrations. The components adjacent to the outboard side of the penetrations may be unqualified for service conditions expected during the most severe DBA as required by 10 CFR 50.49(e)(4). NUREG-0588 Section 1.4 "Radiation Conditions Inside and Outside Containment," required, in part, that "(8) Shielded components need be qualified only to the gamma radiation levels required..." and that "(12) Equipment that may be exposed to radiation doses below 104 rads should not be considered to be exempt from radiation qualification, unless analysis supported by test data is provided to verify that these levels will not degrade the operability of the equipment below acceptable values. The licensee provided a white paper for this issue that asserts that consideration of radiation streaming was not part of their licensing basis, thus enforcement would be addressed through a backfit analysis in accordance with 10 CFR 50.109. The team must determine whether the site licensing basis required consideration of radiation streaming and whether a backfit analysis would be appropriate in lieu of enforcement. The licensee captured this issue in their corrective action program as CR-18-00684 and determined that the process for qualification of equipment used was found acceptable per the VCS SER. Further evaluation will be performed under this CR but currently all components are qualified to their expected operating conditions and will perform their design functions. At worst, the EQ life of components may be reduced. All equipment in penetration areas are operable. |
| 05000368/FIN-2018001-02 | Arkansas Nuclear | 2018Q1 | Failure to Preplan and Perform Service Water Pre-Screen Maintenance | The inspectors reviewed a self-revealed,non-cited violation and associated finding of Arkansas Nuclear One, Unit 2, Technical Specification 6.4.1.a, for the licensees failure to properly preplan maintenance that can affect the performance of safety-related equipment. Specifically, the licensee failed to properly preplan pre-screen cleaning maintenance, causing the trainB service water system to become inoperable |
| 05000416/FIN-2018001-03 | Grand Gulf | 2018Q1 | Inadequate Procedural Guidance Which Resulted in Control Room Air Conditioning Inoperability | The inspectors reviewed a self-revealed non-cited violation of Technical Specification 5.4.1.a, Procedures, for the licensees failure to have adequate procedural guidance while performing a standby service water surveillance procedure. Specifically, the licensees procedural guidance was not adequate to prevent the control room air conditioning subsystem B compressor from starting while condenser cooling water was isolated, which caused damage and rendered the subsystem inoperable and unavailable. |
| 05000266/FIN-2018001-01 | Point Beach | 2018Q1 | Failure to Evaluate and Characterize Fire Protection Pipe Wall Degradation | The inspectors identified a finding of very low significance, for the failure to follow procedure NP 7.7.22, Service Water and Fire Protection Inspection Program. Specifically, Section 4.10, Degraded Component Characterization and System Failure Analysis, step 4.10.1 states, in part, the extent of pipe wall degradation shall be characterized by volumetric non-destructive examination (NDE) for subsequent flaw evaluation. The licensee identified pipe corrosion on November 28, 2012, and failed to characterize it by volumetric NDE. |
| 05000483/FIN-2018001-01 | Callaway | 2018Q1 | Failure to Maintain Emergency Operating Procedures | The inspectors identified a Green, non-cited violation of Technical Specification 5.4.1.a, "Procedures," for the licensee's failure to maintain emergency operating procedures for aligning auxiliary feedwater suction sources. Specifically, the licensee added continuous action steps to emergency operating procedures that placed both motor-driven auxiliary feedwater pumps in pull-to-lock and isolated their associated recirculation lines after depleting the two non-safety-related suction sources. These actions cause two of the three safety-related auxiliary feedwater pumps to be rendered inoperable prior to aligning the safety-related suction source of essential service water which is credited in accident analysis. |
| 05000272/FIN-2018001-02 | Salem | 2018Q1 | Inadequate Procedure Step Results in Service Water Strainer Trip | A self-revealing Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations(10 CFR), Appendix B, Criterion V, was identified because PSEG procedure WC-AA-111, Predefine Process, Revision 8, step 4.8.11, did not adequately prescribe activities that affected the quality of the safety-related 11 service water (SW) strainer. Specifically, step 4.8.11 did not adequately prescribe controls associated with the performance of partial PM activities that affected the quality of the safety-related structures, systems and components (SSCs). Consequently, the 11 SW corrosion control sacrificial anodes were not replaced prior to the PM overdue date and eventually broke into pieces, which rendered the 11 SW pump and strainer inoperable and unavailable from June 8 11, 2017. |
| 05000269/FIN-2018013-01 | Oconee | 2018Q1 | Failure to Translate Design and Licensing Basis Requirements and Verify Adequate Design | The licensee did not correctly translate site design and licensing bases into the site specifications and procedures for the design and installation of plant modifications that included the re-configuration of electrical cables in electrical cable trench #3 between the Keowee Hydro Station (KHS) and transformer CT-4 at Oconee Nuclear Station (ONS) and the Protected Service Water (PSW) ductbank between CT-4 and the PSW building. The specific requirements of IEEE 279-1968 and single failure sections of IEEE 279-1971 were not fully implemented. Contrary to this requirement, the licensee placed Class 1E 125Vdc system cables adjacent to various medium voltage-high energy alternating current (ac) power distribution cables for the offsite and onsite power systems and introduced credible single failure conditions with the potential for exposure of the onsite redundant Class 1E dc power distribution and control systems (dc systems) to possible damaging peak voltage from the offsite and onsite AC power systems. Corrective Actions: The licensee reported this as an unanalyzed condition to the NRC in accordance with 10 CFR 50.73(a)(2)(ii) (B) in Licensee Event Report 269/2014-01 entered this issue into their corrective action program. The licensee also performed immediate and prompt determinations of operability in which they concluded a reasonable expectation of operability existed on the basis that the consideration of the specific hazards was not required by the site licensing basis. A number of plant modifications were implemented to address the concerns.Additional inspections of these corrective actions will be conducted as appropriate. For the limited areas where the concerns could not be addressed, on February 28, 2018, (ML180051B257) the NRC granted relief from the applicable Code and concluded that the proposed alternatives provided an acceptable level of quality and safety for the cable configurations and locations.Corrective Action Reference: PIP O-14-03190, PIP O-14-05125, PIP O-14-03915, and PIP O-14-02965 |
| 05000416/FIN-2017007-05 | Grand Gulf | 2017Q4 | Failure to Update a Calculation and Procedure to Address Standby Service Water Passive Failure | The team identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, which states, in part, Measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Specifically, since September 25, 2013, the licensee failed to include a design basis standby service water system (SSWS) piping crack in the appropriate design calculation and procedure. In response to this issue the licensee performed an operability determination to ensure that the ultimate heat sink basins would still have sufficient capacity to meet the 30 -day mission time. This finding was entered into the licensees corrective action program as Condition Report CR-GGN-2017-10192. The team determined that the failure to update a design calculation and a procedure to address a postulated standby service water passive failure was a performance deficiency. The finding was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of mitigating systems to respond to initiating events to prevent undesirable consequences. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the issue screened as having very low safety significance (Green) because it was a design or qualification deficiency that did not represent a loss of operability or functionality; 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 equipment; and did not screen as potentially risk-significant due to seismic, flooding, or severe weather. The team determined that this finding did not have a cross-cutting aspect because the most significant contributor did not reflect current licensee performance. |
| 05000395/FIN-2017007-01 | Summer | 2017Q4 | Failure to Verify the Adequacy of Design for the EFW system when Supplied by SW | The NRC identified a non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to verify the emergency feedwater (EFW) pumps would be capable of taking suction from service water for an indefinite period of time as required by Updated Final Safety Analysis Report Section 10.4.9.2. The licensee entered this issue into their corrective action program (CAP) as condition report (CR) 17-05528 and performed an operability determination to verify the EFW pumps remained operable. The performance deficiency was determined to be more than minor because it 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. Specifically, the failure to evaluate worst-case design conditions resulted in a reasonable doubt that the EFW pumps could provide cooling water to the steam generators and perform their design basis function. The team determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, and component (SSC), and the SSC maintained its operability. The team determined that no crosscutting aspect was applicable because the finding did not reflect current licensee performance |
| 05000416/FIN-2017014-02 | Grand Gulf | 2017Q4 | Failure to Perform Operator Rounds | 10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality shall be accomplished in accordance with documented instructions or procedures of a type appropriate to the circumstances. Procedure EN-OP-115-01, Operator Rounds, Revision 1, a quality related procedure, provides instructions for operators to conduct watchstanding rounds. Subparagraph5.1(7) requires, in part, that watchstanders tour all required areas of their watch station.Contrary to the above, between February and December, 2016, three watchstandersfailed to tour all required areas of their watchstation. Specifically, three non-licensed operators deliberately failed to tour the area of the standby service water pump houses, which is an area they were required to tour for that watch station.This apparent violation is designated as AV 05000416/2017014-02, Failure to Perform Operator Rounds. |
| 05000461/FIN-2017011-01 | Clinton | 2017Q4 | Failure to Correct an Identified Degraded Condition on the Division 3 Shutdown Service Water Pump | A self-revealing finding and an apparent violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, with associated violations of Technical Specification (TS) 3.7.2 and TS 3.5.1 were identified on June 15, 2017, for the licensees failure to correct a degraded condition identified during the evaluation performed as a result of the Division 3 shutdown service water (SX) pump failure in 2014. Specifically, the licensee identified corrosion of the Division 3 SX pump sleeves as a contributing cause of the 2014 pump failure and failed to appropriately evaluate and correct this issue. This resulted in the Division 3 SX pumps failure to start on June 15, 2017, and rendered the Division 3 SX pump inoperable for a time longer than its TS allowed outage time. The licensee entered this issue into the corrective action program and implemented design changes to the pump and motor assembly, including installing a new motor with higher starting torque characteristics and replacing the pump shaft sleeves and packing with parts more resistant to corrosion. The licensee has completed multiple successful runs of the new pump with no abnormalities noted. The inspectors determined that the licensees failure to correct a degraded condition identified during the evaluation performed as a result of the 2014 Division 3 SX pump failure appears to be not in accordance with the requirements of 10 CFR 50, Appendix B, Criterion XVI, and was a performance deficiency. The performance deficiency was determined to be more than minor because it impacted the Mitigating Systems cornerstone attribute of equipment performance and adversely affected the cornerstone objective of ensuring the availability, capability and reliability of equipment that responds to initiating events. Specifically, the performance deficiency resulted in the failure of the Division 3 SX pump, which impacted the operability and functionality of the high pressure core spray system and the Division 3 emergency diesel generator. Using IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, dated June 19, 2012, a Significance and Enforcement Review Panel preliminarily determined the finding to be of low to moderate safety significance. The inspectors determined that this finding affected the cross-cutting area of problem identification and resolution in the aspect of evaluation, where the organization thoroughly evaluates issues to ensure that resolutions address causes and extent of 3 conditions commensurate with their safety significance. Specifically, the licensee failed to properly evaluate the Division 3 SX pump sleeve corrosion rates when performing the component life evaluation, the component operability evaluation and the evaluation in response to the abnormal noises identified during periodic pump runs. (P.2) |
| 05000440/FIN-2017008-03 | Perry | 2017Q4 | Failure to Verify the Capability to Manually Backwash the Emergency Service WaterStrainer during Loss of Offsite Power | The team identified a finding of very-low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control,for the failure to verify the capability to manually backwash the emergency service water (ESW) strainer during a LOOP. Specifically, the licensee credited the capability to manually backwash the ESW strainers during a LOOP. However, the associated differential pressure alarm setpoint did not ensure sufficient time to complete this activity because the alarms were set at the same value as the design differential pressure value assumed by the hydraulic calculations. The licensee captured the issue in their CAP as CR-2017-09033, reasonably determined ESW remained operable, and planned to revise the associated calculation and the alarm setpoint to ensure sufficient time to perform the required manual actions during a LOOP.The performance deficiency was determined to be more-than-minor because it was associated with the Mitigating Systems cornerstone attribute of protection against external factors 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 did not assure the ESW capability to supply the required minimum flow to its supported components. The finding screened as of very-low safety significance (Green) because it did not result in the loss of operability or functionality of mitigating systems. The team did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance due to the age of the performance deficiency. Specifically, the alarm set point was established more than 3 years ago. |
| 05000364/FIN-2017004-01 | Farley | 2017Q4 | Failure to Evaluate Impacts on the 2C RCP Oil Collection System | A self-revealing finding was identified for the licensees failure to evaluate the impacts to the Unit 2 Reactor Coolant Pump (RCP) 2C oil collection system when a service water (SW) leak was identified on the Unit 2 RCP motor air coolers. As a result, a strategy was not implemented to prevent service water from collecting in the 2C RCP oil collection system drain tank which impacted its design function while the plant was in Mode 1. The licensees failure to evaluate the potential impacts to the Unit 2 RCP 2C oil collection system during the operability/functionality evaluation of the SW leak associated with RCP motor air coolers was a performance deficiency. The licensee initiated condition reports (CRs) 10420400 and 10422562 and replaced the 2C RCP motor and leaking air cooler.The finding was more than minor because it was associated with the protection against external factors (fires) and adversely affected the mitigating systems cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure to maintain adequate capacity in the RCP 2C Oil Spillage Protection System (OSPS) oil collection tank presented a degradation of a fire confinement component which has a fire prevention function of not allowing an oil leak to reach hot surfaces. The significance of this finding was evaluated using IMC 0609, Appendix F, "Fire Protection Significance Determination Process, dated September 20, 2013, because the performance deficiency affected fire protection defense-in-depth strategies involving fire confinement. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) because the exposed fire area contained no potential damage targets that are unique from those in the exposing fire area. The inspectors determined the finding had a cross-cutting aspect of Evaluation in the problem identification and resolution area because the licensee did not fully evaluate the impacts of the RCP motor air cooler SW leak on the Unit 2 RCP oil collection systems. (P.2) |
| 05000424/FIN-2017004-02 | Vogtle | 2017Q4 | Failure to Maintain NEMA Type 4 Qualification for the Nuclear Service Cooling Water Pumps | A Green, self-revealing, NCV of TS 5.4.1.a, Procedures, was identified for the licensees failure to properly implement and establish procedures to maintain watertight requirements of the nuclear service water system (NSCW) pumps motor main power cables termination box. As a result, the Unit 2 B train NSCW pump no. 4 failed due to aphase-to-ground fault caused by water and moisture intrusion into the power cable splice connections. Failure to adequately implement and establish procedures to maintain watertight requirements of the NSCW pumps motor main power cables termination box during maintenance, as required by maintenance procedures and specifications, was a performance deficiency. The licensee replaced the motor and faulted cable; and sealed all potential water and moisture intrusion enclosure locations until watertight enclosure standards are fully restored. This issue was entered into the licensees CAP as CRs10399125, 10404327, and corrective action report 270905.The performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (e.g. core damage). Specifically, the Unit 2 NSCW pump no. 4 was rendered inoperable, adversely affecting the NSCW system reliability. The finding was determined to be of very low safety significance (Green) because it did not result in an actual loss of safety system function, and it did not represent a loss of function of one or more than one train for more than its Technical Specification (TS) allowed outage time or greater than 24 hrs. The finding was assigned a cross-cutting aspect of Resources, because procedures and/or work instructions were not available to maintenance personnel for properly verifying motor termination boxes were installed in compliance with NEMA 4 specifications. (H.1) |
| 05000416/FIN-2017007-07 | Grand Gulf | 2017Q4 | Licensee-Identified Violation | The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as non- cited violations. Technical Specification 5.4.1(a) requires written procedures to be established, implemented, and maintained as recommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Section 4.e recommends, in part, instructions for startup of shutdown cooling and reactor vessel head spray system be prepared. Contrary to the above, from about 2004 until September 1, 2017, the 04-1-01-E12-2 instruction failed to provide instruction for placing the alternate decay heat removal system in service. Specifically, Step 4.9.2a.7(d) instructs an operator to, Manually control component cooling water temperature by throttling P44-F010A(B)(C), PSW inlet to CCW HXs. However, the purpose of that step is to throttle plant service water flow through the alternate decay heat removal system and component cooling water system to ensure both systems have plant service water flow, which is not accomplished by the instruction step. The licensee identified this procedural violation before the system was credited for availability during an inservice demonstration on September 1, 2017, and entered it in the corrective action program as Condition Report CR-GGN-2017-08643. The violation is of very low safety significance (Green) because, although the procedure did delay placing the system in service due to the procedure error, the system was capable of performing its design function, consistent with Inspection Manual Chapter 0609, Appendix G, Attachment 1, Exhibit 3 screening. |
| 05000348/FIN-2017004-04 | Farley | 2017Q4 | Licensee-Identified Violation | 10 CFR 50.55 (a)(b)(5)(i) required in part that licensees must apply the most recent version of ASME BPV Code cases listed in Regulatory Guide 1.147, Revision 17. Contrary to the above, the licensee failed to perform augmented re-examinations on a 30-day periodicity as required by ASME Code Case N-513-3. A through-wall pinhole leak on the Unit 2 Train A Service Water strainer backwash piping was documented in condition report (CR) 10234480 on June 10, 2016. The service water system provides a heat sink for the removal of process and operating heat from safety related components during a Design Basis Accident (DBA) or transient. The backwash piping is safety-related ASME Section III, Class 3 piping. An Immediate Determination of Operability Evaluation (IDO) was performed declaring the strainer operable but degraded non-conforming (OBDN). The licensee followed the guidance of ASME Code Case N-513-3, Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3 Piping, Section XI, Division 1. The code case requires that an additional five similar susceptible locations be identified and inspected to ensure that another flaw does not exist. In addition to the expanded scope, the code case requires that frequent periodic inspections of no more than30-day intervals shall be used to determine if the flaws are growing to an unacceptable size. An additional CR (10236417) was initiated on June 15, 2016, to request work orders for inspection of these five locations. A total of three examinations were performed on a 30-day periodicity, the last being completed on August 22, 2016. CR 10416364 was initiated on October 5, 2017, documenting that no re-examinations on a 30-day periodicity were performed on the original leak location and the five additional locations since August 22, 2016. The ultrasonic examination was completed on October 5, 2017, and the degraded backwash piping was removed and replaced with new piping by WO SNC795917 on October 28, 2017. This finding was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency, it did not represent a loss of system safety function of a single train for greater than its TS allowed outage time, and it did not screen as potentially risk significant due to seismic, flooding, or severe weather initiating events. This finding was entered into the licensees CAP as CR 10416364. |
| 05000395/FIN-2017004-02 | Summer | 2017Q4 | Failure to Implement Corrective Actions to Restore Compliance for Previous NRC-identified Green NCV 05000395/2005007-01 | The inspectors identified a Green finding associated with a cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the failure to ensure that conditions adverse to quality as noted in a previous NRC-identified Green NCV, 05000395/2005007-01, EFW Flow Control Valves Are Susceptible to Plugging by Tubercles or Other Debris from Service Water, were corrected. The licensee entered the issue in their corrective action program as condition report, CR-17-04630. The inspectors determined that the failure to promptly identify and correct the conditions adverse to quality (CAQ) for a design in which the emergency feedwater (EFW) flow control valves were susceptible to plugging by tubercles or other debris from the service water (SW) system was a performance deficiency (PD). The inspectors reviewed IMC 0612, Appendix B and determined the PD was more than minor and therefore a finding, because it affected the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and the respective attribute of design control because the EFW flow control valves were susceptible to plugging by SW debris. This finding had been evaluated and screened to a low safety significance (Green) and documented in the previous NRCidentified Green NCV, 05000395/2005007-01. Because the licensee failed to implement corrective actions and restore compliance in a timely manner, this violation is being treated as a cited violation, consistent with Section 2.3.3 of the NRC Enforcement Policy. The inspectors used IMC 0310 and determined this finding has a cross-cutting aspect of resolution in the area of Problem Identification and Resolution because the organization failed to take effective corrective actions to address issues in a timely manner commensurate with their safety significance and restore compliance (P.3). |
| 05000341/FIN-2017004-02 | Fermi | 2017Q4 | Division 2 Residual Heat Removal Service Water System Outlet Flow Control Valve Lower Bonnet (Backseat) Bushing Failure | The inspectors evaluated the licensee's handling of selected degraded performance issues involving the following risk-significant structures, systems, and components (SSCs):Residual heat removal service water system. 13 The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the SSCs. Specifically, the inspectors independently verified the licensee's handling of SSC performance or condition problems in terms of:appropriate work practices;identifying and addressing common cause failures;scoping of SSCs in accordance with 10 CFR 50.65(b);characterizing SSC reliability issues;tracking SSC unavailability;trending key parameters (condition monitoring);10 CFR 50.65(a)(1) or (a)(2) classification and reclassification; andappropriateness of performance criteria for SSC functions classified (a)(2) and/or appropriateness and adequacy of goals and corrective actions for SSC functions classified (a)(1).In addition, the inspectors verified problems associated with the effectiveness of plant maintenance for risk-significant SSCs were entered into the licensee's corrective action program with the appropriate characterization and significance. Selected CARDs were reviewed to verify corrective actions were appropriate and implemented as scheduled.This inspection constituted one quarterly maintenance effectiveness inspection samples as defined in IP 71111.12.FindingsDivision 2 Residual Heat Removal Service Water System Outlet Flow Control Valve Lower Bonnet (Backseat) Bushing FailureIntroduction. The inspectors identified an unresolved item (URI) to further evaluate the events and causes of a failure of the Division 2 RHRSW system outlet Flow Control Valve (FSC) lower bonnet (backseat) bushing. Specifically, additional information was needed to determine if one or more performance deficiencies exist.Description. On October 23, 2017, the Division 2 RHRSW system was started to support weekly addition of biocide to the Division 2 RHR reservoir (ultimate heat sink) as a preventative measure to minimize raw water system fouling, which typically entailed running both Division 2 RHRSW pumps for approximately 12 hours. Approximately 20 minutes after system startup, the control room received an overhead annunciator alarm for reactor building south west quad leakage to floor drain sump high along with indication that the reactor building south west quad sump pumps were running. A non-licensed operator was dispatched to the field to investigate the alarms and identified the Division 2 RHRSW outlet Flow Control Valve (FCV) (E1150F068B), located in the Division 2 RHR heat exchanger room in the reactor building, had a significant packing leak calculated to be approximately 16 gallons per minute. The leakage did not impact any other plant equipment in the local area and was captured by the Division 2 RHR heat exchanger room floor drains, which discharge into the reactor building south west quad room sump. Control room operators subsequently shutdown the Division 2 RHRSW pumps to stop the packing leakage and declared the Division 2 RHRSW system inoperable 14 The licensee formed an emergent issues team to further investigate the issue.Following valve disassembly and inspection, the licensee identified the valve lower bonnet (backseat) bushing no longer had sufficient thread engagement to remain in place and that the valve packing had been ejected from the valve stuffing box. A temporary modification was implemented to install a new backseat bushing welded directly to the valve bonnet. The system was subsequently returned to service on October 27, 2017.The Division 2 RHRSW outlet FCV is a safety-related, 24inch Powell globe valve with a motor operator. The primary safety function of the outlet FCV is to fully open to support heat transfer from the Division 2 RHR heat exchanger to the ultimate heat sink. The valve remains fully open during RHRSW pump operation (combined pump flow on the order of 10,000 gallons per minute) and generally is not throttled other than during initial startup of the pumps for a short period of time to help mitigate any potential water hammer events.The licensee completed a root cause analysis documented in CARD 1728611 at the end of the inspection period. The direct cause of the Division 2 RHRSW outlet FCVpacking leakage was determined to be the valve bonnet carbon steel threads corroded to the point of no longer functioning as an adequate mechanical connection. This resulted in the backseat bushing detaching from the valve bonnet allowing the packing to be ejected. The root cause was determined to be previous operating experience resolution for galvanic corrosion for valves in the safety-related service water systems was less than adequate resulting in a failure to recognize the vulnerability of galvanic corrosion on passive valve components. Contributing causes consisted of (1) RHRSW system operation produces significant valve vibration levels and periodic wetting and then drying conditions promoting a corrosive environment and (2) high levels of ionic impurities, as measured by chloride concentration, in RHRSW accelerate galvanic corrosion.The inspectors reviewed the root cause analysis report and several previous issues associated with the Division 2 RHRSW outlet FCV. Those events included, but were not limited to:On May 22, 2017, while placing Division 2 RHRSW in service for biocide treatment of the Division 2 RHR reservoir, the Division 2 RHRSW outlet FCVfailed to fully open. Troubleshooting discovered the direct cause was failure of the anti-rotation bushing stem key due to broken tack welds caused by high vibration during system operation. Previous troubleshooting on what was believed to be an indication issue on May 5, 2017 for the Division 2 RHRSW outlet FCV was inadequate and did not identify the failure of the anti-rotation key. As a result, the RHRSW FCV was returned to service on May 7, 2017, and subsequently failed on the next on-demand stroke on May 22, 2017. The licensee submitted Licensee Event Report 05000341/201700300 to report this event in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specification 3.7.1 and 10 CFR 50.73(a)(2)(v)(B) as a condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to remove residual heat. The system was returned to service on May 24, 2017. On September 28, 2017, while Division 2 RHRSW was out of service for planned valve performance monitoring, a partial stem-to-disc separation was detected.This additional monitoring was put in place based on previous industry operating experience of potential stem-to-disc separation following anti-rotation key failures. Upon further investigation and valve-disassembly, the stem-to-disc jam nut tack welds were found broken and the stem had unthreaded approximately 0.225 inches from the disc. Repairs were performed to replace the broken tack welds on the disc jam nut. The disc guide pin was also identified to be damaged and the licensee performed an engineering evaluation to permanently remove the disc guide pin. A broken tack weld was also noted on the backseat bushing which was repaired. The system was returned to service on October 3, 2017.The inspectors questioned the potential relationships between the aforementioned events given the potential for each event to have influenced the eventual failure of the backseat bushing. The inspectors needed additional information to determine whether or not the valve, including the backseat bushing, was subject to an over thrust condition as a result of one or a combination of irregular limit switch settings, anti-rotation key failure, broken and subsequent removal of the disc guide pin, stem-to-disc unthreading, and various broken tack welds. Other additional information was needed in order to determine:if the Division 2 RHRSW outlet FCV was of appropriate design for the known conditions of high vibrations, periods of cavitation on startup and shutdown, and a highly susceptible corrosive environment due to periods of wet and dry conditions with known dissimilar metals highly susceptible to galvanic corrosion;the technical basis behind not including globe valves in the corrosion monitoring program following previously noted and evaluated concerns of RHRSW system susceptibility from years past; andthe technical basis and management of chemistry controls on the RHR reservoirs.Because the licensee completed their root cause evaluation at the end of the inspection period and additional information was required to determine if one or more performance deficiencies exists associated with the various Division 2 RHRSW outlet FCV problems, this issue is being treated as an unresolved item pending receipt of additional information and subsequent inspector review. (URI 05000341/201700402, Division 2 Residual Heat Removal Service Water System Outlet Flow Control Valve Lower Bonnet (Backseat) Bushing Failure) |
| 05000272/FIN-2017003-03 | Salem | 2017Q3 | Failure to Follow Maintenance Procedureto Assure Proper Installation of Service Water Check Valve | A self-revealing Green non-cited violation (NCV) of Technical Specification (TS) 6.8.1, Procedures and Programs, as described in Regulatory Guide 1.33, Revision 2, was identified because PSEG did not install the 12 service water (SW) accumulator injection check valve (12SW536) in accordance with written procedures. Specifically, the check valve was installed in the wrong orientation, which impacted the ability of the valve to close and support containment integrity. PSEG entered this issue in the Corrective Action Program (CAP) as notifications (NOTFs) 20771353 and 20776321, and performed Equipment Reliability Evaluation (ERE) 70195309. Corrective actions (C/As) consisted of removing the check valve from the system, clearing the silt build-up, and reinstalling the check valve in the correct orientation.This issue was more than minor since it was associated with the configuration control attribute of the Barrier Integrity Cornerstone and adversely impacted its objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases cause by accidents or events. Using IMC 0609, Attachment 4 and Appendix A, Exhibit 3, the inspectors determined that this finding was of very low safety significance, or Green, because the finding did not result in an actual open pathway in the physical integrity of reactor containment. The inspectors determined there was no cross-cutting aspect associated with this finding because the causal factors associated with this finding occurred outside the nominal three-year period of consideration and were not considered representative of present performance, in accordance with IMC 0612. |
| 05000272/FIN-2017003-01 | Salem | 2017Q3 | Expiration of Periodic Inservice Testing of 14 Service Water Pump | Inspectors identified a Severity Level IV (SLIV) non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) 50.55a(z) when a periodic Inservice Test (IST) of the 14 service water (SW) pump and its strainer outlet check valve was not completed prior to expiration of its testing frequency on August 4 without Nuclear Reactor Regulation (NRR) authorization. PSEGs corrective actions (C/As) included making repairs to the 14 SW strainer, satisfactory completion of the 14 SW IST on August 21, chartering an apparent cause evaluation (ACE), and entering the issue in their Corrective Action Program (CAP) as notification (NOTF) 20772390.The issue was assessed in accordance with IMC 0612 and traditional enforcement applied since the issue impeded the regulatory process. Specifically, PSEG did not perform the prescribed IST or obtain prior NRR authorization for an alternative measure in accordance with 10 CFR 50.55(a)(z). The Reactor Oversight Processs (ROP) significance determination process does not specifically consider regulatory process impact in its assessment of licensee performance. Therefore, it was necessary to address this violation,which impeded the NRCs ability to regulate, using traditional enforcement to adequately assess the non-compliance. The violation was determined to be a SLIV since: 1) the delay in the inservice test required, and PSEG did not obtain, prior Commission review and approval, 2) the associated consequence was minor or of very low safety significance, and 3) the NRC would have likely approved an alternative, given reasonable assurance of operability of the 14 SW train, in accordance with Section 6.1 of the NRC Enforcement Policy. The NRC also determined this violation was associated with a minor ROP performance deficiency. Traditional enforcement violations are not assessed for cross-cutting aspects. |
| 05000278/FIN-2017003-01 | Peach Bottom | 2017Q3 | Instructions Not Followed for Replacement of HPSW Ventilation Switch Block | A self-revealing NCV of Technical Specification (TS) 5.4.1, Procedures,of very low safety significance (Green) was identified for Exelonnot implementing procedural instructions for the replacement of the HS-3-40H-3AV060 switch block associated with the 3AV060 high pressure service water (HPSW) ventilation fan. Exelon did not ensure that electrical connections were free of loose wire strands per their procedural standard E-1317,Wire and Cable Notes and Details, Power, Control, and Instrumentation, Revision 55, and from the vendor manual instructions. As a result,on July 10, 2017, the 3AV060 HPSW ventilation fan failed its surveillance test(ST)and rendered one subsystem of Unit 3 HPSW inoperable. Exelon entered this issue into their corrective action program (CAP) asissue reports(IR)4030367 and 4044444, straightened out the remaining loose strands, and specified additional electrical panels for an extent of condition (EOC) review.Thisfinding ismore than minor because it isassociated with the equipment performance attribute of the Mitigating Systemscornerstoneand affected the cornerstones objective to ensure the reliability, availability, and capability of systems to respond to initiating events to prevent undesirable consequences (i.e. core damage).By not implementing theE-1317 procedural instructions, the 3AV060 fan failed and affected the reliability of one HPSW subsystem.The inspectors evaluated the finding in accordance with Exhibit 2 of IMC 0609, Appendix A, SDP for Findings At-Power and determined the finding was of very low safety significance (Green) because it did notrepresent a loss of system function or represent an actual loss of function of at least a single train for longer than itsTSallowed outage time. The inspectors determined no cross-cutting aspect applied because the PD occurred in 2010 and was not indicative of current performance. |
| 05000313/FIN-2017003-01 | Arkansas Nuclear | 2017Q3 | Failure to Maintain Service Water Train Separation | The inspectors identified a non- cited violation of Technical Specification 5.4.1.a for the licensees failure to maintain train separation between safety -related service water trains when swapping the swing high pressure injection (HPI) pump between trains. Specifically, by following procedure OP 1104.002, Makeup and Purification System Operation, Revision 89, operators cross -tied service water trains, placing the system in an unanalyzed condition. This condition resulted in the train A electrical equipment room emergency chiller and train B reactor building emergency cooling coils being inoperable for a maximum of 25 minutes per occurrence. Additionally, it was determined that service water temperatures over the past 3 years did not result in an actual loss of function associated with these components if a design basis accident would have occurred. The immediate corrective actions were to assess past operability for not maintaining service water train separation and to revise Operating Procedure 1104.002 with adequate work instructions to maintain service water train separation. The licensee entered this deficiency into the corrective action program as Condition Report CR -ANO -1-2017- 02518. The licensees failure to maintain safety -related service water train separation when swapping the swing HPI pump between trains was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedural quality attribute of the Mitigating Systems Cornerstone, and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events. Specifically, the licensees failure to maintain service water train separation placed the system in an unanalyzed condition and was subsequently determined to cause the train A electrical equipment room emergency chiller and train B reactor building emergency cooling coils to be inoperable for a maximum of 25 minutes per occurrence . Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Finding s At-Power, dated June 19, 2012, the inspectors determined that the finding had very low safety significance (Green) because it: was not a design deficiency; did not represent a loss of system and/or function; did not represent an actual loss of function of at least a single train for longer than its technical specification allowed outage time; and did not result in the loss of a high safety -significant , non -technical specification train. Specifically, inspectors confirmed that service water temperatures were never high enough to result in an actual loss of function for either limiting component. The finding had 3 a cross -cutting aspect in the area of human performance associated with conservative bias because the licensee failed to determine whether the proposed action was safe to proceed, rather than unsafe in order to stop. Specifically, in December 2015 when this approach was revise d to declare only the non- protected service water train inoperable, the licensee did not ensure that the transition lineup was analyzed to be within safety analyses before adopting the revised steps. (H.14) |
| 05000454/FIN-2017007-01 | Byron | 2017Q3 | Fai lure to Perform Maintenance in Accordance with Performance Centered Maintenance Template | The inspectors identified a finding of very low safety significance and an associated NCV of TS 5.4.1, Procedures, when licensee personnel failed to perform maintenance in accordance with written procedures as required by Regulatory Guide 1.33. Specifically, from February 3, 2014, through August 25, 2017, the licensee failed to develop and execute work instructions of sufficient scope to accomplish the 3 preventive maintenance to replace flexible hoses on the essential service water (SX) makeup pumps and the diesel driven auxiliary feedwater (AFW) pumps and did not have a technical justification for a deviation from the Exelon Corporate Performance Centered Maintenance (PCM) template. The licensee entered this issue into their CAP as Action Request (AR) 03961955, AR 03971962, and AR 04045769 and planned to replace the flexible hoses at the next available opportunity. The inspectors determined that failure to perform maintenance in accordance with written procedures as required by TS 5.4.1, Procedures, and Regulatory Guide 1.33 was a performance deficiency. The performance deficiency was more than minor because it was associated with the Mitigating Systems cornerstone attribute of Equipment Performance 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, failing to replace flexible hoses on the SX makeup pumps and the Unit 1 and Unit 2 diesel -driven AFW pumps at a pre - established frequency could allow hose degradation to remain unidentified and lead to the unplanned inoperability of these safety-related systems. Since the finding is a deficiency affecting the design or qualification of mitigating systems, structures and components (SSC s) and the SSC s remained operable and functional, the finding screened as having very low safety significance. This finding affected the C ross -Cutting area of Human Performance in the aspect of Work Management because the licensee failed to perform required maintenance in accordance with their associated maintenance strategy as well as the corporate PCM template (H.5) . |
| 05000458/FIN-2017003-01 | River Bend | 2017Q3 | Failure to Account for Delayed Closure of Isolation Valves in the Ultimate Heat Sink Inventory Analysis | The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, which states, in part, Measures shall be established to assure that applicable regulatory requirements and the design basis, as defined in Section 50.2 and as specified in the license application, for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. Specifically, prior to September 28, 2017, the licensees current calculation for assuring adequate ultimate heat sink inventory did not support the acceptability of the timing of a critical operator action in the abnormal operating procedure for the loss of standby service water. The potential safety consequence is that sufficient ultimate heat sink inventory might not be available to safely shut down the plant and maintain it in a cold shutdown condition for a 30-day period with no external makeup water source available. In response to this finding, the licensee performed an initial analysis and determined that the ultimate heat sink had sufficient inventory to account for the losses associated with the delayed closure of the normal service water return isolation valves and that the losses would likely be less than those previously calculated. This finding was entered into the licensee's corrective action program as Condition Report CR-RBS-2017-06998.The inspector determined that the failure to account for delayed closure of isolation valves in the ultimate heat sink inventory analysis was a performance deficiency. The performance deficiency was more-than-minor, and therefore a finding, because it 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. Specifically, the performance deficiency resulted in a condition where the current analysis to determine the acceptability of the ultimate heat sink with respect to the 30-day inventory requirement needed to be re-performed to assure that accident analysis requirements were met. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated July 19, 2012, the finding screened as having very low safety significance (Green) because it was a design or qualification deficiency that did not represent a loss of operability or functionality; 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 equipment; and did not screen as potentially risk-significant due to seismic, flooding, or severe weather. This finding had a cross-cutting aspect in the area of human performance associated with design margins because the failure to account for delayed closure of isolation valves in the 30-day ultimate heat sink inventory analysis resulted in a significant reduction in the available margin (H.6). |
| 05000482/FIN-2017003-02 | Wolf Creek | 2017Q3 | Failure to Ensure the Design Basis was Adequately Represented in the Technical Specification Bases | The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to establish adequate measures to ensure that the design bases are correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee did not ensure the auxiliary feedwater system design basis was adequately represented in the Technical Specification Bases; as a result, the Technical Specification Bases and other station procedures allowed for one train of essential service water supply to the turbine-driven auxiliary feedwater pump to be removed from service without recognition that auxiliary feedwater operability was impacted. Immediate corrective actions included entering Condition Reports 113304 and 116852 into the corrective action program and incorporating a note on operations turnover documents to temporarily postpone applicable portions of the operations quarterly tasks.The licensee also completed a past operability review, and created actions to develop a license amendment request to add a specific Technical Specification condition and submit for NRC approval.The failure to ensure the auxiliary feedwater system design basis was adequately represented in the Technical Specification Bases was a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it is 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 (i.e., core damage). The inspectors evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of Inspection Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings At-Power, and determined this finding was of very low safety significance (Green). The inspectors determined that the finding has a problem identification and resolution cross-cutting aspect in the area of evaluation because the organization did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. This issue is indicative of current performance because the evaluation of Condition Report 111808 in May 2017 was a reasonable opportunity for the licensee to identify that the Technical Specification Bases was inadequate (P.2). |
| 05000266/FIN-2017003-02 | Point Beach | 2017Q3 | Service Water Cable Support Failure | A finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified by the inspectors for the failure to promptly identify and correct degraded structural supports 3 for safety-related cables, a condition adverse to quality. Specifically, the licensee failed to repair or replace degraded service water pump cable supports after they identified the degraded supports in 2011. The licensee was in the process of scheduling the cable support repairs at the end of the inspection period. The inspectors determined that the continued non-compliance does not present an immediate safety concern because, given the weight pressing onto the cables, the insulation should remain intact. The finding was determined to be more than minor because the finding was associated with the Mitigating Systems cornerstone attribute of Reliability and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the failure of the service water motor cable support allowed the structural beam to drop and metal cable clamps to impinge on the insulation of the 480 volt safety-related cables. The inspectors determined the finding could be evaluated in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, issued on October 7, 2016. Specifically, the inspectors used IMC 0609 Appendix A SDP for Findings At-Power, issued June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions to screen the finding. The finding screened as of very low safety significance (Green) because the inspectors answered No to the screening questions. This finding has a cross-cutting aspect in the area of human performance, Conservative Bias, because the licensee did not use decision making-practices that emphasize prudent choices overt those that are simply allowed. (H.14) |
| 05000482/FIN-2017002-02 | Wolf Creek | 2017Q2 | Failure to Declare Train A Component Cooling Water Inoperable | The inspectors identified a Green non-cited violation of Technical Specification Limiting Condition for Operation 3.7.7 for the licensees failure to place the unit in MODE 3 within 78 hours with the train A component cooling water system inoperable. Specifically, the essential service water emergency make-up to component cooling water train A valve was not declared inoperable when it was out of service, and as a result, train A component cooling water was out of service for longer than its Technical Specification allowed outage time. The licensees planned actions include revising Technical Specification Bases 3.7.7 and training operators on the proposed Technical Specification Bases revisions, and the licensee issued an Essential Reading document for operators to review. The licensee entered the issue into the corrective action program as Condition Report 111808. The failure to declare train A component cooling water inoperable is a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it is associated with the human performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of Inspection Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings At-Power, and determined the finding was of very low safety significance (Green). The inspectors determined that the finding has a human performance cross-cutting aspect in the area of challenge the unknown because individuals did not stop when faced with uncertain conditions, and risks were not evaluated and managed before proceeding. This issue is indicative of current performance because the creation and implementation of the subject clearance order occurred in the last three years (H.11). |
| 05000416/FIN-2016008-03 | Grand Gulf | 2017Q2 | Failure to Follow Operations Procedures | The team identified a non -cited violation of Technical Specification 5.4.1.a , Procedures, for the licensees failure to implement procedures required by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Specifically, contrary to procedures , on September 23, 2016, operations personnel failed to verify adequate plant service water flow to the alternate decay heat removal heat exchangers while placing the system in service . The licensee implemented corrective actions which included high intensity training to improve nuclear worker behaviors and clarifying the directions in the procedure. The licensee entered this issue into the corrective action program as Condition Report CR- GGN -2016- 08333. The failure to implement procedures , as required by Technical Specification 5.4.1. a, was a performance deficiency. This performance deficiency was more than minor, and therefore a finding, because , if left uncorrected, the failure to implement procedures as required by Technical Specification would have the potential to lead to a more significant safety concern. Using Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process , and Inspection Manual Chapter 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, the team determined that the finding was of very low safety significance (Green ) because it did not affect the design or qualification of a mitigating system structure, system , or component and did not directly prevent the alternate decay heat removal system from maintaining its functionality. The team identified a cross -cutting aspect the area of human performance, challenge the unknown, because individuals failed 4 to stop when faced with uncertain conditions and risks were not evaluated and managed before proceeding (H.11). |
| 05000445/FIN-2017002-05 | Comanche Peak | 2017Q2 | Failure to Translate Design Requirements Into the As Built Facility | Green. The inspectors identified a non- cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, associated with the licensees failure to assure that applicable regulatory requirements and the design bases, as defined in 10 CFR 50.2 and as specified in the license application, for those structure, systems and components to which this appendix applies, were correctly translated into specifications, drawings, procedures, and instructions. Specifically, from initial construction through March 2017, the licensee failed to fully incorporate applicable moderate energy line break design requirements for fire protection piping located in the vicinity of the station service water pumps, the latter which are needed to ensure the capability to shut down the reactor and maintain it in a safe shutdown condition following a moderate energy line break. This issue does not represent an immediate safety concern because when the lines were identified the licensee took prompt action to isolate and depressurize them, and the licensee has implemented plant modifications. The licensee entered this issue into the corrective action program as Condition Report CR -2016- 008147. The failure to incorporate applicable design requirements into specifications for moderate energy line break protection was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the design control 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, from initial construction through March 2017, the licensee failed to fully incorporate applicable design requirements for components needed to ensure the capability to shut down the reactor and maintain it in a safe shutdown condition following a moderate energy line break. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, dated July 1, 2012, and Inspection Manual Chapter 0609, Appendix A, Significance Determination Process for Findings At -Power , Exhibit 2, Mitigating Systems Screening Questions, dated 5 October 7, 2016, the inspectors determined the finding required a detailed risk evaluation because the finding involved a deficiency affecting the design and qualification of a mitigating structure, system, or component, and resulted in a loss of operability, and represented an actual loss of function of at least a single train for longer than its allowed outage time. A senior reactor analysts from Region IV performed a detailed risk evaluation and determined that the bounding increase in core damage frequency for this issue was 5.1E -8/year for Unit 1 and 2.9E -10/year for Unit 2, and was therefore of very low safety significance (Green ). The inspectors did not assign a cross -cutting aspect because the performance deficiency was not reflective of present performance |
| 05000348/FIN-2017002-04 | Farley | 2017Q2 | Tornado Missile Vulnerabilities Result in Condition Prohibited by Technical Specifications | On December 7, 2016, licensee staff determined that the Unit 1 and 2 service water structure intake and exhaust ventilation hoods were not adequately protected from tornado generated missiles. On January 26, 2017, it was also identified that the emergency diesel generator fuel oil storage tank vents were not adequately protected from tornado generated missiles. Upon discovery, the on-shift Operations staff declared the service water pumps and emergency diesel generators inoperable and implemented Enforcement Guidance Memorandum (EGM) 15-002, Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance. The licensee made a non-emergency report in accordance with 10 CFR 50.72(b)(3)(ii)(B) and 10 CFR 50.72(b)(3)(v)(D) via EN# 52414. These items were entered into the licensees CAP and discussed with the resident inspectors. The inspectors reviewed this LER, EGM 15-002 and verified the licensee implemented adequate compensatory measures 19 in accordance with interim staff guidance DSS-ISG-2016-01, Clarification of Licensee Actions in Receipt of Enforcement Discretion per Enforcement Guidance Memorandum EGM 15-002. Final corrective actions to resolve these issues are pending. On December 7, 2016, licensee determined that the Unit 1 and 2 service water structure intake and exhaust ventilation hoods were not adequately protected from tornado generated missiles. On January 26, 2017, the licensee also identified that the emergency diesel generator fuel oil storage tank vents were not adequately protected from tornado generated missiles. The licensee declared the service water pumps and emergency diesel generators inoperable, implemented compensatory measures and declared the affected equipment operable but nonconforming. These issues were entered into the licensees corrective action program and discussed with the resident inspectors. The inspectors reviewed the circumstances associated with the event report and verified the licensee implemented compensatory measures consistent with interim staff guidance DSS-ISG-2016-01, Clarification of Licensee Actions in Receipt of Enforcement Discretion per Enforcement Guidance Memorandum EGM 15-002, (ADAMS ML15348A202). Because this violation was identified during the discretion period covered by Enforcement Guidance Memorandum 15-002, Revision 1, Enforcement Discretion for Tornado Missile Protection non-compliance, (ADAMS ML16355A286) and because the licensee had implemented compensatory measures, the NRC is exercising discretion (EA-17-131) and not issuing enforcement action. The enforcement discretion was applied to the required shutdown actions of the following Technical Specification (TS) LCOs for both units: TS 3.7.8, Service Water System (SWS) TS 3.8.1, AC Sources Operating Final corrective actions to resolve these issues will be addressed by the licensees corrective action program. The licensee has entered this issue into the corrective action program as condition reports 10306023 and 10322897. This LER is closed. |
| 05000334/FIN-2017002-01 | Beaver Valley | 2017Q2 | Licensee-Identified Violation | The following violation of very low safety significance (Green) was identified by FENOC and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as a NCV . TS 3.7.8, "Service Water System", requires two service water trains to be operable. There is no associated action provided for both trains inoperable. LCO 3.0.3 states, in part, that when an LCO is not met and an associated action is not provided, the unit shall be placed in a MODE or other specified condition in which the LCO is not applicable. Act ion shall be initiated within one hour to place the unit, as applicable, in M ODE 3 within 7 hours. Contrary to the above, on August 20, 2015 and August 31, 2015 , FENOC had both trains of service water inoperable for greater than 7 hours while performing the service water full flow test and did not place Unit 2 in Mode 3. FE NOC entered this issue into the CAP as CR 2017- 04023. The inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings . Because the finding represented a loss of function of a system, a detailed risk evaluation was performed. A Region I senior reactor analyst used the BVPS Unit 2 Standardized Plant Analysis Risk Model version 8.5 to perform the evaluation. A seismic initiating event frequency was obtained from the Risk Assessment of Operational Events Handbook Volume 2, External Events. A surrogate loss -of-offsite - power event was used applying the seismic initiating event frequency for BVPS with a train of service water being failed with no recovery assumed. The finding was determined to be of very low safety significance (Green) because the limited exposure time in this configuration resulted in a change in core damage frequency in the 1E -10/yr range. The dominant core damage sequence was a seismic event with failure of the EDG . |
| 05000461/FIN-2017002-06 | Clinton | 2017Q2 | Failure to Perform Preventive Maintenance on a Safety - Related Breaker Cubicl | Green . The inspectors identified a finding of very low safety significance for the licensees failure to perform maintenance on a safety -related motor control center cubicle. Specifically, the licensee failed to perform thermography on the division 1 shutdown service water pump room cooler breaker cubicle in accordance with the maintenance strategy/template without providing justification for differing from the template as required by MA AA 716 210, Performance Centered Maintenance Process , Revision 3. This resulted in the division 1 shutdown service water pump room cooler fan failing because of a high resistance connection that went undetected. The licensee entered this issue into their CAP as AR 02667822. As corrective actions, the licensee replaced the thermal overload relays and created a preventative maintenance action to perform thermography on this equipment on a periodic basis. This performance deficiency was determined to be more than minor because it impacted the Mitigating Systems cornerstone attribute of equipment performance and adversely affected the cornerstone objective of ensuring the availability, capability and reliability of equipment that responds to initiating events. Specifically , the room cooler fan failure directly impacted the operability of the division 1 shutdown service water pump and the 4 division 1 emergency diesel generator which are safety -related, risk significant systems. The finding was screened against the Mitigating Systems cornerstone and determined to be of very low safety significance because the inspectors were able to answer all of the associated screening questions No. The inspectors determined that this finding is not indicative of current plant performance and therefore did not assign a cross -cutting aspect. |
| 05000443/FIN-2017002-01 | Seabrook | 2017Q2 | Seabrook 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). |