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05000311/FIN-2018003-0130 September 2018 23:59:59SalemNRC identifiedInadequate Chiller Maintenance ProceduresThe inspectors identified a Green NCV of TS 6.8.1, Procedures and Programs, when PSEG did not properly preplan maintenance activities in accordance with written instructions appropriate to the circumstances of safety-related chiller compressor tubing repairs and installation. Specifically, PSEG installed compressor oil tubing lines without appropriate work instructions, which led to insufficient separation, and use of a nylon strap/tie to support and route two adjacent lines of tubing, causing the tubing lines to rub and fret during normal compressor operation. Consequently, on March 5, 2018, the 22 chiller compressor tripped on low oil pressure as a result of oil leakage from tube fretting.
05000311/FIN-2018003-0230 September 2018 23:59:59SalemNRC identifiedFailure to Follow Generic Letter 89-13 Program ProcedureThe inspectors identified a Green NCV of 10 CFR Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG did not adequately follow Generic Letter (GL) 89-13 program procedure steps for performing inspections of the safety-related SW piping and components. Specifically, certain American Society of Mechanical Engineers (ASME) Nuclear Class III pressure retaining components were not inspected during SW system internal pipe inspections, as required by ER-AA-340, GL 89-13 Program Implementing Procedure, Revision 8, during SW system internal pipe inspections. Consequently, protective internal coating degradation on the 21 SW supply header two-inch branch connection was not identified and corrected, which resulted in through-wall leakage and significant weld material loss due to corrosion.
05000272/FIN-2018003-0330 September 2018 23:59:59SalemLicensee-identifiedLicensee-Identified ViolationThis violation of very low safety significant was identified by PSEG, has been entered into PSEGs CAP, and is being treated as a Green NCV, consistent with Section 2.3.2 of the Enforcement Policy. Violation: 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires activities affecting quality shall be prescribed by procedures, and shall be accomplished in accordance with these procedures. PSEG procedure MA-AA-716-011, Work Execution and Closeout, Revision 17, step 4.13.5, required order operations to be completed after the preventive maintenance WO was taken Technically Complete, or TECOd. Contrary to the above, preventive maintenance WOs 30319825 and 30320738 were TECOd by mechanical maintenance, on March 2 and April 9, 2018, respectively, without completing all of the WO operations. Specifically, maintenance technicians performed the monthly thermography on the 22 chiller evaporator divider plate gasket and took the preventive maintenance work order TECO and did not perform MA-AA-716-011, step 4.13.5to complete operation 0020 by notifying engineering that the thermography results were available for review. Consequently, leakage past the divider plate gasket went undetected from March 2 to April 30, 2018, until quarterly compressor thermography detected crankcase temperature above the action level on April 30, 2018. Maintenance immediately notified Operations of the elevated compressor temperature, and the 22 chiller was declared inoperable and removed from service emergently on April 30, 2018. Subsequent disassembly and inspection revealed internal compressor damage and pieces of the evaporator divider plate gasket in the compressor filter housing. PSEG replaced the compressor and restored the 22 chiller to OPERABLE on May 4, 2018
05000272/FIN-2018002-0130 June 2018 23:59:59SalemSelf-revealingInadequate Design Change for Service Water PumpsA 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.
05000272/FIN-2018403-0130 June 2018 23:59:59SalemNRC identifiedSecurity
05000272/FIN-2018403-0230 June 2018 23:59:59SalemLicensee-identifiedLicensee-Identified Violation
05000272/FIN-2018007-0231 March 2018 23:59:59SalemLicensee-identifiedLicensee-Identified ViolationThis violation of very low safety significant was identified by the licensee and has been entered into the licensee corrective action program and is being treated as an NCV, consistent with Section2.3.2 of the Enforcement Policy.Violation:Salem Unit 2Facility Operating License Condition 2.(C).(10), in part, requires PSEG to implement and maintain in effect all provisions of the fire protection program as described in the UFSAR, as approved by the NRC. SC.ER-PS.FP-0001-A3, Salem Fire Protection Report-Safe Shutdown Analysis, Revision 0, establishes the basis for demonstrating a capability to achieve and maintain post-fire safe shutdown as described in the UFSAR, Section 9.5.1.1, Fire Protection Program. SC.ER-PS.FP-0001-A3 states that 10 CFR Part 50, Appendix R, Section III.L describes the safe shutdown requirements when an alternate or dedicated shutdown capability is provided as required in Appendix R, Section III.G.3. Appendix R, Section III.L.3, states, in part, that alternative shutdown capability shall be independent of the specific fire area. SC.ER-PS.FP-0001-A3 designates Fire Areas 2FA-AB-84A and 2FA-AB-64A as alternative shutdown areas.Contrary to the above, as of January 10, 2018, PSEG identified that the power cable that supplies power to both the Nuclear Instrumentation System Wide Range Amplifier Panel 962 and Signal Processor Panel 964 is routed through Fire Areas 2FA-AB-84A and 2FA-AB-64A without a required fire barrier and, therefore, was not independent of the specific fire area. As a result, for a fire event in either of these alternative shutdown areas, the power supply to the Unit 2 Hot Shutdown Panel Source Range and Power Range monitor could be lost and result in the loss of the neutron monitoring function. PSEG promptly implemented compensatory measures for this deficiency that included establishing a fire watch for the affected area. Because this violation was of very low safety significance (Green) and was entered into PSEGs Corrective Action Program (NOTF 20785256), this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy.Significance/Severity Level: The team performed a Phase 1 Significance Determination Process (SDP) screening, in accordance with Inspection Manual Chapter 0609, Appendix F, Fire Protection SDP, Task 1.4.5: Post-fire Safe-shutdown. This issue screened to very low safety significance (Green) because it did not affect the ability to reach and maintain a stable plant condition within the first 24 hours of a fire event. Specifically, the Hot Shutdown Panel Source Range and Power Range monitor only provides a process monitoring function for reactivity control and safe shutdown actions would be determined using reactor coolant system chemistry sampling for boron concentration. Corrective Action Reference: NOTF20785256
05000272/FIN-2018001-0131 March 2018 23:59:59SalemNRC identifiedImplementing Procedures for Beyond Design Basis FLEX Mitigating Strategies Not FollowedA Green finding was identified by the inspectors for multiple examples of PSEG not following the station specific procedures that implement the Salem and Hope Creek Generating Station (HCGS) Final Integrated Plans for Beyond Design Basis FLEX Mitigating Strategies, EM-SA-100-1000 and EM-HC-100-1000, respectively. Specifically, since compliance with the FLEX order was met on November 10, 2016, PSEG did not follow the common PSEG fleet Preventive Maintenance (PM) Process and diesel fuel oil testing program procedures, MA-AA-716-210, CY-AB-140-410, and SC.OP-LB.DF-0001 for the annual fuel oil sampling of FLEX equipment. In addition to this, between December 6, 2017, and March 8, 2018, PSEG did not follow site specific procedures for FLEX equipment unavailability and mitigation capability protection in accordance with the Salem and HCGS procedures, OP-HC-108-115-1001 and OP-SA-108-115-1001, Operability Assessment and Equipment Control Program.
05000272/FIN-2018410-0131 March 2018 23:59:59SalemNRC identifiedSecurity
05000272/FIN-2018001-0231 March 2018 23:59:59SalemSelf-revealingInadequate Procedure Step Results in Service Water Strainer TripA 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.
05000272/FIN-2018001-0331 March 2018 23:59:59SalemSelf-revealingFailure to Establish Containment Integrity during Plant StartupThe inspectors determined there was a self-revealing Green non-cited violation (NCV)of Technical Specification (TS) 6.8.1, Procedures and Programs, when PSEG did not follow procedure S1.OP-SO.SG-0002, Maintaining Steam Generators in Wet Layup, Revision 10, step 5.7.7L, to close the 14 steam generator (SG) blowdown manual nitrogen supply valves prior to entry into MODE 4 on November 7, 2017, and MODE 3 on November 9, 2017. Specifically, 14 SG blowdown manual nitrogen supply valves were left open during startup transition from MODE 5 through MODE 3 (Hot Standby), which resulted in a steam leak into the Unit 1 auxiliary building (AB) through an actual open pathway upstream of the 14 SG blowdown containment isolation valve.
05000272/FIN-2018007-0131 March 2018 23:59:59SalemNRC identifiedFailure to Perform Testing of Emergency Diesel Generator Bypass SwitchesThe team identified a finding of very low safety significance (Green) involving an NCV of Salem Unit 1 License Condition 2.C.(5) and Salem Unit 2 License Condition 2.C.(10) of the respective facility operating licenses for failure to implement and maintain in effect all provisions of the approved Fire Protection Program. Specifically, PSEG did not periodically test or check the EDG bypass switches to verify that they were capable of performing their intended design functions during safe shutdown operation in the event of a significant fire.
05000272/FIN-2017004-0231 December 2017 23:59:59SalemSelf-revealingInadequate Reactor Vessel Head Removal ProcedureThe inspectors documented a self-revealing, Green non-cited violation (NCV) of Unit 1 Technical Specification (TS) 6.8.1, Procedures and Programs, for inadequate reactor vessel (RV) head removal procedures that led to the reactor coolant system (RCS) level lowering out of the procedural band during detensioning with lowered inventory and short time-to-boil conditions. PSEGs C/As included restoring level within operating bands, completing an apparent cause evaluation, revising associated procedures and entering this matter in their CAP as NOTF 20778011The issue was more than minor since it was associated with the RCS procedural quality attribute of the Barrier Integrity cornerstone and adversely affected its objective to provide reasonable assurance that physical design barriers (i.e., fuel cladding and the RCS) protect the public from radionuclide releases caused by accidents or events. The finding was evaluated using IMC 0609, Appendix B, dated September 22, 2015, and screened to Green via IMC 0609 Appendix G, Attachment 1, dated May 9, 2014, based on not being a loss of level control, that is, an inadvertent loss of 2 feet of RCS inventory while not in mid-loop.The actual drop in level was less than one foot. The finding had a cross-cutting aspect in PI&R, Evaluation, in that PSEG did not thoroughly evaluate this issue to ensure that the resolution addressed the causes and extent of condition commensurate with its safety significance. Specifically, PSEG did not properly classify, prioritize, and evaluate the Unit 2 RCS level transient (April 2017) according to its safety significance so that the associated Unit 1 procedures were revised prior to their use during the same evolution in a subsequent RV detensioning (October 2017). (P.2)
05000272/FIN-2017004-0131 December 2017 23:59:59SalemNRC identifiedNon-conformance with the Containment Thermal Insulation System was not Identified and CorrectedThe inspectors identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations(10 CFR) Part 50, Appendix B, Criterion XVI, Corrective Action,when PSEG did not identify and correct a non-conformance with the Unit 1 containment thermal insulation system. The installed configuration did not provide a watertight seal between the containment liner and the insulation cover in conformance with the design specification. As a result, periodic SW leakage seeped behind the insulation and caused corrosion of the containment liner. PSEGs C/As included entering the issue into the CAP, repairing the portions of degraded liner, and planning to modify the top of the insulation panels to prevent water intrusion.The finding was more than minor because it was associated with the design control attribute of the Barrier Integrity cornerstone and adversely affected its objective to provide reasonable assurance that physical design barriers (i.e., containment) protect the public from radionuclide releases caused by accidents or events. The finding was evaluated using IMC 0609.04 and IMC 0609, Appendix A, Exhibit 3, dated June 9, 2012, and screened to Green because the finding did not represent an actual open pathway in the physical integrity of the reactor containment. This finding had a cross-cutting aspect of Problem Identification and Resolution (PI&R), Identification, because PSEG did not implement a CAP with a low threshold for identifying issues where individuals identify issues completely, accurately, and in a timely manner in accordance with the program. (P.1)
05000272/FIN-2017007-0130 September 2017 23:59:59SalemNRC identifiedInadequate Design Verification that Inter-Cabinet Bolts were Installed between SEC and Bailey CabinetsThe team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, because between May 1995 to July 2017, PSEG did not verify that bolts, or other suitable connections, were installed to connect the safeguard equipment control (SEC) cabinets to the Bailey termination cabinets to satisfy the Seismic Qualification Utilities Group (SQUG) recommended method to resolve effects of potential cabinet interaction during a seismic event. PSEGs immediate corrective actions included initiating several corrective action notifications (NOTFs) to evaluate operability, extent-of-condition, and long-term resolution. This issue is more than minor because it is associated with the Design Control attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, PSEG performed a SQUG evaluation in response to unresolved safety issue (USI) A-46, Verification of Seismic Adequacy of Mechanical and Electrical Equipment in Operating Reactors, and submitted the results to the NRC detailing a potential for SEC cabinet seismic interaction with the adjacent Bailey termination cabinet. The evaluation results recommended bolting the SEC cabinet to the Bailey cabinet to eliminate the interaction. However, PSEG did not ensure and verify that the SQUG recommended bolts were installed, which resulted in a reasonable doubt on the operability of the SEC to reliably perform its intended function during and following a design basis seismic event. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, the team determined that this finding was Green because it was a design deficiency that potentially affected the design or qualification of a mitigating system, however, the mitigating system maintained its operability. The team determined there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance.
05000272/FIN-2017007-0230 September 2017 23:59:59SalemNRC identifiedInadequate PM for the EDG Room Ventilation SystemThe team identified a Green non-cited violation of Technical Specification (TS) 6.8.1, Procedures and Programs, because since January 2007, PSEG did not establish an appropriate preventive maintenance (PM) schedule for the emergency diesel generator (EDG) ventilation dampers. Specifically, PSEG cancelled a pre-existing 36-month lubrication/clean/inspect PM in 2007 but failed to add the lubrication task to an existing 6-year damper PM as intended. As a result, since January 2007, the intended lubrication PM was cancelled for the inlet, recirculation, and exhaust ventilation dampers on all six Unit 1 and Unit 2 EDG ventilation systems. PSEGs immediate corrective actions included initiating a corrective action NOTF to address the PM inadequacy and extent-of-condition. The issue is more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, the removal of the EDG ventilation damper lubrication PM had the potential to adversely impact EDG reliability. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, the team determined that this finding was Green because it was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent the actual loss of a safety function of a single train for greater than its TS allowed outage time, and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in PSEGs Maintenance Rule program for greater than 24 hours. The team determined there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance.
05000272/FIN-2017003-0130 September 2017 23:59:59SalemNRC identifiedExpiration of Periodic Inservice Testing of 14 Service Water PumpInspectors 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.
05000272/FIN-2017007-0330 September 2017 23:59:59SalemNRC identifiedInadequate Corrective Action Regarding Missed Periodic Inspection of 2C EDG AVR CardThe team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because between April 2008 and July 2017, PSEG failed to promptly identify and correct a condition adverse to quality associated with an automatic voltage regulator (AVR) card installed in the 2C EDG. Specifically, PSEG corrective actions in response to a 2007 MPR Associates Part 21 report did not ensure that the 2C EDG was not susceptible to undesired voltage fluctuations associated with an aged-related defect in the installed AVR card. PSEGs immediate corrective actions included initiating a corrective action NOTF to evaluate operability and prioritize scheduling AVR card replacement. The issue is more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, without further inspection of the 2C EDG AVR card solder joints, cracks could form in the solder joint connections resulting in undesired voltage fluctuations and potentially preclude the 2C EDG from performing its safety function. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, the team determined that this finding was Green because it was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent the actual loss of a safety function of a single train for greater than its TS allowed outage time, and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in PSEGs Maintenance Rule program for greater than 24 hours. The team determined the finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Self-Assessment, because PSEG did not conduct self-critical and objective assessments of its programs and practices. Specifically, PSEGs pre-inspection self-assessment in May 2017 reviewed PSEGs corrective actions for the MPR Associates Part 21 Report, but did not identify the missed periodic refueling cycle inspections of the 2C EDG AVR card.
05000272/FIN-2017003-0230 September 2017 23:59:59SalemNRC identifiedViolation of Containment Integrity Technical SpecificationThe inspectors identified a Green non-cited violation (NCV) of Technical Specifications (TS) Limiting Condition for Operation (LCO) 3.6.1.1, Containment Integrity,when PSEG did not ensure that the APD backup CIVs, associated with penetrations required to be closed during accident conditions, were unisolated intermittently under appropriate administrative controls. Specifically, manual CIVs associated with the APD sampling system were opened and left continuously open for 27 days, under tagging instructions that would have resulted in an actual open penetration outside of containment during certain design basis accidents and PSEG had not evaluated the adequacy of the tagging instruction to ensure radiological dose consequences would remain in conformance with the licensing basis. PSEG entered this issue in the Corrective Action Program (CAP) as notifications (NOTFs) 20751423 and 20777663. Technical Specification (TS) compliance was restored on January 4, 2017, when PSEG restored the normal air APD sample valve configuration. 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 release cause by accidents or events. Using Appendix H, the inspectors determined this finding was of very low safety significance, or Green, because this was a Type B finding (Section 4.0), involving small diameter lines that were not important to large early release frequency (LERF), as described in Table 4.1. The finding had a cross-cutting aspect in the area of Human Performance, Work Management, in that the organization implements a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. Specifically, the planned tagging instructions for control of the back-up sampling valves did not ensure the work activity was controlled and executed in accordance with TS. (H.5)
05000272/FIN-2017003-0330 September 2017 23:59:59SalemSelf-revealingFailure to Follow Maintenance Procedureto Assure Proper Installation of Service Water Check ValveA 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-2017002-0230 June 2017 23:59:59SalemLicensee-identifiedLicensee-Identified ViolationTS 3.3.1.1 requires that the reactor trip system instrumentation shown in Table 3.3- 1 shall be operable. Table 3.3- 1, Function 14, states there are a total of three channels , per S/G loop, of the water level low -low instrumentation. Action 6 states, in part, with the number of operable channels less than the total number of channels, the inoperable channel is to be placed in the tripped condition within 6 hours. Contrary to TS 3.3.1.1, one less than the total number of channels of S /G water level low -low was inoperable from August 19, 2013, until October 10, 2014, without being placed in the tripped condition. The condition was a licensee- identified violation because it was identified by operators in the main control room. Additional details are provided in the closure documentation for LER 05000272/2015- 002 -02 in report Section 4OA3.2 . This performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating System cornerstone, and adversely affected the cornerstone objective of ensuring the reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the finding was of very low 23 safety significance (Green) in accordance with the screening criteria found in IMC 0609, Attachment 4, and Appendix A, Exhibit 2 . PSEG entered this issue into the CAP as NOTF 20682366. Because the finding was of very low safety significance (Green) and was entered into PSEGs CAP, this issue is being treated as an NCV consistent with Section 2.3.2.a of the NRCs Enforcement Policy.
05000272/FIN-2017002-0130 June 2017 23:59:59SalemLicensee-identifiedLicensee-Identified Violation10 CFR 50.54(q)(2) states, in part, that the licensee shall follow and maintain the effectiveness of an emergency plan that meets the requirements in Appendix E to this part. Appendix E. IV.C.2, states, in part, that licensees shall establish and maintain the capability to assess, classify, and declare an emergency condition within 15 minutes after the availability of indications to plant operators that an emergency action level (EAL) has been exceeded and shall promptly declare the emergency condition as soon as possible following identification of the appropriate emergency classification level. Contrary to the above, on April 20, 2017, at 8:27 p.m., when the SM was informed of the presence of toxic gas (hydrazine) causing work stoppage and evacuation in the Salem Unit 2 containment, he did not promptly declare an emergency in accordance with the Salem EALs. The SM declared an Unusual Event, based on EAL HU.3.1, toxic gas that has adversely affected normal plant operations, at 9:10 p.m. (43 minutes after he had indications that the EAL was exceeded). PSEG identified that the emergency was not declared within the 15 minute requirement during a post -event review. This performance deficiency was more than minor because it was associated with the ERO performance attribute of the Mitigating System cornerstone, and adversely affected the cornerstone objective of ensuring that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. The inspectors determined that the finding was of very low safety significance (Green) in accordance with IMC 0609, Appendix B, Figure 5.4 -1, because the Unusual Event was declared in a degraded or untimely manner. PSEG entered this issue into the CAP as NOTF 20763130. Because the finding was of very low safety significance (Green) and was entered into PSEGs CAP, this issue is being treated as an NCV consistent with Section 2.3.2.a of the NRCs Enforcement Policy
05000272/FIN-2017001-0431 March 2017 23:59:59SalemLicensee-identifiedLicensee-Identified Violation

TS LCO 3.3.2.1 requires the ESFAS instrumentation channels and interlocks shown in Table 3.3-3 shall be operable. Table 3.3-3, Function 1.d, pressurizer pressure-low, requires that with the number of operable channels one less than the total number of operable channels in Modes 1, 2, and 3 (at and above the P-11 setpoint, or 1925 psig), startup and/or power operation may proceed provided that the inoperable channel is placed in the tripped condition within 6 hours.

TS LCO 3.3.3.1 requires the reactor trip system instrumentation channels and interlocks of Table 3.3-1 shall be operable. Table 3.3-1, Functions 7 (OTDT), 8 (pressurizer pressure low), and 9 (pressurizer pressure high), require that with the number of operable channels one less than the total number of operable channels in Modes 1 and 2, startup and/or power operation may proceed provided that the inoperable channel is placed in the tripped condition within 6 hours.

TS LCO 3.4.3 requires, in part, that two PORVs shall be operable in Modes 1, 2, and 3. Action b requires, in part, that with one PORV inoperable, within 1 hour either restore the PORV to operable status or close its associated block valve and remove power from the block valve; restore the PORV to operable status within the following 72 hours or be in hot standby within the next 6 hours and in hot shutdown within the following 6 hours

TS 3.0.4, Applicability, states, in part, that when a limiting condition for operation is not met, entry into a Mode or other specified condition in the Applicability shall only be made when the associated Actions to be entered permit continued operation in the Mode or other specified condition in the Applicability for an unlimited period of time; or after performance of a risk assessment addressing inoperable systems and components and establishment of risk management actions

05000272/FIN-2017403-0131 March 2017 23:59:59SalemLicensee-identifiedLicensee-Identified Violation
05000272/FIN-2017001-0131 March 2017 23:59:59SalemNRC identifiedLoss of Unit 1C 4kV Vital Bus due to Inadequate Activity Risk ScreeningA self-revealing Green finding (FIN) was identified when PSEG did not screen the risk associated with replacing the Unit 1C emergency diesel generator (EDG) output breaker in accordance with WC-AA-105, "Work Activity Risk Management." Specifically, on December 14, 2016, the Unit 1C 4 kilovolt (kV) vital bus was inadvertently de-energized when the Unit 1 C EDG output breaker, which was removed without adequate risk mitigation actions, made contact with the switchgear (SWGR) cubicle door containing relays for bus differential current protection. PSEG entered this issue into their corrective action proggram (CAP) as NOTF 20751669 and performed apparent cause evaluation (ACE) 70191319. PSEG's corrective actions (CA) included inspecting the involved relay and re-energizing the vital bus. The finding was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerston's objective of ensuring the availability, reliability, and capability of systems relied upon to mitigate the consequences of an accident. The inspectors evaluated the finding in accordance with IMC 0609, Appendix A, Exhibit 2, and determined the finding was Green because it did not affect the design of qualification of a mitigating SSC, and did not represent an actual loss of function or system. The finding had a cross cutting aspect in the area of Human Performance, Work Management, because the work process did not include the identification and management of risk commensurate to the work and the need for coordination with different groups or job activities. Specifically, PSEG did not identify the level of medium risk associated with the work activity, did not manage the level of risk commensurate wiht the work, and did not coordinate appropriate mitigating actions with different work groups.
05000272/FIN-2017001-0231 March 2017 23:59:59SalemSelf-revealingInadequate Fire Risk Assessment and ManagementInspectors identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(a)(4) when PSEG did not adequately assess and manage the risk of online maintenance activities associated with the 13 and 23 charging (CV) positive displacement pumps (PDPs) and the 16 service water (SW) pump. Consequently, this resulted in the approval of hot work and the introduction of unaccounted for transient combustibles into a restricted fire area. PSEG wrote notifications (NOTFs) 20758370, 20759221, and 20761411 to document the observations and fire risk program gaps. On March 9, a roving fire watch was implemented as previously planned by PSEG. The finding was more than minor given its similarity to IMC 0612, Appendix E, example 7.e, in that had an adequate risk assessment been performed, it procedurally would have required additional risk management actions (RMAs). Additionally, this finding was more than minor because it adversely impacted the protection against external factors (fire) attribute of the Initiating Events cornerstone objective to limit the likelihood of events that upset plan stability and challenge critical safety functions during shutdown as well as power operations. The inspectors evaluated the finding in accordance with IMC 0609, Attachment 4 and Appendix K, since it involved a maintenance rule (MR) risk assessment. Since the performance deficiency was related to maintenance activities affecting structures, systems, and components (SSCs) needed for fire mitigation, Appendix K directed the significance to be determined by an internal NRC management review using risk insights. A Senior Reactor Analyst used risk insights from IMC 0609, Appendix F and its Attachment 2, to inform the significance and determined the issue screened to Green given that the combustible conditions and quantities were predominantly representative of a Low degradation rating.
05000272/FIN-2017001-0331 March 2017 23:59:59SalemSelf-revealingFailure to Conduct Post-Maintenance Testing Required by Procedure and Work Order Resulting in Inoperable Containment Fan Coil UnitsGreen. A self-revealing Green non-cited violation (NCV) of Technical Specification (TS) 6.8.1, Procedures and Programs; TS 3.6.2.3, Containment Cooling Fans; TS 3.6.1.1, Primary Containment Integrity; and TS 3.0.4, Applicability, was identified. Specifically, PSEG did not perform a specified post-maintenance test (PMT) after replacing the air supply valve for service water (SW) system accumulator discharge valve 11SW535. As a result, valve 11SW535 failed its subsequent technical specification (TS) required stroke time to close surveillance, and rendered two of the five containment fan coil units (CFCUs) inoperable. PSEG entered this issue in the corrective action program (CAP) as NOTF 20736868 and completed corrective actions (CAs) included coaching the senior operator involved in closing the work order (WO) without ensuring the PMT was completed and a review of similar retest activities (no additional deficiencies identified). This issue was more than minor because it was associated with the human performance attribute of the Mitigating Systems corner stone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the incomplete PMT resulted in a delay in identifying a degraded stroke time and resultant inoperability of two CFCUs. The inspectors determined that this finding was Green in accordance with IMC 0609, Appendix A, Exhibit 2, because the finding did not result in an actual loss of function of a system or train. The finding had a cross-cutting aspect in the area of Human Performance, Work Management, because the organization did not implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. Specifically, PSEG did not execute WO instructions to conduct the appropriate PMT following maintenance on an air supply valve for SW accumulator discharge valve 11SW535, which resulted in 11SW535 stroking closed too fast and required declaring two CFCUs inoperable. (H.5)
05000272/FIN-2016004-0131 December 2016 23:59:59SalemSelf-revealingInadequate Maintenance Procedure for Steam Generator Feedwater Pump Coupling Hub Set Screw InstallationGreen: A self-revealing Green finding (FIN) against MA-AA-716-010, Maintenance Planning Process, step 4.2.3, Revision 18, was identified for PSEGs inadequate maintenance guidance that resulted in 11 steam generator feedwater pump (SGFP) elevated vibrations and required an emergent down power to be taken out of service due to a coupling and shaft failure. PSEG entered this issue in their CAP as notification (NOTF) 20739299, conducted a prompt investigation, troubleshooting, repairs, and a completed a causal evaluation under Order 70189096. This issue was more than minor since it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely impacted its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened to Green in accordance with IMC 0609, Appendix A, because the finding did not represent an actual loss of function of one or more non-TS equipment trains designated as high safety-significant in accordance with PSEGs Maintenance Rule (MR) program. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Operating Experience (OE), because PSEG did not ensure that the organization systematically and effectively collects, evaluates, and implements relevant internal and external operating experience in a timely manner. (P.5)
05000311/FIN-2016004-0231 December 2016 23:59:59SalemNRC identifiedInadequate Surveillance Test Procedure Results in Water Hammer and Reactor TripGreen. The inspectors determined there was a self-revealing Green non-cited violation (NCV) of Technical Specification (TS) 6.8.1.c, Surveillance and test activities of safety-related equipment, when PSEG did not establish adequate procedures for restoring service water (SW) to a drained section of discharge piping from the containment fan coil unit (CFCU) following surveillance test activities. Consequently, during restoration of SW to 22 CFCU following testing on August 31, 2016, refilling the voided SW piping created a pressure pulse sufficient to extrude the motor cooler cover plate spacer gasket inside primary containment, resulting in leakage that caused a 21 reactor coolant pump (RCP) cable fault and subsequent reactor trip. PSEG entered the issue in the corrective action program (CAP), performed a root cause evaluation (RCE), and revised applicable procedures for filling and venting SW to the CFCUs on September 19, 2016. This issue was more than minor since it was associated with the procedure quality attribute of the Initiating Events cornerstone and adversely impacted its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions. Using IMC 0609, Attachment 4 and Appendix A, Exhibit 1, the inspectors determined that this finding was of very low safety significance, or Green, since mitigating equipment relied upon to transition the plant to stable shutdown remained available. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because PSEG did not thoroughly evaluate previous CFCU motor cooler gasket leaks such that the resolution addressed the cause. (P.2)
05000272/FIN-2016004-0331 December 2016 23:59:59SalemLicensee-identifiedLicensee-Identified ViolationThe following PSEG-identified violation of NRC requirements was determined to be of very low safety significance (Green) and meet the NRC Enforcement Policy criteria for being dispositioned as an NCV. As a result of a Salem Post-Fire Safe Shutdown Analysis update, PSEG submitted LER 272/1999-009-00 when they identified that cables for pressurizer PORVs and associated block valves were routed in the same containment cable trays, a fire-induced spurious operation concern, that could result in a pathway for a loss of reactor coolant inventory and pressure control. A similar condition was also identified for a fire in the control or relay rooms that could affect alternate shutdown capability. The NRC dispositioned this issue in IR 05000272;311/1999-010. On August 26, 2015, PSEG identified that they had not adequately completed corrective actions associated with the relay rooms. Specifically, a fire scenario involving cables within cabinets existed that could result in spurious PORV operation while preventing the ability to manually close block valves. At the time of this discovery, the safe shutdown analysis did not include the evaluations required to credit closure of both PORVs and block valves in the main control room prior to evacuation. Local, manual closure of the block valves had been incorporated into procedures but could be delayed up to 40 minutes in the scenario while EDGs were restored. The loss of reactor coolant inventory and pressure control had not been accounted for during this timeframe. The issue was determined to be more than minor since it was associated with the protection against external factors (Fire) attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was evaluated in accordance with IMC 0609, Appendix A, Attachment 4, and Appendix F. The IMC 0609, Appendix F, Attachment 1, Step 1.6, permits screening of the issue with PSEG fire PRA results provided there is an approved fire PRA for the plant. PSEG provided a fire PRA evaluation for the degraded condition but since the PRA results were not from a finalized, approved fire PRA, additional evaluation was required. The Senior Reactor Analyst (SRA) conducted a detailed assessment of the issue using the External Initiator Risk Informed Inspection Notebook for Salem Generating Station (Revision 1). Fires of concern were determined to be those confined to the Unit 1 and Unit 2 Relay Rooms. This is modeled in table 3.3.13 of the notebook as Fire Group M. For evaluation, it was assumed that Spurious PORV Due to Hot Short had a probability of 1.0. For this model, this would indicate a condition in which a PORV and its associated block valve were open. Given the exposure period of greater than 30 days, this would result in a change in core damage frequency of approximately 1E-8, Green, for Unit 1 and Unit 2. The notebook was conservative since the evaluation assumed the failure of the PORV to close as opposed to the more realistic probability that fire would cause a spurious failure of a PORV and hot short resulting in failure of the block valve. The dominant sequences included: 1) Fire in the relay room with a failure of the PORV to close and a failure of high pressure injection and 2) Fire in the relay room with a failure of the PORV to close and a failure of high pressure recirculation. PSEGs results were consistent with the SRAs analysis. Title 10 CFR Part 50, Appendix B, Criterion XVI, requires, in part, that conditions adverse to quality are promptly identified and corrected. Salem Unit 1 and 2 license conditions 2.(C).5 and 2.(C).10 respectively require, in part, that PSEG shall implement and maintain all provisions of the fire protection program. PSEGs Quality Assurance Topical Report states that the Quality Assurance Program is applied to the Fire Protection Program consistent with Branch Technical Position APCSB 9.5-1 Appendix A, Section C requirements that include, under Corrective Action, that conditions adverse to fire protection are promptly identified, reported, and corrected. Contrary to this, from about 1999 to August 2015, actions from a previous, related fire-induced circuit failure scenario did not completely correct the condition resulting in the inability to credit manual closure of PORV and PORV block valves in an associated fire scenario. PSEG entered this in their CAP as NOTFs 20700943 and 20750010.
05000272/FIN-2016404-0130 September 2016 23:59:59SalemNRC identifiedSecurity
05000311/FIN-2016404-0230 September 2016 23:59:59SalemNRC identifiedSecurity
05000272/FIN-2016003-0130 September 2016 23:59:59SalemSelf-revealingMisclassification of and Lack of Preventative Maintenance for SWC Valve 2GW75 and Relay S62-C1The inspectors documented a self-revealing, Green finding (FIN) because PSEG did not classify plant equipment in accordance with procedure ER-AA-1001, Component Classification, Revision 0, step 4.5. Specifically, PSEG did not appropriately classify a valve and relay within the stator water cooling (SWC) system, and subsequently did not perform the appropriate periodic maintenance. As a result of the absence of maintenance, the valve developed a packing leak, which dripped onto the trip relay and caused the relay to internally fill with water. On February 14, 2016, the trip relay contacts experienced an electrical short, which led to a turbine trip and a reactor trip from 100 percent power. PSEG entered this issue into the corrective action program (CAP) under notifications 20720566 and 20745264, performed apparent cause evaluation (ACE) 70184453, replaced the failed relay, and repaired the packing leak on the SWC valve. The inspectors determined that a performance deficiency existed because PSEG did not properly classify the SWC relay and valve in accordance with station procedures to ensure the components would receive the appropriate preventive maintenance (PM). The finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone and adversely impacted its objective to limit the likelihood of events that upset plant stability (main generator and turbine trip) and challenge critical safety functions. Using IMC 0609, Attachment 4 and Appendix A, Exhibit 1, the inspectors determined that this finding was of very low safety significance, or Green, since mitigating equipment relied up to transition the plant to stable shutdown remained available. The inspectors determined there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance.
05000272/FIN-2016003-0230 September 2016 23:59:59SalemLicensee-identifiedLicensee-Identified Violation10 CFR 72.150 requires that each licensee shall prescribe activities affecting quality by documented instructions, procedures, or drawings of a type appropriate to the circumstances and shall require that these instructions, procedures, and drawings be followed. Holtec HI-STORM Certificate of Compliance 72-1014 Amendment 5, Final Safety Analysis Report for the HI-STORM 100 Cask System, Revision 7, Section 2.1.9.1.2, specifies the required helium backfill pressure range for loaded canisters. Contrary to the above, PSEG selected the incorrect helium backfill pressure range table in Attachment 9 of SC.MD-FR.DCS-0006(Q), Sealing, Drying, and Backfilling of a loaded multi-purpose canister (MPC) for two MPCs, one on June 20, 2016, and the other on June 25, 2016. The NRC inspectors evaluated this violation as having very low safety significance because a thermal analysis performed by Holtec determined the resulting fuel cladding temperatures and the cask/MPC component temperatures would not exceed the applicable design limits for normal long-term storage with the current helium pressure. In accordance with the NRC Enforcement Policy Section 2.2, Part 72, Independent Spent Fuel Storage Installation inspection findings follow the traditional enforcement process and are not dispositioned through the reactor oversight process or the significance determination process. The violation was determined to be a Severity Level IV violation of the NRC requirements. The licensee entered the issue into their CAP as NOTF 20735208. This Severity Level IV violation was treated as a NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. CAs for this issue included the Holtec thermal analysis and a revision of the MPC loading procedure SC.MD-FR.DCS-0006, Sealing, Drying, and Backfilling of a Loaded MPC.
05000311/FIN-2017009-0130 September 2016 23:59:59SalemSelf-revealingFailure to Follow Troubleshooting Procedure for BIT Relief Valve LeakageAnalysis. The inspectors determined that PSEG's performance of activities on the HHSI system that were beyond those documented in the approved troubleshooting instructions was a performance deficiency that was reasonably within PSEG's ability to foresee and correct, and should have been prevented. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating System cornerstone in Inspection Manual Chapter (IMC) 0305, "Operating Reactor Assessment Program," and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure to execute the troubleshooting plan as written resulted in HHSI system inoperability and adversely affected the availability, reliability, and capability of both trains of the HHSI. This performance deficiency required a detailed risk evaluation (ORE) in accordance with IMC 0609, "Significance Determination Process," Appendix A, screening questions in Exhibit 2, "Initiating Events," because the finding affected other systems used to mitigate a loss of coolant accident (LOCA), namely high head safety injection. Specifically, due to a failure of the 2SJ1 0, the 2SJ4 and 2SJ5 valves were de-energized, isolating HHSI. Operators declared both trains of HHSI inoperable which resulted in a loss of the high head safety function. The inspectors and a Region I Senior Reactor Analyst (SRA) conducted a bounding ORE and determined this finding to be of very low safety significance (Green). The leakage was determined to be sufficiently below the leak rate bounding a small break LOCA and the risk of the leak itself was considered to be minimal. The impact on the loss of HHSI system was evaluated using the Salem Standardized Plant Analysis model with both trains of HHSI out-ofservice, assuming at power operations, and resulted in a core damage frequency risk increase of less than 1 E-6. This was due in large part to the short exposure period of the degraded condition. Recognizing that the unit was shutdown and coming out of an outage with very little decay heat, the actual risk of core damage was considerably lower and the potential for impacts from a large early release was negligible. In accordance with IMC 0310, "Aspects Within Cross Cutting Areas," this finding had a crosscutting aspect in the area of Human Performance, Procedure Adherence, in that individuals did not follow processes, procedures, and work instructions. Specifically, PSEG operators in the field performed actions outside of the written instructions while performing troubleshooting activities in the field to investigate lowering pressure in the Unit 2 BIT. (H.8) Enforcement. TS 6.8.1, "Procedures and Programs," states, in part, that "written procedures shall be established, implemented and maintained covering the applicable procedures recommended in Appendix 'A' of Regulatory Guide (RG) 1.33, Revision 2, February 1978." RG 1.33, Section 9, "Procedures for Performing Maintenance," states, in part, that "maintenance that can affect the performance of safety-related equipment should be properly preplan ned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances." MA-AA-716-004, "Conduct of Troubleshooting," Revision 12, is one administrative procedure controlling the conduct of maintenance involving troubleshooting that can affect the performance of safety-related equipment. Step 4.1.4 of MA-AA-716-004, states that any need for changes to an approved troubleshooting plan requires that the plan be revised and reapproved. Work is to be stopped in the field until the plan is revised and reapproved. Contrary to the above, on November 23, 2015, PSEG did not properly implement procedures related to the performance of maintenance involving troubleshooting of a safety-related system. Specifically, while troubleshooting the Unit 2 BIT and its associated relief valve (2SJ1 0), PSEG personnel did not follow procedure MA-AA-716-004 when changes to the approved troubleshooting plan were implemented. The 2SJ1 0 relief valve was mechanically agitated in the field without stopping work in the field to revise and reapprove the documented instructions in the troubleshooting plan. Mechanically agitating the 2SJ1 0 relief valve outside of the documented instructions in the troubleshooting plan resulted in increased RCS leakage that exceeded the TS limit for unidentified RCS leakage and Unusual Event entry criterion and caused TS inoperability of both trains of the HHSI. PSEG operators immediately isolated the RCS leak, and declared both trains of high head safety injection inoperable, entered TS 3.0.3, and conducted a cooldown to Mode 5. PSEG entered this in their corrective action program (CAP) as 20711368, performed a prompt investigation, and commenced an apparent cause evaluation. Because this finding was of very low safety significance and was entered into PSEG's CAP, this violation is being treated as an NCV consistent with Section 2.3.2.a of the NRC's Enforcement Policy. (NCV 05000311/2017009-01, Failure to Follow Troubleshooting Procedure for BIT Relief Valve Leakage)
05000311/FIN-2016002-0230 June 2016 23:59:59SalemNRC identifiedWithdrawn - Failure to Follow Operability Determination Procedure for Unit 2 Baffle-Former BoltsThe inspectors identified a 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," because, from June 15, 2016 until July 26, 2016, PSEG did not accomplish actions necessary to provide adequate confidence that a structure, system, and component (SSC) would perform satisfactorily in service (an activity affecting quality) as prescribed by a documented procedure. Specifically, although PSEG had concluded Salem Unit 2 is susceptible to baffle bolt failure due to its design and operating life (but less susceptible than Salem Unit 1), PSEG inadequately implemented Procedure OP-AA-108-115, "Operability Determinations & Functionality Assessments," Sections 4.7.14 followed by Sections 4.7.18-4.7.20 to perform an operability evaluation (OpEval) to justify continued operation of the unit until the next refueling outage. PSEGs immediate corrective actions included entering the issue into its corrective action program (NOTF 20736630) and documenting an operability evaluation to support the basis for functionality of the baffle structure and the operability of the emergency core cooling system (ECCS) and reactivity control systems. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, in that degradation of a significant number of baffle bolts could result in baffle plates dislodging following an accident. This issue was dispositioned as more than minor because it was also similar to example 3.j of IMC 0612, Appendix E, Examples of Minor Issues, in that the condition resulted in reasonable doubt of operability of the ECCS and additional analysis was necessary to verify operability. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors screened the finding for safety significance and determined it to be of very low safety significance (Green), since the finding did not represent an actual loss of system or function. After inspector questioning, PSEG performed OpEval 2016-015, which provided sufficient bases to conclude the Unit 2 baffle assembly would support ECCS and control rod system operability until the next refueling outage. This finding is related to the cross-cutting aspect of Operating Experience because PSEG did not effectively evaluate relevant internal and external operating experience. Specifically, PSEG did not adequately evaluate the impact of degraded baffle bolts in Unit 2 when directly relevant operating experience was identified at Unit 1.
05000311/FIN-2016002-0430 June 2016 23:59:59SalemLicensee-identifiedLicensee-Identified ViolationTS LCO 3.3.2.1 requires the ESFAS instrumentation channels and interlocks shown in Table 3.3-3 shall be operable. Table 3.3-3, Function 8, requires two channels of AFW automatic actuation logic to be operable in Modes 1, 2, and 3. With the number of operable channels one less than the required number of channels, TS LCO 3.3.2.1 requires the inoperable channel to be restored to operable status within 6 hours or, be in at least Hot Standby within the next 6 hours and in at least Hot Shutdown within the following 6 hours. Contrary to TS LCO 3.3.2.1, one less than the required number of channels of AFW automatic actuation logic were operable from April 20, 2015, until Unit 2 entered Mode 4 for a scheduled refueling outage on October 23, 2015. This was due to the 21 AFW pump loop time response being greater than the allowed TS value because the isolation valve for the pressure override defeat pressure transmitter was in the closed position. PSEG entered this issue into the CAP as NOTFs 20709417, 20716352, 20710947, and 20711796. This performance deficiency was more than minor because it was associated with the human performance attribute of the Mitigating System cornerstone, and adversely affected the cornerstone objective of ensuring the reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated this finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2. The inspectors determined that the finding was of very low safety significance (Green) because the finding did not represent an actual loss of function of at least a single train for greater than its TS allowed outage time.
05000272/FIN-2016002-0130 June 2016 23:59:59SalemNRC identifiedBaffle-Former Bolts with Identified AnomaliesThe inspectors determined the level of degradation of Unit 1 baffle bolts reported to the NRC as a condition not previously analyzed is an issue of concern that warrants additional inspection to determine whether a performance deficiency exists. As a result, the NRC opened a unresolved item (URI). Additional inspection is warranted to determine whether a performance deficiency exists related to Event Notification 51902, dated May 3, 2016, in which PSEG reported to the NRC that the level of degradation of baffle bolts was a condition not previously analyzed. The baffle bolts secure plates in the reactor core barrel to form a shroud around the fuel core to direct reactor coolant flow upward through the fuel assemblies. In order to determine if a performance deficiency exists, the inspectors will review the results of PSEGs RCE which will be completed at a later date.
05000311/FIN-2016002-0330 June 2016 23:59:59SalemSelf-revealingInadequate Work Order Planning Results in Main Generator AVR STV Relay TripA Green, self-revealing finding (FIN) was identified against MA-AA-716-010, Maintenance Planning Process, Revision 18, when PSEG work orders (WOs) did not specify the appropriate procedure to perform satisfactory modification testing of the main generator automatic voltage regulator (AVR) protective relay (model STV1). Consequently, the relay actuated below its design setpoint on February 4, 2016, resulting in an automatic trip of the Unit 2 main turbine and reactor. PSEG entered the issue in their Corrective Action Program (CAP) and performed a root cause evaluation (RCE), replaced the failed STV1 relay with a properly tested relay, verified other STV relays were appropriately tested as an extent of condition, and initiated an action to revise Laboratory Testing Services (LTS) department relay test procedures to ensure all applicable acceptance criteria will be incorporated. The inspectors determined that a performance deficiency existed because PSEG WOs did not specify the appropriate procedure to perform satisfactory modification testing of the main generator AVR protection relay. This issue was more than minor since it was associated with the procedure quality attribute of the Initiating Events cornerstone and adversely impacted its objective to limit the likelihood of events that upset plant stability (turbine and reactor trip) and challenge critical safety functions. Using IMC 0609, Attachment 4 and Appendix A, Exhibit 1, the inspectors determined that this finding was of very low safety significance, or Green, since mitigating equipment relied up to transition the plant to stable shutdown remained available. The finding had a cross-cutting aspect in the area of Human Performance, Work Management, in that the PSEG did not adequately implement the work process to coordinate with engineering and maintenance departments as needed to appropriately plan the STV1 relay modification test WO.
05000272/FIN-2016001-0131 March 2016 23:59:59SalemSelf-revealingFailure to Correct Chiller Failures due to Gasket LeakageA self-revealing Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, was identified when PSEG did not assure that an identified condition adverse to quality was corrected. Specifically, PSEG closed a corrective action to address chiller gasket leakage without performing the designated action. This resulted in four subsequent chiller trips due to gasket failures. PSEG entered this issue in the CAP under notification 20708693, and completed ACE 70181604 on December 21, 2015. Corrective actions from the ACE were completed on February 25, 2016, and included: obtaining the proper gasket material; testing an alternative gasket material (Teflon); and establishing interim performance monitoring under Order 80115963. The inspectors determined that closing a corrective action to correct a condition adverse to quality evaluated by an ACE without implementing the corrective action was a performance deficiency. This performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating System cornerstone, and adversely affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences, in that safety-related chillers were subsequently rendered inoperable as a result of not having the proper gasket material. The inspectors determined that this finding screened to Green in accordance with IMC 0609, Appendix A, because the finding did not represent an actual loss of function of at least a single train for greater than its technical specification allowed outage time. The inspectors determined that this finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, because PSEG did not take effective corrective action to address recurring chiller evaporator head gasket leaks in a timely manner.
05000311/FIN-2016001-0231 March 2016 23:59:59SalemSelf-revealingInadequate Digital Feedwater Design Change EvaluationA self-revealing Green finding against procedure CC-AA-103, Configuration Change Control for Permanent Physical Plant Changes, Revision 15, was identified when PSEG did not adequately evaluate a modifications effect on existing design and operating margins. Specifically, an Advanced Digital Feedwater Control System (ADFCS) modification introduced a steam generator feedwater pump (SGFP) over-acceleration trip feature that was not evaluated and resulted in a SGFP trip and auxiliary feedwater (AFW) actuation. PSEG corrective actions included re-establishing main feedwater, making a report to the NRC via ENS 51738 for the AFW actuation, and entering this in their Corrective Action Program (CAP) as 20718519. The inadequate evaluation of the ADFCS modifications effect on existing design and operating margins was a performance deficiency. The issue was determined to be more than minor since it was similar to IMC 0612, Appendix E, example 3b in that the design was not correctly translated and resulted in system operation being adversely affected by a SGFP trip and an AFW system actuation. It was also more than minor since it was associated with the design control attribute (plant modification) of the Initiating Events cornerstone and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions. The finding was evaluated in accordance with IMC 0609, Attachment 4 and Appendix A, where it was screened to Green since the transient did not result in both a reactor trip and loss of mitigation equipment relied upon to transition the plant from the onset of a trip to a stable shutdown condition (loss of feedwater). The finding had a cross-cutting aspect in the area of Human Performance, Change Management, in that, PSEG did not anticipate, manage, and communicate the effects of the over-acceleration trip change in the ADFCS modification to ensure unintended consequences were avoided.
05000272/FIN-2016001-0331 March 2016 23:59:59SalemSelf-revealingUntimely Identification and Correction of Unsatisfactory Control Room Ventilation Charcoal TestingA self-revealing Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, was identified when PSEG did not promptly identify and correct a condition adverse to quality (CAQ). Specifically, PSEG did not promptly identify that negative results of a control room emergency air conditioning system (CREACS) charcoal filtration sample had Technical Specification (TS) implications and correct it prior to violating TSs. In response, PSEG entered Unit 1 TS 3.0.3, suspended irradiated fuel movements on Unit 2 to comply with Unit 2 TS 3.7.6, and commenced actions to re-align control area ventilation to Unit 2 supplying in the maintenance mode. Unit 1 TS 3.0.3 was exited at 7:55 a.m. that morning and PSEG reported this via an 8-hour report to the NRC under ENS 51504. PSEG revised the associated surveillance procedure to write a NOTF to replace the charcoal bank in the next system window if methyl iodide results are greater than or equal to 2 percent penetration (0.5% margin). PSEG documented and evaluated the issue in their CAP as Notifications (NOTFs) 20707922, 20707650, and 20712068. Untimely identification and correction of the charcoal filter performance was a performance deficiency. The issue was more than minor since it was similar to IMC 0612, Appendix E, example 2.a in that a TS limit was exceeded. Further, it was more than minor since it was associated with the system performance attribute of the Barrier Integrity cornerstone and adversely affected its cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, unsatisfactory charcoal filter performance resulted in inoperability of the single filtration train that was in service. The finding was reviewed in accordance with IMC 0609, Attachment 4 and Appendix A, where it was screened to Green since it only represented a degradation of the radiological barrier function provided for the control room. The finding had a cross-cutting issue in Human Performance, Teamwork, in that PSEG staff did not collaborate and cooperate in connection with operational activities, such as CAP entry and notification of the control room, associated with the CREACS filter testing and results.
05000272/FIN-2016001-0431 March 2016 23:59:59SalemLicensee-identifiedLicensee-Identified ViolationTS LCO action statement 3.6.2.2.a requires that with the spray additive system inoperable, action shall be taken to restore the system to operable status within 72 hours, or be in at least hot standby within the next 6 hours. Contrary to the above, on June 22, 2015, PSEG determined that the spray additive system was inoperable for a period of time greater than allowed by TS. Specifically, PSEG review of past CS additive tank level versus estimated NaOH concentration by weight indicated that the NaOH concentration in the tank had decreased below the TS limit of 30 percent by weight on January 15, 2015, based on dilution from in-leakage. On June 23, 2015, following chemical addition, NaOH concentration was verified to be 31.4 percent by weight NaOH, and Salem Unit 1 exited TS action statement 3.6.2.2.a. PSEG reported this event as an LER, as documented in Section 4OA3 of this report. The inspectors determined that the finding was of very low safety significance (Green) in accordance with Section A of Exhibit 2 in Appendix A of IMC 0609, "The Significance Determination Process for Findings at Power, because PSEG determined under ACE 70178077 that design calculations confirmed the spray additive system will perform its safety function within the range of 28 to 36 percent by weight NaOH solution. Because this finding is of very low safety significance and has been entered into PSEG's CAP under NOTF 20694465, this violation is being treated as a Green NCV consistent with the NRC Enforcement Policy.
05000272/FIN-2015403-0131 December 2015 23:59:59SalemNRC identifiedSecurity
05000272/FIN-2015004-0531 December 2015 23:59:59SalemLicensee-identifiedLicensee-Identified ViolationFrom 2010 to 2014, Salem Units 1 and 2, made a total of 8 shipments of radioactive waste for disposal which contained category 2 levels of radioactive material quantity of concern, but did not implement a transportation security plan for these shipments in violation of the requirements of 10 CFR 71.5, Transportation of Licensed Material, and 49 CFR 172, Subpart I, Safety and Security Plans. This performance deficiency adversely affected the Public Radiation Safety cornerstone attribute of Program and Process based on inadequate procedures associated with the transportation of radioactive material. The finding was determined to be of very low safety significance (Green) because Salem had an issue involving transportation of radioactive material, but it did not involve: (1) a radiation limit that was exceeded; (2) a breach of package during transport; (3) a certificate of compliance issue; (4) a low level burial ground nonconformance; or (5) not making notifications or not providing emergency information. This issue was documented in the PSEGs CAP as notification 20674767. Corrective actions included issuance of new procedure RP-AA-600-1009, revision of procedure LS-AA-1020, Implementation of Significant Rules and Orders, Revision 1, and contracting with a vendor to receive regular, prompt notifications of potentially applicable rule changes in the Federal Register.
05000311/FIN-2015004-0131 December 2015 23:59:59SalemNRC identifiedInadequate Auxiliary Building Barrier ControlsInspectors identified a Green NCV of TS 6.8.1, Procedures and Programs, when PSEG improperly implemented barrier controls in accordance with procedure CC-AA-201, Plant Barrier Control, Revision 5, during modification activities that impacted the flooding and radiological barrier design functions of the Unit 2 auxiliary buildings external boundary. In response, PSEG properly implemented appropriate plant barrier impairments for the area to include compensatory actions for the flooding and occupational radiation barrier aspects of the program, entered this in their CAP, and performed an apparent cause analysis. This finding was more than minor because it was associated with the configuration control attribute of the Barrier Integrity cornerstone, and adversely affected the associated cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The finding was evaluated in accordance with IMC 0609, Attachment 4 and Appendix A, Exhibit 3, and determined to be Green since it did not represent a degradation of the control room barrier function despite representing a degradation of multiple barrier functions of the auxiliary building. This finding has a cross-cutting aspect in the area of Human Performance, Work Management, in that licensees implement a process of planning, controlling, and executing work to include the identification and management of risk and need for coordination such that nuclear safety is the overriding priority. Specifically, PSEG did not properly plan and control work involving an impaired auxiliary building barrier to include coordinating with and ensuring awareness of different groups as well as incorporating risk insights, compensatory actions, and contingency plans.
05000272/FIN-2015004-0231 December 2015 23:59:59SalemNRC identifiedInadequate Maintenance Effectiveness of Control Room Ventilation Radiation MonitorsInspectors identified a Green NCV of 10 CFR 50.65(a)(2) when control area ventilation (CAV) radiation monitor (RM) performance was not being effectively controlled through appropriate PM. Specifically, there were repetitive foil issues and a repeat maintenance preventable functional failure (RMPFF) during the monitoring period. PSEG placed the system in monitoring under 10 CFR 50.65(a)(1) and entered this in their CAP. The issue was more than minor since it was associated with the barrier performance attribute of the Barrier Integrity cornerstone and adversely affected its objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The finding was screened in accordance with IMC 0609, Attachment 4 and Appendix A, Exhibit 3, where it screened to Green since it only represented a degradation of the radiological barrier function provided for the control room. The finding has a cross-cutting aspect in Human Performance, Conservative Bias, in that licensees take timely action to address degraded conditions commensurate with their safety significance and take a conservative approach to decision making.
05000272/FIN-2015004-0331 December 2015 23:59:59SalemSelf-revealingImproper PM Deletion Resulted in Plant Shutdown Required by Technical SpecificationsA self-revealing Green NCV of Technical Specification (TS) 6.8.1, Procedures and Programs, as described in Regulatory Guide (RG) 1.33, Revision 2, February 1978, was identified when PSEG did not maintain an appropriate preventive maintenance (PM) schedule for Salem containment fan cooling units (CFCUs). Specifically, PSEG did not incorporate vendor recommendations and industry operating experience (OE) in 2003 when modifying PM schedules to delete motor air gap measurements for CFCUs. The 14 CFCU subsequently failed to start in low speed for scheduled testing on March 8, 2015. PSEG entered this in their corrective action program (CAP) as notification 20681031, replaced the 14 CFCU motor, completed an apparent cause evaluation (ACE), and re-initiated CFCU motor air gap measurement PMs. PSEGs inadequate analysis of PM deletion was a performance deficiency within PSEGs ability to correct and should have been prevented. This issue was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affects its cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the finding was of very low safety significance (Green) in accordance with IMC 0609, Attachment 4 and Appendix A, Exhibit 2, because the finding was not a design or qualification deficiency, did not represent a loss of safety system function, did not represent the loss of function for any TS system, train, or component beyond the allowed TS outage time, and it did not represent an actual loss of function of any non-TS trains of equipment designated as high safety significance in accordance with PSEGs maintenance rule (MR) program. The inspectors determined that there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance. Specifically, in accordance with IMC 0612, the causal factors associated with this finding occurred outside the nominal three-year period of consideration and were not considered representative of present performance.
05000272/FIN-2015004-0431 December 2015 23:59:59SalemSelf-revealingInadequate Post Maintenance Testing on OTDT ChannelsA self-revealing Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion XI, Test Control, and associated NCV of TS 3.3.1.1 was identified, with two examples, for not ensuring that all testing required to demonstrate that nuclear instrumentation (NI) would perform satisfactorily in service was identified and performed. As a result, inoperable Over-Temperature Delta-Temperature (OTDT) channels were not placed in the tripped condition within the timeframe required by TS limiting condition for operation (LCO) 3.3.1.1, on January 20 and April 21, 2015, respectively. PSEG entered this issue in their CAP and developed corrective actions to provide improved retest requirements for all maintenance performed on the NI system. The inspectors determined that the failure to ensure the NI channels were operable upon restoration to service was a performance deficiency. The performance deficiency is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected its cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. Inspectors evaluated the findings significance in accordance with IMC 0609, Attachment 4 and Appendix A, and determined that the finding did not affect a single reactor protection system (RPS) trip signal to initiate a reactor scram and the function of other redundant trips or diverse methods of reactor shutdown, did not involve control manipulations that unintentionally added positive reactivity and did not result in a mismanagement of reactivity by operator(s). Therefore, the finding screened to Green, or very low safety significance. The finding has a cross-cutting aspect in the area of Human Performance, Documentation, because PSEG did not ensure that plant activities were effectively governed by comprehensive, high-quality, programs, processes and procedures. Specifically, subsequent to completion of calibration and replacement work and post-maintenance testing (PMT) per Instrumentation and Controls (I&C) surveillance procedures, work packages did not adequately address or specify activities related to verifying potentially affected RPS indications.
05000311/FIN-2015003-0230 September 2015 23:59:59SalemNRC identifiedInadequate Operability Determination of Auxiliary Feedwater Flow Rate IndicatorThe inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when PSEG did not adequately implement procedure OP-AA-108-115, Operability Determinations & Functionality Assessments. Specifically, PSEG did not properly evaluate and document an adequate basis for operability of an AFW flow rate indicator prior to restoring it to an operable status. PSEG re-declared the channel inoperable, vented air from the transmitter, took satisfactory voltage readings prior to declaring the channel operable, and entered this issue in their CAP. The issue was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was evaluated in accordance with IMC 0609, Attachment 4 and Appendix A, where it screened to Green since it did not affect the design or qualification of a mitigating structure, system, and component (SSC), did not represent a loss of system and/or function, and did not represent an actual loss of at least a single train for greater than its technical specification (TS) allowed outage time. The finding had a cross-cutting aspect in the area of Human Performance, Conservative Bias, in that licensee staff use decision making-practices that emphasize prudent choices over those that are simply allowable. Specifically, PSEG did not take a conservative approach to decision making, particularly when information was incomplete and conditions were unusual. Further, PSEG management did not take timely action to address degraded conditions commensurate with their safety significance.