IR 05000272/2014007
| ML14239A657 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 08/27/2014 |
| From: | Christopher Cahill Engineering Region 1 Branch 2 |
| To: | Joyce T Public Service Enterprise Group |
| Cahill C | |
| References | |
| IR-14-007 | |
| Download: ML14239A657 (36) | |
Text
T. Joyc UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION I
2100 RENAISSANCE BLVD., SUITE 100 KING OF PRUSSIA, PA 19406-2713 August 27, 2014 Mr. Thomas Joyce President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancocks Bridge, NJ 08038 SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 -
NRC COMPONENT DESIGN BASES INSPECTION REPORT 05000272/2014007 and 05000311/2014007
Dear Mr. Joyce:
On July 24, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Salem Nuclear Generating Station, Unit Nos. 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on July 24, 2014, with Mr. Lawrence Wagner, Salem Plant Manager, and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.
In conducting the inspection, the team examined the adequacy of selected components to mitigate postulated transients, initiating events, and design basis accidents. The inspection involved field walkdowns, examination of selected procedures, calculations and records, and interviews with station personnel.
This report documents one NRC-identified finding that was of very low safety significance (Green). The finding was determined to involve a violation of NRC requirements. However, because of the very low safety significance of the violation and because it was entered into your corrective action program, the NRC is treating the finding as a non-cited violation (NCV)
consistent with Section 2.3.2 of the NRC Enforcement Policy. If you contest the NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Senior Resident Inspector at the Salem Nuclear Generating Station. In addition, if you disagree with the cross-cutting aspect assigned to the finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis of your disagreement, to the Regional Administrator, Region I, and the NRC Senior Resident Inspector at the Salem Nuclear Generating Station. In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for the public inspection in the NRC Public Docket Room or from the Publicly Available Records component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Christopher G. Cahill, Acting Chief Engineering Branch 2 Division of Reactor Safety Docket Nos: 50-272; 50-311 License Nos: DPR-70; DPR-75 Enclosure: Inspection Report 05000272/2014007 and 05000311/2014007 w/Attachment: Supplemental Information cc: via ListServ
SUMMARY OF FINDINGS
IR 05000272/2014007 and 05000311/2014007; 06/23/2014 - 07/24/2014; Salem Unit Nos.
and 2; Component Design Bases Inspection.
The report covers the Component Design Bases Inspection conducted by a team of four U.S. Nuclear Regulatory Commission (NRC) inspectors and two NRC contractors. One finding of very low risk significance (Green) was identified, which was also considered to be a non-cited violation. The significance of most findings is indicated by their color (Green, White, Yellow,
Red) using NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process.
Cross-cutting aspects associated with findings are determined using IMC 0310, Components Within the Cross-Cutting Areas. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,
Revision 5.
Cornerstone: Mitigating Systems
Green: The team identified a non-cited violation of 10 CFR 50, Appendix B, Criterion XVI,
Corrective Action, because PSEG did not promptly identify and correct conditions adverse to quality. Specifically, PSEG did not promptly identify and correct degraded conditions associated with the Unit 1 and Unit 2 auxiliary feedwater storage tank (AFWST) and refueling water storage tank (RWST) instrumentation panels. PSEG entered the associated issues into their corrective action program (CAP) as notifications 20654991, 20654996, 20656136, 20657114, 20657115, and 20657117. PSEGs short-term corrective actions included installing bolts/plugs on the Unit 1 RWST panel 378-1 and unplugging the failed fan in Unit 1 AFWST panel 802-1.
The team determined that the inadequate identification and resolution of the conditions adverse to quality is a performance deficiency that was within PSEGs ability to foresee and correct. The finding is associated with the Mitigating Systems cornerstone and is more than minor because if left uncorrected it could lead to a more significant safety concern.
Specifically, if left uncorrected, the continued exposure to external environmental elements and/or existing internal degraded conditions could potentially result in loss of level indication, non-conservative level indication, and/or loss of low level alarm functions. 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 team determined that the finding is of very low safety significance (Green), because the finding was a deficiency affecting the design or qualification of a mitigating system, structure, or component (SSC), where the SSC maintained its operability.
The finding has a cross-cutting aspect in the area of Problem Identification and Resolution,
Corrective Action Program, because PSEG did not identify issues completely, accurately, and in a timely manner in accordance with the corrective action program. Specifically,
PSEG did not identify degraded conditions associated with the Unit 1 and Unit 2 AFWST and RWST panels and take timely and appropriate corrective actions [P.1].
(Section 1R21.2.1.7)ii
Other Findings
None.
iii
REPORT DETAILS
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R21 Component Design Bases Inspection (IP 71111.21)
.1 Inspection Sample Selection Process
The team selected risk significant components for review using information contained in the Salem Probabilistic Safety Assessment (PSA) model and the U. S. Nuclear Regulatory Commissions Standardized Plant Analysis Risk (SPAR) model for the Salem Nuclear Generating Station. Additionally, the team referenced the Plant Risk Information e-Book (PRIB) for the Salem Nuclear Generating Station in the selection of potential components for review. In general, the selection process focused on components that had a risk achievement worth (RAW) factor greater than 1.3 or a risk reduction worth (RRW) factor greater than 1.005. The components selected were associated with both safety-related and non-safety related systems, and included a variety of components such as pumps, breakers, protection logic, electrical buses, instrumentation, batteries, motors, tanks, heat exchangers, and valves.
The team initially compiled a list of components based on the risk factors previously mentioned. Additionally, the team reviewed the previous component design bases inspection (CDBI) reports (05000272 & 311/2011007, 05000272 & 311/2008007, and 05000272 & 311/2006006) and excluded the majority of those components previously inspected. The team then performed a margin assessment to narrow the focus of the inspection to 16 components and 4 operating experience (OE) items. The team selected Unit 1 feedwater penetration seals and an Unit 2 containment pressure vacuum relief valve for large early release frequency (LERF) implications. The teams evaluation of possible low design margin included consideration of original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition/equipment reliability issues. The assessment also included items such as failed performance test results, corrective action history, repeated maintenance, Maintenance Rule (a)(1) status, operability reviews for degraded conditions, NRC resident inspector insights, system health reports, and industry OE. Finally, consideration was also given to the uniqueness and complexity of the design and the available defense-in-depth margins.
The inspection performed by the team was conducted as outlined in NRC Inspection Procedure (IP) 71111.21. This inspection effort included walkdowns of selected components; interviews with operators, system engineers, and design engineers; and reviews of associated design documents and calculations to assess the adequacy of the components to meet design basis, licensing basis, and risk-informed beyond design basis requirements. Summaries of the reviews performed for each component and OE sample, and the specific inspection findings identified are discussed in the subsequent sections of this report. Documents reviewed for this inspection are listed in the
.
.2 Results of Detailed Reviews
.2.1 Detailed Component Reviews (16 samples)
.2.1.1 Unit 1 B Reactor Trip Breaker
a. The team inspected the Unit 1 B reactor trip breaker (RTB) to verify that it was capable of meeting its design basis requirements. The installed RTBs are designed to open during accident and/or transient conditions thereby removing power from the control rod drive mechanisms to automatically shut down the reactor. Since PSEG rotated other trip breakers, including the reactor trip bypass breakers, into service when they removed the B RTB for testing and maintenance, the team inspected more than one specific RTB.
The team reviewed the vendor technical manual and equipment data to verify that PSEG incorporated the requirements and recommendations into testing and maintenance procedures. The team reviewed results of testing and preventive maintenance (PM)activities to confirm that PSEG adequately verified design requirements and implemented component replacements in accordance with the manufacturers recommendations. The team also reviewed corrective action notifications (NOTFs) and system health reports to confirm that PSEG appropriately identified and resolved any observed deficiencies or adverse trends. The team performed several walkdowns of the Unit 1 trip and bypass breakers, including the associated control room instrumentation, to assess the material condition, operating environment, and configuration control.
b. Findings
No findings were identified.
.2.1.2 1C 230 Vac Bus
a. Inspection Scope
The team inspected the 1C 230 Vac bus to verify that it was capable of performing its design function. The team reviewed the one-line diagrams, control schematics, and the design basis as defined in the Updated Final Safety Analysis Report (UFSAR) to verify the adequacy of the 230 Vac bus capability to supply adequate voltage and current to its safety-related loads. The team reviewed the associated voltage drop calculations to verify that adequate voltage was available to components supplied by the bus under worst case loading and degraded voltage conditions. The team reviewed the bus supply and feeder breaker ratings and trip settings to verify that protection coordination was provided for the loads and for the feeder conductors. The team reviewed vendor specifications, nameplate data, and calculations related to the 230 Vac bus supply to ensure that PSEG operated and maintained the 1C 230 Vac in accordance with design requirements and specifications. The team performed several walkdowns of the bus, its associated transformer, and adjacent areas to assess the installed configuration, material condition, the operating environment, and potential vulnerability to hazards.
The team also reviewed associated corrective action NOTFs and system health reports to confirm that PSEG appropriately identified and resolved any observed deficiencies or adverse trends.
b. Findings
No findings were identified.
.2.1.3 Unit 2 Safety Injection Valve 2SJ13
a. Inspection Scope
The team inspected Unit 2 safety injection (SI) system valve 2SJ13 to verify its capability to perform its design basis function. The 2SJ13 valve is one of two parallel, normally closed, motor-operated valves (MOVs) in the flow path from the high pressure injection pumps (high head charging pumps) to the reactor cold legs. The 2SJ13 valves safety function is to open automatically on SI initiation. The team reviewed the UFSAR, Technical Specifications (TSs), drawings, and procedures to identify the design basis requirements for the valve. The team verified that PSEG tested 2SJ13 in accordance with the TS requirements and that the surveillance test (ST) records verified proper performance of 2SJ13. The team reviewed PSEGs response to NRC Generic Letter (GL) 95-07, Pressure Locking and Thermal Binding of Power Operated Gate Valves, especially with respect to its applicability to the 2SJ13 valve. The team reviewed vendor and PSEG thrust/torque calculations to verify that the valve had sufficient margin to perform its design basis function. The team performed a walkdown of 2SJ13 with the system engineer and piping seismic stress engineer to visually inspect the physical/material condition of the valve and its support systems and to ensure adequate configuration control. The team reviewed and discussed PSEGs evaluation and analysis of concrete cracking in the 2SJ13 support pedestal to assess the material condition, potential impact on system operability, and PSEGs related corrective actions.
The team also reviewed corrective action documents and system health reports to determine whether there were any adverse operating trends or existing issues affecting valve reliability or performance.
b. Findings
No findings were identified.
.2.1.4 Unit 2 Residual Heat Removal Pump Suction Valve (21RH4)
a. Inspection Scope
The team inspected the residual heat removal (RHR) RWST supply valve (21RH4) to verify that it was capable of performing its design function in response to transients and accidents. The normally open 21RH4 valve is required to be open for the RHR system to perform its initial emergency core cooling system (ECCS) injection function and required to close to isolate the RWST during containment sump recirculation. The team reviewed applicable portions of Salems TSs, the UFSAR, and the RHR system design basis document (DBD) to identify design basis requirements for the valve.
The team reviewed design calculations, valve specifications, and operating history to verify that the valve was acceptable for RHR service, and to verify that it met the applicable American Society of Mechanical Engineers (ASME) Code requirements. The team reviewed a sample of ST results to verify that valve performance met the acceptance criteria and that the criteria were consistent with the design bases. Also, the team reviewed operator training lesson plans to verify the technical adequacy and details of the plan. The team interviewed the MOV program engineer and reviewed valve diagnostic test results and trending to assess valve performance capability, design margin, and susceptibility to recent industry OE. The team reviewed a sample of RHR system corrective action documents (NOTFs), the RHR system health report, and applicable test results to determine if there were any adverse operating trends and to ensure that PSEG adequately identified and addressed any adverse conditions. The team also performed several walkdowns of the valve, adjacent area, accessible portions of the RHR system, and associated control room instrumentation to assess the material condition, operating environment, and configuration control.
b. Findings
No findings were identified.
.2.1.5 23 Chiller
a. Inspection Scope
The team inspected one of the three Unit 2 chiller packages, specifically the 23 chiller, to verify that it was capable of performing its design function. Each chiller is a 50 percent capacity system used to remove heat from the auxiliary building and the main control room during both normal and emergency operating conditions. The team performed several walkdowns of the Unit 2 chillers to assess the system condition, configuration control, and the operating environment. The team interviewed the system engineer and also performed a system walkdown together to discuss operational challenges and assess system deficiencies. The team reviewed the UFSAR, vendor documentation, and drawings to identify design requirements of the chiller system. The team also reviewed PM and internal inspection documents associated with the chiller heat exchangers (HXs) and the service water (SW) system to ensure that PSEG adequately maintained HX tube integrity and appropriately addressed the potential for biological fouling. The team also reviewed the maintenance and functional history of the 23 chiller by sampling corrective action documents and the system health report to ensure that PSEG appropriately identified, characterized, and corrected problems.
b. Findings
No findings were identified.
.2.1.6 Unit 1 Solid State Protection System Train A
a. Inspection Scope
The team reviewed the maintenance, testing, and operation of the Unit 1 solid state protection system (SSPS) with specific emphasis on the A train components to verify that the system was capable of performing its design function of providing proper actuation signals under operating, transient, and accident conditions. The team verified that the overall SSPS system actuation, from protective signal actuation through RTB opening, was within the TS requirements for the selected scenarios. The team reviewed selected modifications, including temporary changes, to verify that the modifications did not adversely impact system design functions or capability. The team reviewed the vendor technical manual to verify that PSEG adequately incorporated the guidelines, including the recommended frequency, into the associated testing and maintenance procedures. The team verified that PSEG properly implemented the associated TS operating and testing requirements. The team also reviewed corrective action NOTFs and system health reports to confirm that PSEG appropriately identified and resolved any observed deficiencies or adverse trends. The team performed an internal, non-intrusive inspection of the Unit 1 SSPS cabinets in the control room to assess the material condition, operating environment, and configuration control.
b. Findings
No findings were identified.
.2.1.7 Unit 1 and Unit 2 Refueling Water Storage Tank and Containment Sump Level
Instrumentation
a. Inspection Scope
The team reviewed portions of the instrument uncertainty and setpoint calculations for the Unit 1 and Unit 2 RWST and containment sump level instrumentation to confirm that assumptions and design inputs regarding tank geometry, process effects, reference leg configuration, instrument uncertainty, and analytical or process limits had been appropriately considered, and that appropriate statistical methodology had been used. This included confirming that the calculations were consistent with operation under operating, transient, and accident conditions. In addition, the team reviewed a sample of calibration results and trending data, as reported by PSEGs maintenance measured data program. The team performed several walkdowns of the RWST level instrumentation panels, including non-intrusive internal inspections, to assess the installed configuration, material condition, the operating environment, and potential vulnerability to hazards. The team also reviewed associated corrective action NOTFs and system health reports to confirm that PSEG appropriately identified and resolved any observed deficiencies or adverse trends.
b. Findings
Introduction:
The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, because PSEG did not promptly identify and correct conditions adverse to quality. Specifically, PSEG did not promptly identify and correct degraded conditions associated with the Unit 1 and Unit 2 AFWST and RWST instrumentation panels.
Description:
On June 24, 2014, the team performed a system walkdown of the Unit 1 and Unit 2 RWST panels to assess the condition of the level instrumentation in the field.
While inspecting the external condition of the panels, the team identified four 1-inch diameter bolts missing on the top of the Unit 1 RWST 378-1 panel (one bolt hole on each corner). The missing bolts on the top of the Unit 1 RWST 378-1 panel potentially allowed external environmental elements (rain, snow, sleet) to enter the inside of the sealed panel which could adversely impact the safety-related RWST level instrumentation. The team noted an operator aid posting (SC-MDA-93-004) on all of the outdoor RWST and AFWST panels that stated Close the door. Leaving this door open can cause instrument line freezing resulting in a Technical Specification violation or plant shutdown. On June 25, the team completed a follow-up walkdown with the RHR system engineer to open and inspect the inside of the panel to assess the material condition and potential water intrusion impact. The team observed that the internal insulation of the Unit 1 RWST panel was severely degraded, there was significant corrosion of the panel itself, and some corrosion evident on several internal components.
PSEG initiated corrective action NOTF 20654991 for this condition and promptly installed bolts on top of the Unit 1 RWST 378-1 panel. The teams initial extent-of-condition walkdown also identified that four bolts atop one of the Unit 2 AFWST panels were not fully engaged and the team observed some corrosion within the panel. PSEG initiated corrective action NOTF 20654996 for this condition.
On July 8, as part of the teams follow-up extent-of-condition walkdowns, the team identified four missing bolts on top of the Unit 1 AFWST 802-1 panel and questioned the functionality of an internal cooling fan within the panel (the fan was not running at the time). PSEG initiated corrective action NOTF 20656136 for the missing bolts in Unit1 AFWST panel 802-1. On July 21, during a subsequent extent-of-condition walkdown, the team identified additional conditions adverse to quality that included: a failed fan inside the Unit 1 AFWST 802-1 panel (NOTF 20657114), a failed thermostat causing high temperatures in the AFWST 379-1 panel (NOTF 20657115), and a damaged heater in the AFWST 379-1 panel (NOTF 20657117). PSEG initiated corrective actions NOTFs for each of these conditions, including unplugging the failed fan in Unit 1 AFWST panel 802-1. Based on interviews and a CAP database review, the team found no evidence that the missing bolts were removed within the last three years.
The team noted that PSEG had several opportunities to identify the missing bolts and degraded conditions within the panels. Although equipment operators and system engineers periodically toured the panel area, they did not identify the missing bolts and thus did not adequately evaluate the conditions within the panels for potential impact to the safety-related equipment installed inside. In September 2012, operators initiated NOTFs 20576202 and 20576087 for rusty conditions inside and outside of the Unit 1 AFWST 802-1 panel. On July 10, 2013, PSEG personnel replaced the door seal on the Unit 1 AFWST 802-1 panel (work order 60108142) in an attempt to correct the water in-leakage. During a follow-up AFWST 802-1 panel walkdown in May 2014, operators noted in NOTF 20652576 that further deterioration as has been seen over the last 20 months will eventually lead to inoperability of the equipment and render it unable to perform its design function. In April 2014, personnel inspected and performed work inside of the Unit 1 RWST 378-1 panel to investigate the cause of a level discrepancy (NOTF 20646537). In June 2014, NOTF 20653134 stated that following a thunderstorm and rain, non-TS channel 2LA2705 in the Unit 2 AFWST 802-2 panel failed high. It appears that the rain affects the 2LA2705 channel. In addition, PSEG previously performed a thorough RWST panel inspection every three years (last performed in 2008); however, PSEG reduced the scope of this PM inspection to include limited portions of it during their annual Winter readiness PM of the panels.
Analysis:
The team determined that the inadequate identification and resolution of the conditions adverse to quality associated with the Unit 1 and Unit 2 AFWST and RWST instrumentation panels was a performance deficiency that was within PSEGs ability to foresee and correct. The finding was associated with the Mitigating Systems cornerstone and was more than minor because if left uncorrected it could lead to a more significant safety concern. Specifically, if left uncorrected, the continued exposure to external environmental elements and/or the existing internal degraded conditions could potentially result in loss of level indication, non-conservative level indication, and/or loss of low level alarm functions. 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 team determined that the finding was of very low safety significance (Green), because the finding was a deficiency affecting the design or qualification of a mitigating system, structure, or component (SSC), where the SSC maintained its operability.
The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because PSEG did not identify issues completely, accurately, and in a timely manner in accordance with the CAP. Specifically, PSEG did not identify degraded conditions associated with the Unit 1 and Unit 2 AFWST and RWST panels and take timely and appropriate corrective actions [P.1].
Enforcement:
10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to the above, PSEG failed to promptly identify and correct conditions adverse to quality. Specifically, since initial panel installation (estimated), PSEG did not promptly identify and correct the missing bolts on the Unit 1 RWST 378-1 panel until June 24, 2014, and on the Unit 1 AFWST 802-1 panel until July 8, 2014. In addition, PSEG did not promptly identify and correct the degraded conditions within the Unit 1 AFWST panels from approximately July 8, 2014, to July 21, 2014 (estimated). PSEGs short-term corrective actions included installing bolts/plugs on the Unit 1 RWST panel 378-1, unplugging the failed fan in Unit 1 AFWST panel 802-1, and initiating corrective action NOTFs for each adverse condition. Because this finding was of very low safety significance and because it was entered into PSEGs CAP (NOTFs 20654991, 20654996, 20656136, 20657114, 20657115, and 20657117), this violation is being treated as an NCV, consistent with the NRC Enforcement Policy. (NCV 05000272;05000311/2014007-01, Failure to Identify Degraded Conditions Associated with the Unit 1 and Unit 2 RWST and AFWST Panels)
.2.1.8 Unit 2 Auxiliary Feedwater Storage Tank and Auxiliary Feedwater Suction Piping
a. Inspection Scope
The team inspected the Unit 2 AFWST and AFW suction piping to verify their capability to meet design basis requirements. The safety-related AFW system supplies feedwater to the secondary side of the steam generators when the non-safety related main feedwater system is not available. The AFW system is relied upon to prevent core damage and system overpressurization in the event of accidents such as a loss of normal feedwater or secondary system pipe rupture, and to provide a means for plant cooldown. The team conducted a walkdown of the Unit 2 AFWST and AFW suction piping with the AFW system engineer, and also performed several independent walkdowns, including control room instrumentation. These walkdowns examined the material condition of accessible portions of the Unit 2 AFWST and AFW suction piping and included the verification of tools and spool pieces required to enable operators to line up alternate sources of water to the AFW pump suctions. The team reviewed the operator actions for various AFWST level indications and the procedures used to line up the alternate water sources to the AFW suction piping. The team reviewed the calculations for AFWST useful water volume, AFWST outlet piping vortexing, and AFW pump net positive suction head (NPSH). The team reviewed associated AFW drawings, design changes and modifications, and engineering evaluations to verify that PSEG maintained the design bases for the AFWST and AFW suction piping. The team reviewed system health reports, corrective action documents, maintenance history, and testing records to determine if there were any adverse operating trends and to ensure that PSEG adequately identified and addressed any adverse conditions.
b. Findings
No findings were identified.
2.1.9 22 Residual Heat Removal Pump
a. Inspection Scope
The team reviewed applicable portions of Salem TSs, the UFSAR, and the RHR system DBD to identify the design bases requirements for the 22 RHR pump. The team reviewed design calculations and site procedures to verify that PSEG appropriately translated the design bases and design assumptions into these documents. The team also reviewed design and operational requirements with respect to pump flow rate, developed head, achieved system flow rate, and NPSH. The team verified that minimum flow requirements as described in NRC Bulletin 88-04 were satisfied under all conditions to avoid pump damage. The team reviewed the pump discharge check valve testing and the associated acceptance criteria, to ensure that the valve would support maximum accident flow conditions and perform its closure function to prevent undesired backflow. The team reviewed the adequacy of assumptions, limiting parameters, the pumps protection from the formation of air vortexes, and the adequacy of its suction from the containment sump.
The team verified that test procedures and test results were supported by design basis documents, acceptance criteria for tested parameters were supported by calculations or other engineering documents, and that tests and analyses served to validate component operation under accident and transient conditions. The team also reviewed the adequacy of the pump baseline for in-service testing including the actual pump performance results to ensure that the pump was performing within accident analysis assumptions. The team reviewed operating and emergency operating procedures (EOPs) to verify that selected operator actions could be accomplished. Additionally, the team reviewed control schematics to verify that the system operation complied with the system design requirements. The team performed a walkdown of the pump, accessible RHR piping, and the adjacent area to assess the material condition, operating environment, and configuration control. The team also reviewed a sample of RHR system corrective action documents, the RHR system health report, and applicable test results to determine if there were any adverse operating trends and to ensure that PSEG adequately identified and addressed any adverse conditions.
b. Findings
No findings were identified.
.2.1.1 0 Unit 2 Containment Pressure Vacuum Relief Outlet Valve (2VC5)
a. Inspection Scope
The team inspected the Unit 2 containment pressure vacuum relief outlet valve (2VC5)to verify its ability to meet its design basis requirements. The 2VC5 valves safety-related functions include containment isolation capability upon a high containment pressure signal or high radiation signal and control of the differential pressure between the containment and the atmosphere during normal operation. The team reviewed in-service test (IST) program requirements and evaluated IST surveillance results, including stroke time testing, to verify acceptance criteria were met and any performance degradation identified. The team also performed several walkdowns of 2VC5 and valves in the vicinity to assess equipment condition, configuration control, operating environment, and potential hazards. The team reviewed design drawings and vendor documentation to ensure that PSEG appropriately controlled design requirements. The team reviewed operator and equipment logs used to track the amount of time that the 2VC5 was open (in Modes 1 - 4) to verify that it met site specific administrative limits and licensing basis commitments. The team also reviewed the maintenance and functional history of the 2VC5 by sampling corrective action documents and the system health report to ensure that PSEG appropriately identified, characterized, and corrected problems.
b. Findings
No findings were identified.
.2.1.1 1 C 125 Vdc Battery and 1C 125 Vdc Bus
a. Inspection Scope
The team reviewed the design, testing, and maintenance of the 1C 125 Vdc station battery and its associated distribution bus to verify that they were capable of performing their design function of providing a reliable source of direct current (DC) power to required loads under operating, abnormal, and accident conditions. The team reviewed the voltage regulation calculations to ensure that adequate voltage would be available to required loads under accident and station blackout (SBO) conditions. The team also reviewed the short circuit and breaker/fuse coordination calculations to determine if the circuit breakers and fuses were appropriately sized and were capable of interrupting potential circuit faults. The team verified that PSEG used the proper cable resistance and ampacity values in both the voltage regulation and short circuit calculations through a comparison of corrected values provided in the National Electric Code. The team also reviewed battery test procedures and test results to verify that the testing was in accordance with industry standards, aligned with the design calculations, and fully satisfied TS requirements. The team verified that the testing results confirmed acceptable performance of the battery and adequate battery capacity.
The team interviewed design engineers regarding design margin, operation, and testing of the DC system. The team performed several walkdowns of the 1C 125 Vdc battery, 1C DC bus, and associated battery chargers to assess the material condition, operating environment, and configuration control. The team reviewed the battery seismic evaluations and compared them to the as-installed configuration to verify that the battery was capable of performing its design function under design basis accident conditions.
The team also reviewed corrective action NOTFs and system health reports to confirm that PSEG appropriately identified and resolved any observed deficiencies or adverse trends.
b. Findings
No findings were identified.
.2.1.1 2 22 Residual Heat Removal Pump Motor
a. Inspection Scope
The team inspected the 22 RHR pump motor to determine whether it could fulfill its design basis function of providing adequate horsepower for the pump to deliver the required flow under normal operating, transient, and accident conditions. The team walked down the RHR pump, the pump motor, and both Unit 2 RHR pump rooms to assess the material condition, configuration control, and the operating environment. The team reviewed the RHR pump performance curve and design basis flow requirements to evaluate the required capacity for the break horsepower required by the pump during design basis conditions. The team reviewed the motor overcurrent relay setting calculation, relay settings, and recent overcurrent relay calibration tests to evaluate whether the protective relays would provide for reliable motor operation at design basis minimum voltage conditions. Finally, the team reviewed corrective action documents to verify PSEG was identifying and correcting issues with the motor, and to verify that there were no adverse trends.
b. Findings
No findings were identified.
.2.1.1 3 23 Turbine Driven Auxiliary Feedwater Pump Steam Supply Valve
a. Inspection Scope
The team inspected the 23 turbine driven AFW (TDAFW) pump steam supply valve, 2MS132, to verify its capability to perform its design basis function. The 2MS132 valve is a normally closed air operated valve (AOV) located in the steam supply line from the steam header to the Unit 2 TDAFW pump turbine. The 2MS132 valve opens automatically upon the receipt of a start signal to the TDAFW pump. The team reviewed the control circuit diagrams, the opening/closing calculations, and the recent surveillance test documents to verify that the valve functioned as designed. The team also reviewed the engineering change package, applicable work orders, and the post maintenance testing for the recent replacement of the valve/actuator connection to verify that PSEG specified and met the appropriate design requirements. The team interviewed the AOV program engineer and the AFW system engineer to gain an understanding of maintenance issues and overall reliability of the valve. The team reviewed applicable plant drawings, AFW system health reports, AOV program health reports, maintenance records, and performed several system walkdowns to assess the material condition, performance history, and PSEGs configuration control. The team reviewed work orders and corrective action documents to verify that PSEG appropriately identified and resolved deficiencies and properly maintained the valve.
b. Findings
No findings were identified.
.2.1.1 4 22 Residual Heat Removal Heat Exchanger
a. Inspection Scope
The team inspected the 22 RHR HX to verify that it was capable of meeting its design basis requirements. The team reviewed the Salem UFSAR, the RHR DBD, drawings, and procedures to identify the HX design basis requirements. The RHR HXs are designed to remove residual and sensible heat from the core and reduce the temperature of the reactor coolant system during the second phase of plant cooldown.
Under normal operating conditions, the RHR system HX will reduce the temperature of the reactor coolant from 350 F to 140 F within 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> following reactor shutdown.
The team reviewed the design pressure and temperature of the HX shell and tubes to verify that operational procedures and performance under accident conditions were consistent with the design parameters. The team reviewed the flowpaths used in the EOPs for containment sump recirculation to ensure that the design rated flow through the tube side of the HX was consistent with the allowable vendor specifications. The team reviewed the corresponding pressures within the shell and tube side of the HX in the long-term recirculation alignment to verify that the system pressures would be consistent with licensing bases assumptions in the UFSAR. The team reviewed the design and logic for the shell side valves associated with the component cooling water (CCW) supply to the RHR HX to ensure that adequate shell side cooling would exist prior to initiating containment sump recirculating water to avoid the possibility of any steam void formation. The team reviewed corrective action documents to verify that the RHR HX had not been showing signs of leakage and to verify that PSEG appropriately identified and resolved deficiencies.
b. Findings
No findings were identified.
.2.1.1 5
11 Safety Injection Pump Breaker
a. Inspection Scope
The team inspected the 11 SI pump breaker (1AD1AX5D) to verify that it was capable of performing its design function. The team reviewed the one-line diagrams, control schematics, and the design basis as defined in the UFSAR to verify the adequacy of the 11 SI pump breaker to provide the loading and switching requirements under the worst case loading conditions. The team reviewed the breaker closing permissives and interlocks to verify that the breaker opening and closing control circuits functioned as designed. The team reviewed a sample of preventive and corrective maintenance test results to verify that the applicable test acceptance criteria and test frequency requirements were satisfied. The team performed several walkdowns of the 4KV breaker and its associated 4KV bus to assess the installed configuration, material condition, operating environment, and potential vulnerability to hazards. The team also reviewed the maintenance and operating history of the breaker, associated corrective action NOTFs, the last replacement/refurbishment of the breaker, and applicable test results to determine if there were any adverse operating trends and to ensure that PSEG adequately identified and addressed any adverse conditions.
b. Findings
No findings were identified.
2.1.16 12BF22 and 14BF22 Containment Penetration Seals
a. Inspection Scope
The team inspected the 12BF22 and 14BF22 containment penetration seals to verify that they were capable of meeting their design basis requirements. The 12BF22 and 14BF22 containment penetration seals are part of the primary containment boundary.
The penetrations contain a non-safety related penetration cooling system which uses station air to maintain the temperature of the concrete less than 150 F to prevent long-term degradation of the concrete surrounding the penetration. The team performed several walkdowns of the penetrations, both inside and outside of containment, and accessible portions of their associated penetration cooling system to ensure conformance with the design bases. The team used a contact pyrometer to independently verify that concrete temperatures and penetration cooling heat removal were within design requirements and to ensure that system operation was in accordance with design documentation. The team also conducted interviews and a system walkdown with PSEG engineers to assess the condition of the penetrations and to ensure proper operation of the penetration cooling system. The team reviewed the UFSAR, drawings, Maintenance Rule scoping documents, and the structural monitoring program to assess the penetration conditions against design requirements. The team also reviewed the most recent IST Type A integrated leak test to ensure that leakage requirements associated with the penetrations were in accordance with IST program and TS limits. The team also reviewed the maintenance and functional history of the 12BF22 and 14BF22 penetrations by sampling corrective action documents and system health reports to ensure that PSEG appropriately identified, characterized, and corrected problems.
b. Findings
No findings were identified.
.2.2 Review of Industry Operating Experience and Generic Issues (4 samples)
The team reviewed selected OE issues for applicability at Salem Unit 1 and 2. The team performed a detailed review of the OE issues listed below to verify that PSEG had appropriately assessed potential applicability to site equipment and initiated corrective actions when necessary.
.2.2.1 NRC Information Notice 2013-05: Battery Expected Life and Its Potential Impact on
Surveillance Requirements
a. Inspection Scope
The team evaluated PSEGs applicability review and disposition of NRC Information Notice (IN) 2013-05 to determine if Salem Generating Station was susceptible to the battery performance issues stated in the IN. The NRC issued the IN to alert licensees to issues of non-conservative TSs regarding surveillance requirements due to reductions in battery expected life as a result of load growth and environmental conditions. The team reviewed PSEGs evaluation of the issues presented in this IN and assessed PSEGs actions to monitor battery room and cell conditions, such as temperature. The team reviewed PSEGs battery testing and maintenance programs with respect to the IN concerns (see also Section 1R21.2.1.11). The team also reviewed PSEGs battery replacement criteria to ensure that the required capacity would be available throughout the batterys installed lifetime.
b. Findings
No findings were identified.
.2.2.2 NRC Information Notice 2013-18: Refueling Water Storage Tank Degradation
a. Inspection Scope
The team evaluated PSEGs applicability review and disposition of IN 2013-18. The NRC issued the IN to alert licensees to issues associated with leakage due to flaws in RWST welds. The team reviewed PSEGs evaluation of their RWST maintenance plans, and the recommended actions associated with the review. The team performed several walkdowns of the Unit 1 and Unit 2 RWSTs looking at the external condition of the tank and the tank welds. The team also reviewed the most recent internal and external inspection reports for both the Unit 1 and Unit 2 RWSTs. The team also reviewed corrective action documents and system health reports to determine whether there were any adverse operating trends, system leakage, or existing issues affecting tank integrity.
b. Findings
No findings were identified.
.2.2.3 NRC Information Notice 2011-12: Reactor Trips Resulting from Water Intrusion into
Electrical Equipment
a. Inspection Scope
The team evaluated PSEGs applicability review and disposition of NRC IN 2011-12.
The NRC issued the IN to inform licensees of several events involving water intrusion into electrical equipment that resulted in reactor trips. PSEG initiated order 70126964 to address potential reactor trip risk vulnerabilities that could result from water intrusion.
The team reviewed the information to assess the current vulnerabilities identified to determine if PSEG took effective and timely corrective actions commensurate with the risk to the station. The team also interviewed station personnel assigned with corrective actions to understand the status. The team performed several independent walkdowns of the auxiliary building (including the emergency diesel generators and vital switchgear rooms), SW intake motor control centers (MCCs), fire pump house, main control room, and turbine building to assess the material condition, operating environment, and potential vulnerability to water intrusion. The team also performed a CAP review to ensure that PSEG appropriately identified and resolved water intrusion issues (see also Section 1R21.2.1.7).
b. Findings
No findings were identified.
.2.2.4 NRC Information Notice 2012-14: Motor-Operated Valve Inoperable Due To Stem-Disc
Separation
a. Inspection Scope
The team evaluated PSEGs applicability review and disposition of NRC IN 2012-14.
The NRC issued this IN to inform licensees about an event where a MOV failed at the connection between the valve stem and disc. The team reviewed PSEGs actions relative to the conditions described within the lN to ensure that PSEG had performed appropriate evaluations for the Salem Units. The team interviewed the MOV program engineer, reviewed a sample of valve diagnostic test results and trending, and reviewed a sample of PSEGs remote valve position verifications to independently assess Salem MOV susceptibility to this failure mechanism.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA2 Identification and Resolution of Problems (IP 71152)
a. Inspection Scope
The team reviewed a sample of problems that PSEG had previously identified and entered into the CAP. The team reviewed these issues to verify an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions. In addition, the team reviewed corrective action NOTFs written on issues identified during the inspection to verify adequate problem identification and incorporation of the problem into the CAP. The specific corrective action documents that the team sampled and reviewed are listed in the attachment.
b. Findings
No findings were identified.
4OA6 Meetings, Including Exit
On July 24, 2014, the team presented the inspection results to Mr. Lawrence Wagner, Salem Plant Manager, and other members of PSEG management. The team reviewed proprietary information and returned the associated documents to PSEG at the end of the inspection. The team verified that no proprietary information is documented in the report.
=SUPPLEMENTAL
INFORMATION=
KEY POINTS OF CONTACT
PSEG Personnel
- J. Bergeron, I&C Manager
- M. Brummitt, Nuclear Shift Supervisor
- K. Chambliss, Regulatory Assurance Manager
- M. Crawford, Senior Mechanical Design Engineer (PSEG Contractor)
- R. DeNight Jr., Operations Director
- P. Essner, Electrical Engineer
- A. Garcia, Senior Nuclear Engineer
- K. King, Regulatory Assurance
- D. Lafleur, Regulatory Assurance
- G. Morrison, Senior Mechanical Design Engineer
- K. Musante, AOV Program Engineer
- L. Oberembt, Manager, System Engineering
- J. Okulewicz, RHR System Engineer
- J. Owad, Nuclear Engineer
- M. Pennington, Nuclear Engineer
- G. Stafford, AFW System Engineer
- L. Wagner, Plant Manager, Salem
- K. Wolf, Senior Nuclear Engineer
NRC Personnel
C. Cahill Senior Reactor Analyst
P. Finney Senior Resident Inspector
A. Ziedonis Resident Inspector
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
Open and
Closed
- 05000272 & 311/2014007-01 NCV Failure to identify degraded conditions associated with the Unit 1 and Unit 2 RWST and AFWST panels. (Section 1R21.2.1.7)