IR 05000272/2012003

IR 05000272-12-003, 05000311-12-003; 04/01/2012 - 06/30/2012; Salem Nuclear Generating Station Units 1 and 2; Maintenance Effectiveness and Operability Determinations and Functionality Assessments

ML12223A464
Person / Time
Site:	Salem
Issue date:	08/10/2012
From:	Arthur Burritt Reactor Projects Branch 3
To:	Joyce T Public Service Enterprise Group
Burritt A
References
IR-12-003
Download: ML12223A464 (44)

Text

{{#Wiki_filter:UNITED STATES NUCLEAR REGULATORY COMMISSION ust 10, 2012

SUBJECT:

SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 - NRC INTEGRATED INSPECTION REPORT 05000272/2012003 AND 05000311/2012003

Dear Mr. Joyce:

On June 30, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Salem Nuclear Generating Station, Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on July 12, 2012, with Mr. Fricker, Vice President of Salem Operations, 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.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents one NRC identified and two self-revealing findings of very low safety significance (Green). These findings were determined to involve violations of NRC requirements. Additionally, a licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. However, because of the very low safety significance, and because they are entered into your corrective action program (CAP), the NRC is treating these findings as non-cited violations (NCVs) consistent with Section 2.3.2 of the NRC Enforcement Policy. If you contest any 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 Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Salem Nuclear Generating Station. In addition, if you disagree with the cross-cutting aspect assigned to any 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 1, and the NRC Resident Inspector at 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 public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely, /RA/ Arthur L. Burritt, Chief Reactor Projects Branch 3 Division of Reactor Projects Docket Nos.: 50-272, 50-311 License Nos.: DPR-70, DPR-75

Enclosure:

Inspection Report 05000272/2012003 and 05000311/2012003 w/Attachment: Supplementary Information

REGION I== Docket Nos.: 50-272, 50-311 License Nos.: DPR-70, DPR-75 Report No.: 05000272/2012003 and 05000311/2012003 Licensee: PSEG Nuclear LLC (PSEG) Facility: Salem Nuclear Generating Station, Unit Nos. 1 and 2 Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: April 1, 2012 through June 30, 2012 Inspectors: D. Schroeder, Senior Resident Inspector P. McKenna, Resident Inspector R. Nimitz, Senior Health Physicist Approved By: Arthur L. Burritt, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000272/2012003, 05000311/2012003; 04/01/2012 - 06/30/2012; Salem Nuclear

Generating Station Units 1 and 2; Maintenance Effectiveness and Operability Determinations and Functionality Assessments.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified three findings of very low safety significance (Green), which were NCVs. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). The cross cutting aspect of the findings were determined using IMC 0310, Components Within the Cross-Cutting Areas.

Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

Green.

A self-revealing non-cited violation (NCV) of Technical Specification (TS) 6.8.1.a Procedures and Programs, was identified because the 13 service water (SW) strainer failed while in-service on March 13, 2012. PSEG failed to perform adequate post-maintenance testing (PMT) on the 13 SW strainer before declaring it operable on January 13, 2012, and therefore did not find inadequate clearance between the strainer drum and body. This issue was entered into PSEGs corrective action program (CAP) as notification 20550115. PSEGs immediate corrective actions were to replace the strainer drum o-ring, adjust the strainer clearances and perform a PMT of the strainer.

The inspectors determined that the performance deficiency was more than minor because it was associated with the human performance attribute of the Mitigating Systems cornerstone, and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the trip of the 13 SW strainer while the 14 SW pump was inoperable for planned maintenance resulted in Salem Unit 1 entering a 72 hour unplanned limiting condition for operation (LCO) for 11.5 hours. The finding was evaluated in accordance with IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, and was determined to require additional evaluation. The finding was subsequently evaluated in IMC 0609, Phase 3 utilizing the NRCs SAPHIRE 8 risk analysis SDP interface tool using the Salem specific standardized plant analysis review (SPAR)model, and confirmed to be of very low safety significance. This finding has a cross-cutting aspect in the area of human performance, work practices, because PSEG personnel did not follow procedures. Specifically, PSEG personnel failed to comply with procedure Service Water Auto Strainer Adjustment, Inspection, Repair and Replacement, which required an evaluation of a torque curve generated by a baker box. (H.4(b)) (Section 1R12)

Green.

A self-revealing NCV of 10 Code of Federal Regulation (CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, was identified because PSEG did not correct a condition adverse to quality. Specifically, repeat failures of solenoid operated valves (SOVs) with voltage applied greater than design voltage was not been corrected in a timely manner and caused a failure of the 11 control area chiller (CAC).

The performance deficiency was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, the inspectors determined that a single train of a safety-related system was unavailable for eight hours, less than the TS allowed outage time. Therefore, the issue was of very low safety significance (Green) because it did not result in a loss of system safety function, loss of a single train for greater than TS allowed outage time, or potentially risk-significant due to a fire, flooding, or severe weather initiating event. Immediate corrective actions taken included replacement of the failed SOV, and compensatory measures include periodic temperature monitoring of similar energized SOVs. This finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program, because PSEG did not take appropriate corrective actions to address a safety issue in a timely manner, commensurate with the safety significance and complexity. Specifically, the premature failure of SOVs, due to a higher than design voltage that created higher than design heat in the coil and insulation, was a known issue that was not corrected in a timely manner. (P.1(d)) (Section 1R12)

Green.

The inspectors identified a NCV of TS 6.8.1.a Procedures and Programs, because PSEG failed to properly control and store transient material within seismic class I buildings such that the equipment did not pose a hazard to safe plant operation. Specifically, two large tool gang boxes were stored unrestrained in the vicinity of the sodium hydroxide storage tank and associated containment spray (CS) valves and two full 55 gallon SW maintenance drums were stored unrestrained next to the 11, 12, and 15 containment fan cooler unit (CFCU) SW flow transmitters. This issue was entered into PSEGs CAP as notification 20559092. PSEGs immediate corrective actions were to restrain the subject material in accordance with the PSEG procedure CC-AA-320-011, Transient Loads.

The performance deficiency was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The issue was also similar to IMC 0612, Appendix E, Examples of Minor Issues, example 4.a which stated the issue was more than minor if the licensee routinely failed to follow their procedure and safety-related equipment was adversely impacted. Specifically, PSEG was not following the requirements of procedure CC-AA-320-011, Transient Loads, and equipment had been stowed in close vicinity of safety-related equipment. The finding was evaluated under IMC 0609, Attachment 4, Initial Screening and Characterization of Findings. The inspectors determined that the finding is of very low safety significance (Green) because it did not involve loss or degradation of equipment specifically designed to mitigate a seismic event, and did not involve total loss of a safety function that contributes to external event initiated core damage sequences. The finding has a cross-cutting aspect in the area of human performance, work practices, in that PSEG did not define and effectively communicate expectations regarding procedural compliance and personnel did not follow procedures. Specifically, station personnel did not follow procedures for the storage of transient loads in the auxiliary building (H.4(b)) (Section 1R15)

Other Findings

A finding of very low safety significance that was identified by PSEG was reviewed by the inspectors. Corrective actions taken or planned by PSEG have been entered into PSEGs CAP. This violation and corrective action tracking number are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Salem Nuclear Generating Station Unit 1 (Unit 1) began the period at 100 percent power. On April 24, 2012, plant operators reduced power to 89 percent due to transmission line 5015 maintenance and then to 75 percent for main turbine valve testing. Unit 1 returned to 89 percent power on April 24, 2012 and then to 100 percent power on April 28, 2012. On April 30, 2012, Unit 1 experienced a trip and an inadvertent safety injection signal. Unit 1 was placed in Mode 5 for maintenance and troubleshooting of the reactor protection system (RPS). Unit 1 returned to 100 percent power on May 8, 2012. On June 25, 2012 plant operators reduced power to 91 percent due to a tube leak in the 13B feedwater heater. Unit 1 returned to 100 percent power on June 28, 2012. Unit 1 remained at 100 percent power for the remainder of the period.

Salem Nuclear Generating Station Unit 2 (Unit 2) began the period at 100 percent power. On June 13, 2012, plant operators reduced power to 98 percent due to the 21 moisture separator reheater being removed from service. Operators returned Unit 2 to full power on June 15, 2012.

Unit 2 remained at 100 percent power for the remainder of the period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors performed a review of PSEGs readiness for the onset of seasonal high temperatures. The review focused on SW, component cooling water (CCW), and the emergency diesel generators (EDGs). The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), TSs, control room logs, and the CAP to determine what temperatures or other seasonal weather could challenge these systems, and to ensure PSEG personnel had adequately prepared for these challenges. The inspectors reviewed station procedures, including PSEGs seasonal weather preparation procedure and applicable operating procedures. The inspectors performed walkdowns of the selected systems to ensure station personnel identified issues that could challenge the operability of the systems during hot weather conditions. Documents reviewed for each section of this inspection report are listed in the Attachment.

b. Findings

No findings were identified.

.2 Summer Readiness of Offsite and Alternate Alternating Current (AC) Power Systems

a. Inspection Scope

The inspectors performed a review of plant features and procedures for the operation and continued availability of the offsite and alternate AC power system to evaluate readiness of the systems prior to seasonal high grid loading. The inspectors reviewed PSEGs procedures affecting these areas and the communications protocols between the transmission system operator and PSEG. This review focused on changes to the established program and material condition of the offsite and alternate AC power equipment. The inspectors assessed whether PSEG established and implemented appropriate procedures and protocols to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system. The inspectors evaluated the material condition of the associated equipment by interviewing the responsible system manager, reviewing notifications and open work orders, and walking down portions of the offsite and AC power systems including the 500 kilovolt (KV) switchyard.

b. Findings

No findings were identified. ==1R04 Equipment Alignment Partial System Walkdowns (71111.04Q - 4 samples)

   ==

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems: Unit 2 EDGs with a single source of offsite power on April 5, 2012 1A and 1B EDGs with 1C EDG out of service (OOS) on May 16, 2012 21 and 22 auxiliary feedwater (AFW) pumps with 23 AFW pump OOS on May 16, 2012 21 CCW pump after return from maintenance on May 31, 2012 The inspectors selected these systems based on their risk significance relative to the reactor cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the UFSAR, TSs, work orders, notifications, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. The inspectors also reviewed whether PSEG staff had properly identified equipment issues and entered them into the corrective action program for resolution with the appropriate significance characterization.

b. Findings

No findings were identified. ==1R05 Fire Protection