IR 05000272/2012004
| ML12313A083 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 11/08/2012 |
| From: | Arthur Burritt Reactor Projects Branch 3 |
| To: | Joyce T Public Service Enterprise Group |
| BURRITT, AL | |
| References | |
| IR-12-004 | |
| Download: ML12313A083 (32) | |
Text
UNITED STATES ber 8, 2012
SUBJECT:
SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 -
NRC INTEGRATED INSPECTION REPORT 05000272/2012004 AND 05000311/2012004
Dear Mr. Joyce:
On September 30, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Salem Nuclear Generating Station, Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on October 4, 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 self-revealing finding of very low safety significance (Green). This finding was determined to involve a violation of NRC requirements. However, because of the very low safety significance, and because it is entered into your corrective action program, the NRC is treating this 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 Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, U. S.
Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at 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 for your disagreement, to the Regional Administrator, Region I, 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 the 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 05000272/2012004 and 05000311/2012004 w/Attachment: Supplementary Information
REGION I==
Docket Nos.: 50-272, 50-311 License Nos.: DPR-70, DPR-75 Report No.: 05000272/2012004 and 05000311/2012004 Licensee: PSEG Nuclear LLC (PSEG)
Facility: Salem Nuclear Generating Station, Units 1 and 2 Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: July 1, 2012 through September 30, 2012 Inspectors: D. Schroeder, Senior Resident Inspector P. McKenna, Resident Inspector J. Schoppy, Senior Reactor Inspector E. H. Gray, Senior Reactor Inspector R. Nimitz, Senior Health Physicist A. Turilin, Project Engineer Approved By: Arthur L. Burritt, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR 05000272/2012004, 05000311/2012004; 07/01/2012 - 09/30/2012; Salem Nuclear
Generating Station Units 1 and 2; Surveillance Testing.
This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified one finding of very low safety significance (Green), which was a non-cited violation (NCV). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). The cross-cutting aspects for 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 Green NCV of TS 3.7.1.2.a, Auxiliary Feedwater System, was identified because the 23 steam generator flow control valve from the 21 AFW pump opened unexpectedly during the in service test of the 21 AFW pump on July 5, 2012.
PSEG determined that the air supply to the valve was incorrectly isolated during previous surveillance testing, which caused the valve to fully open when the 21 AFW pump was started and prevented operators from closing it using the valve control switch in the control room. This alignment directed full flow from the 21 AFW pump to the 23 SG during performance of the surveillance test, which adversely affected level control for that SG and required operators to declare the 21 AFW pump inoperable. PSEG entered the issue into the CAP as notification 20566493.
The performance deficiency is more than minor because it is associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Using IMC 0609,
Appendix A, The Significance Determination Process for Findings at Power, the inspectors determined that the finding was of very low safety significance (Green) because the system maintained the ability to inject water into each of the steam generators. Senior Risk Analyst review determined that the valve failure to close is not modeled in sequences which could lead to core damage. The inspectors determined that this finding has a cross-cutting aspect in the area of human performance, work practices, because PSEG did not adequately communicate expectations regarding human error prevention techniques H.4(a).
Specifically, as required by the sites human performance error prevention technique procedures, flagging and robust barriers were not used in a situation where multiple similar components existed within close proximity to each other. This resulted in the isolation of the air regulator valve for valve 23AF21, which resulted in inoperability of the 21 AFW pump.
REPORT DETAILS
Summary of Plant Status
The Salem Nuclear Generating Station Unit 1 (Unit 1) operated at or near full rated thermal power for the duration of the inspection period except for brief periods to support planned testing.
The Salem Nuclear Generating Station Unit 2 (Unit 2) operated at or near full rated thermal power for the duration of the inspection period except for brief periods to support planned testing.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
.1 External Flooding
a. Inspection Scope
During the week of September 17, 2012, the inspectors performed an inspection of the external flood protection measures for Salem Unit 2, in conjunction with Temporary Instruction 2515/187. The inspectors reviewed the updated final safety analysis report (UFSAR), Chapter 3.4, which depicted the design flood levels and protection areas containing safety-related equipment to identify areas that may be affected by external flooding. Specifically, the inspectors reviewed the condition of the Unit 2 electrical penetration room external flood protection, with emphasis placed on the sealing of equipment below the flood line, such as electrical conduits. The inspectors verified that degraded conditions with the potential to impact safety-related components and systems were reported in the corrective action program. Corrective action notifications written for degraded conditions were reviewed to ensure that operability of components in the electrical penetration room were not impacted. Documents reviewed for each section of this inspection report are listed in the Attachment.
b. Findings
No findings were identified.
1R04 Equipment Alignment
.1 Partial System Walkdowns
a. Inspection Scope
The inspectors performed partial walkdowns of the following systems:
Unit 2 service water (SW) with the 24 SW pump out of service (OOS) during the week of August 6, 2012 21 residual heat removal (RHR) pump and heat exchanger with the 22 RHR pump OOS on August 7, 2012 Unit 1 chemical volume control (CVC) with the 11 CVC pump OOS on September 5, 2012 The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the UFSAR, TSs, work orders, condition reports, 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
.1 Resident Inspector Quarterly Walkdowns
a. Inspection Scope
The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that PSEG controlled combustible materials and ignition sources in accordance with administrative procedures. The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan, and passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for OOS, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.
Unit 3 Jet Combustion Turbine and Station Blackout Air Compressor on July 5, 2012 Unit 1 Turbine Generator Building, 100 elevation, on July 12, 2012 Unit 1 Turbine Generator Building, 120 elevation, on July 16, 2012 Unit 1 Mechanical Piping Penetration Area, 78 and 100 elevations, on August 21, 2012 Unit 1 Fuel Handling Building, 84, 100 and 116 elevations, on August 21, 2012
b. Findings
No findings were identified.
1R06 Flood Protection Measures
Annual Review of Cables Located in Underground Bunkers/Manholes
a. Inspection Scope
The inspectors conducted an inspection of underground bunkers/manholes subject to flooding that contain cables whose failure could disable risk-significant equipment. The inspectors performed walkdowns of risk-significant areas, including manholes HH 1 through 4 containing switchyard breaker control power cables and manholes SW1-1 east and west end sections containing power cables for the SW intake structure, to verify that the cables were not submerged in water, that cables and/or splices appeared intact, and to observe the condition of cable support structures. The inspectors also ensured that drainage was provided and functioning properly in areas where dewatering devices were not installed.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program
.1 Quarterly Review of Licensed Operator Requalification Testing and Training
a. Inspection Scope
The inspectors observed licensed operator simulator training on August 29, 2012, which included a main power transformer (MPT) failure, and an inadvertent safety injection (SI), followed by a steam generator tube rupture and a reactor coolant system leak that created a radiological release path and the need for an event classification. The inspectors evaluated operator performance during the simulated event and verified completion of risk significant operator actions, including the use of abnormal and emergency operating procedures. The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. The inspectors verified the accuracy and timeliness of the emergency classification made by the shift manager and the technical specification action statements entered by the shift technical advisor. Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.
b. Findings
No findings were identified.
.2 Quarterly Review of Licensed Operator Performance in the Main Control Room
a. Inspection Scope
The inspectors observed and reviewed the Unit 2 solid state protection system (SSPS)train B 48 volt DC power supply replacement on August 27, 2012, and the 13 AFW pump quarterly in-service testing, Unit 2 time response testing of engineered safety features, 11 SI pump start and filling of 14 SI accumulator, and Unit 2 deborating flush on September 26, 2012 through September 27, 2012. The inspectors assessed the adequacy of communications, the pre-job brief, procedure use, human performance tools, and the oversight and direction provided by the control room supervisor.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, and component (SSC) performance and reliability. The inspectors reviewed system health reports, corrective action program documents, maintenance work orders, and maintenance rule basis documents to ensure that PSEG was identifying and properly evaluating performance problems within the scope of the maintenance rule. For each sample selected, the inspectors verified that the SSC was properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and verified that the (a)(2) performance criteria established by PSEG staff was reasonable. As applicable, for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2). Additionally, the inspectors ensured that PSEG staff was identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries.
13 and 23 positive displacement charging pumps during the week of September 24, 2012 Unit 2 SW during the week of September 24, 2012
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed station evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that PSEG performed the appropriate risk assessments prior to removing equipment for work. The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that PSEG personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When PSEG performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk.
The inspectors reviewed the scope of maintenance work and discussed the results of the assessment with the stations probabilistic risk analyst to verify plant conditions were consistent with the risk assessment. The inspectors also reviewed the TS requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.
Max emergency generation action with 21 auxiliary building ventilation supply fan, 21 core spray pump, and 25 SW pump OOS on July 18, 2012 22 control air supply fan, 24 SW pump, and 22 RHR pump OOS for planned maintenance on August 7, 2012 (yellow risk)
Emergent unavailability of the 25 SW pump concurrent with planned maintenance on the 24 SW pump work on August 8, 2012 Emergent loss of one 48 VDC Power Supply on Unit 2 SSPS Train B during week of August 19, 2012
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
a. Inspection Scope
The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:
River water temperature greater than 90 F on July 5, 2012 Evaluation of loose bolting found bolting found on the SI pump/charging pump lube oil coolers on August 7, 2012 11 SW strainer drum and body clearance on August 13, 2012 Unit 2 SSPS with 48 Vdc power supply failure on SSPS B on August 23, 2012 General Electric 4 kV breakers on September 6, 2012 12MS9 body to bonnet steam leak on September 11 - 14, 2012 The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determinations to assess whether TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and UFSAR to PSEGs evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled by PSEG. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.
b. Findings
No findings were identified.
1R18 Plant Modifications
a. Inspection Scope
The inspectors reviewed a temporary plant modification (2ST-12-006) which replaced the pivot point anchor button on the 2A reactor trip bypass breaker with a high tensile strength 3/8 socket head screw and lock nut. The pivot point is located on the sliding mechanism that is used to rack the breaker in and out. The inspectors reviewed this temporary modification to determine whether the modification affected the safety functions of systems that are important to safety. The inspectors reviewed 10 CFR 50.59 documentation and post-modification testing results, and conducted field walkdowns of the modification to verify that the temporary modification did not degrade the design bases, licensing bases, and performance capability of the affected systems.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the post-maintenance tests for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure was consistent with the information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed test data to verify that the test results adequately demonstrated restoration of the affected safety functions.
14 SW strainer bonnet replacement on July 16, 2012 22 RHR pump and 24RH4 suction valve planned maintenance on August 7, 2012 25 SW pump motor replacement on August 16, 2012 Unit 2 SSPS B planned maintenance on August 27, 2012 25 containment fan cooler unit planned maintenance on September 12 - 13, 2012 2C emergency diesel generator (EDG) preventive maintenance on September 13 -
14, 2012
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied TSs, the UFSAR, and PSEG procedure requirements. The inspectors verified that test acceptance criteria were clear, tests demonstrated operational readiness and were consistent with design documentation, test instrumentation had current calibrations and the range and accuracy for the application, tests were performed as written, and applicable test prerequisites were satisfied. Upon test completion, the inspectors considered whether the test results supported that equipment was capable of performing the required safety functions. The inspectors reviewed the following surveillance tests:
S2.OP-ST.AF-0001, 21 AFW Pump Surveillance Test on July 5, 2012 S1.OP-ST.RCS-0001, S1RCS Rod Control System Monthly Surveillance Test on July 26, 2012 S2.OP-ST.DG-0001, 2A EDG Surveillance Test on August 2, 2012 S2.OP-PT.AF-0003, 23 AFW Pump Periodic Run on August 15, 2012 S1.MD-FT.SEC-0003, 1C Safeguards Equipment Control Sequencer Surveillance Test on August 15, 2012 S1.MD-FT.4KV-0001, 1A 4kV Vital Bus Undervoltage Test on August 29, 2012
b. Findings
Introduction:
A self-revealing Green NCV of TS 3.7.1.2.a, Auxiliary Feedwater System, was identified because the 23 steam generator flow control valve from the 21 AFW pump opened unexpectedly during the in service test of the 21 AFW pump on July 5, 2012. PSEG determined that the air supply to the valve was incorrectly isolated during previous surveillance testing, which caused the valve to fully open when the 21 AFW pump was started and prevented operators from closing it using the valve control switch in the control room. This alignment directed full flow from the 21 AFW pump to the 23 SG during performance of the surveillance test, which adversely affected level control for that SG and required operators to declare the 21 AFW pump inoperable.
Description:
The 23AF21 valve is an air to close valve used to control flow from the 21 AFW pump to the 23 SG. When the 21 AFW pump was started for IST testing on July 5, 2012, because the air supply to the flow control valve was previously isolated, the valve failed open. This directed full flow to the 23 SG, which adversely affected level control for that SG. Operators declared the 21 AFW pump and the 23AF21 containment isolation valve inoperable and entered the appropriate limiting conditions for operation.
Through its troubleshooting PSEG identified the isolated air supply to the associated electric-pneumatic converter, restored the appropriate valve line-up for the converter and returned the 21 AFW pump to service after successfully completing IST surveillance testing later that day on July 5, 2012.
PSEG conducted a root cause evaluation and identified three probable causes for the mispositioned isolation valve. Each probable cause was associated with a human performance error that occurred during maintenance or testing conducted on equipment in the vicinity of the valve found out of position. The PSEG root cause evaluation concluded that the error most likely occurred during the conduct of maintenance on April 27, 2012, or May 16, 2012. Multiple control air regulators are located in the instrumentation cabinet containing the mispositioned valve, including an unlabeled installed spare air regulator that is periodically used to perform maintenance and surveillance tests.
The inspector walked down the associated instrumentation cabinet and reviewed PSEG procedure HU-AA-101, Human Performance Tools and Verification Practices, that requires the use of flagging or robust operational barriers if multiple similar components exist within close proximity. Based on the conditions observed in the cabinet the inspectors determined that since the affected equipment was multiple similar components located in close proximity, the use of flagging or robust operational barriers during operation of equipment in the affected cabinet may have prevented the mispositioning of the control air valve and the associated inoperability of the 21 AFW pump. The inspectors also determined through a review of the procedures used to conduct maintenance and testing on the equipment located in the cabinet, discussions with technicians who conducted such maintenance, and reviews of work order documentation associated with this maintenance and testing that flagging or robust operational barriers were not routinely used by PSEG technicians for the associated maintenance.
PSEGs review of maintenance recently completed in the associated instrumentation cabinet determined that the 21 AFW pump may have been inoperable for as long as 91 days, which was longer than the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed by the technical specifications without implementing the requirements of the TS action statements.
In response to the identified issue, PSEGs prompt corrective actions included labeling and tagging the air supply regulator that was used to supply air for other instrumentation calibration and testing and planned corrective actions included revisions to the sites maintenance alteration process. The planned revision to this process will require that all alterations to positionable components be reviewed and approved by a licensed SRO, and that a revision to the control of equipment and system status will prohibit the operation of unlabeled equipment in the power block.
Analysis:
The inspectors concluded that the failure of PSEG to properly control the position of the air supply valve to the 23 steam generator flow control valve was a performance deficiency. Specifically, the PSEG root cause evaluation concluded that the air supply valve position was changed from open to closed due to a human performance error during the conduct of maintenance or operations on April 27, or May 16, 2012. When the 21 AFW pump was started for a surveillance test on July 5, 2012, the motor driven AFW pump flow control valve to the 23 steam generator went open unexpectedly, and could not be closed from the control room. PSEG determined that this event was a safety system functional failure, because operators may not have been able to terminate AFW flow to a faulted steam generator within the ten minute time requirement. The performance deficiency is more than minor because it is associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage).
Using IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, the inspectors determined that the finding was of very low safety significance (Green) because the system maintained the ability to inject water into each of the steam generators. Senior Risk Analyst review determined that the valve failure to close is not modeled in sequences which could lead to core damage.
The inspectors determined that this finding has a cross-cutting aspect in the area of human performance, work practices, because PSEG did not adequately communicate expectations regarding human error prevention techniques. Specifically, as required by the sites human performance error prevention technique procedures, flagging and robust barriers were not used in a situation where multiple similar components existed within close proximity to each other. This resulted in the isolation of the air regulator valve for valve 23AF21, which resulted in inoperability of the 21 AFW pump H.4(a).
Enforcement:
TS 3.7.1.2.a, Auxiliary Feedwater System, requires at least three independent steam generator auxiliary feedwater pumps and associated manual activation switches in the control room and flow paths shall be operable. The associated Limiting Condition for Operation Action Statement requires that with one auxiliary feedwater pump inoperable, restore the required auxiliary feedwater pump to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in hot standby in the next six hours. TS 3.6.3.1, Containment Isolation Valves, states that each containment isolation valve shall be operable. The associated Limiting Condition for Operation Action Statement requires that the inoperable valve be restored to operable status within four hours, or isolate the affected penetration within four hours. Contrary to the above, the 21 AFW pump was inoperable for a period of more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> due to a mispositioned air regulator valve.
PSEG determined that the air supply valve for 23AF21 was most likely mispositioned due to a human performance error on April 27, 2012, or May 16, 2012. Additionally, the containment isolation function of the 23AF21 valve was inoperable for a period of more than four hours without taking the required action. Upon discovery, PSEG plant operators took appropriate actions to comply with TS 3.7.1.2.a and TS 3.6.3.1. Because this issue is of very low safety significance (Green) and PSEG entered the issue into the CAP as notification 20566493, this violation is being treated as an NCV consistent with the NRC Enforcement Policy. (NCV 05000311/2012004-01, Inadvertent Injection of Auxiliary Feedwater into the 23 Steam Generator)
RADIATION SAFETY
Cornerstone: Public Radiation Safety
2RS6 Radioactive Gaseous and Liquid Effluent Treatment
This area was inspected during the week of July 23, 2012, and September 10, 2012.
The inspectors selectively reviewed aspects of PSEGs gaseous and liquid effluent control program in the areas listed below.
.1 Inspection Planning and In-Office Reviews
Event Report and Effluent Report Reviews
a. Inspection Scope
The inspectors reviewed the Radiological Effluent Release Reports issued, since the last inspection, to determine if the reports were submitted as required by the offsite dose calculation manual (ODCM)/TSs. The inspectors reviewed the reports for any anomalous results, unexpected trends, or abnormal releases identified by PSEG for further inspection.
The inspectors reviewed the reports to identify radioactive effluent monitor operability issues reported by PSEG as provided in effluent release reports. The inspectors also reviewed groundwater remediation reports.
b. Findings
No findings were identified.
a. Inspection Scope
The inspectors reviewed the UFSAR descriptions of the radioactive effluent monitoring systems, treatment systems, and effluent flow paths to verify during inspection walkdowns.
b. Findings
No findings were identified.
2RS7 Radiological Environmental Monitoring Program (REMP)
This area was inspected during the week of July 23, 2012, and September 10, 2012, to verify that:
- (1) the Radiological Environmental Monitoring Program (REMP) accurately quantifies the impact of radioactive effluent releases to the environment and sufficiently validates the integrity of the radioactive gaseous and liquid effluent release program; (2)the REMP is implemented consistent with regulatory requirements contained in TSs, the ODCM, and the design objectives in Appendix I to 10 CFR Part 50;
- (3) the REMP monitors non-effluent exposure pathways (e.g., onsite spills or leaks, exposures from direct and scattered (skyshine) radiation from plant facilities and components);
- (4) the REMP is based on sound principles and assumptions; and
- (5) the REMP validates that doses to members of the public were within the dose limits of 10 CFR Part 20, Standards for Protection against Radiation, and 40 CFR Part 190, Environmental Radiation Protection Standards for Nuclear Power Operations.
The inspectors used the requirements in 10 CFR Part 20, 40 CFR Part 190, 10 CFR 50 Appendix I, TSs, the ODCM, and station program procedures as criteria for determining compliance.
.1 Inspection Planning
a. Inspection Scope
The inspectors reviewed the annual radiological environmental and effluent operating reports (2010, 2011) and the results of PSEG assessments since the last inspection to verify that the REMP was implemented in accordance with the TSs and the ODCM. The inspectors reviewed the last report for changes to the ODCM with respect to environmental monitoring, commitments in terms of sampling locations, monitoring and measurement frequencies, land use census, inter-laboratory comparison program, and analysis of data.
The inspectors reviewed the ODCM and associated maps to identify locations of environmental monitoring stations. The inspectors also reviewed the UFSAR for information regarding the environmental monitoring program and meteorological monitoring instrumentation.
The inspectors reviewed quality assurance audit results of the program to assist in selection of samples. The inspectors reviewed available audits and technical evaluations performed on the vendors program, as applicable, if used to analyze REMP samples.
The inspectors reviewed the annual effluent release report and the 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste, report to determine if PSEG was sampling for the predominant and dose-causing radionuclides likely to be released in effluents.
b. Findings
No findings were identified.
.2 Site Inspection
a. Inspection Scope
The inspectors walked down and observed sample collection for air sampling stations (5S1, 5S2, 5D1, 1F1, 2F6), thermoluminescent dosimeter (TLD) monitoring stations (5S1/2, 5D1, 3E1, 1F1, 2F6), and one well water station (3E1) to determine whether they were located as described in the ODCM. The inspectors also reviewed PSEG garden placement and fodder crop sampling. The inspectors reviewed material conditions of monitoring equipment, as appropriate. The inspectors selected air sampling station locations based on the locations with the highest X/Q, D/Q wind sectors, and the inspectors selected the TLDs based on the most risk-significant locations.
For the air samplers and TLDs, the inspectors reviewed the calibration and maintenance records/data (orifices, vacuum gauge) to verify that they demonstrate adequate operability of these components.
The inspectors evaluated PSEG criteria, as appropriate, for sampling of other media upon loss of a required sampling station.
The inspectors observed the collection and preparation of various environmental samples from different environmental media (particulate and iodine air monitoring stations, one well water sample). The inspectors evaluated the environmental sampling to ensure it was representative of the release pathways as specified in the ODCM and that sampling techniques were in accordance with procedures.
Based on direct observation and review of records, the inspectors verified that the meteorological instruments were operable, calibrated, and maintained in accordance with guidance contained in the UFSAR, NRC Regulatory Guide 1.23, Meteorological Monitoring Programs for Nuclear Power Plants, and PSEG procedures. The inspectors verified that the meteorological data readout and recording instruments in the control room and at the tower were operable. The inspectors toured the meteorological tower and reviewed meteorological data readouts. The inspectors compared readouts with control room indications. The inspectors reviewed monthly meteorological monitoring reports, including availability. The inspectors evaluated potential impact of trees or other foliage on instrument readouts.
The inspectors verified that missed and/or anomalous environmental samples were identified and reported in the annual environmental monitoring report. As available, the inspectors selected events that involved a missed sample, inoperable sampler, lost TLD, or anomalous measurement and verified that PSEG had identified the cause and has implemented corrective actions. The inspectors reviewed and discussed PSEGs assessment of any positive sample results (i.e., licensed radioactive material detected above the lower limits of detection). The inspectors reviewed, as appropriate, the associated radioactive effluent release data that was the source of the released material.
The inspectors selected SSCs that involve or could reasonably involve licensed material for which there is a credible mechanism for licensed material to reach groundwater and verified that PSEG had implemented a sampling and monitoring program sufficient to detect leakage of these SSCs to groundwater. The inspectors reviewed Radiological Ground Water Protection Program Reports and also reviewed various Quarterly Ground Water Remedial Action Progress Reports.
The inspectors discussed and reviewed records to verify that records of leaks, spills, and remediation, as required by 10 CFR 50.75(g), were being retained in a retrievable manner.
The inspectors reviewed any significant changes made by PSEG to the ODCM as the result of changes to the land use census, long-term meteorological conditions (e.g.,
three-year average) or modifications to the sampling stations. The inspectors reviewed technical justifications for any changed sampling locations. The inspectors verified that PSEG performed the reviews required to ensure that the changes did not affect its ability to monitor the impacts of radioactive effluent releases to the environment.
The inspectors verified that appropriate detection sensitivities were used for counting samples with respect to TS/ODCM. The inspectors reviewed quality control charts for maintaining radiation measurement instrument status and actions taken for degrading detector performance, as applicable. Vendor laboratory analysis results for REMP samples and the results of the vendors quality control program, including the inter- and intra-laboratory comparison program, were reviewed to verify the adequacy of the vendors program.
The inspectors reviewed the results of PSEGs inter-laboratory comparison program to verify the adequacy of environmental sample analyses performed by PSEG. The inspectors selectively verified that the inter-laboratory comparison test included the media/nuclide mix appropriate for the facility. The inspectors reviewed, as applicable, PSEGs determination of any bias to the data and the overall effect on the REMP.
b. Findings
No findings were identified.
.3 Identification and Resolution of Problems
a. Inspection Scope
The inspectors determined if problems associated with the REMP were being identified by PSEG at an appropriate threshold and were properly addressed for resolution in the corrective action program. In addition to the above, the inspectors verified the appropriateness of the corrective actions for a selected sample of problems documented by PSEG that involve the REMP.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
Mitigating Systems Performance Index (6 samples)
a. Inspection Scope
The inspectors reviewed PSEGs submittal of the Mitigating Systems Performance Index for the following systems for the period of July 1, 2011 through June 30, 2012:
Unit 1 and Unit 2 AFW systems Unit 1 and Unit 2 RHR systems Unit 1 and Unit 2 SW systems To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors also reviewed PSEGs operator narrative logs, condition reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution
.1 Routine Review of Problem Identification and Resolution Activities
a. Inspection Scope
As required by Inspection Procedure 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that PSEG entered issues into the corrective action program at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the corrective action program and periodically attended condition report screening meetings.
b. Findings
No findings were identified.
.2 Annual Sample: Review of the Operator Workaround Program
a. Inspection Scope
The inspectors reviewed the cumulative effects of the existing operator workarounds, operator burdens, existing operator aids and disabled alarms, and open main control room deficiencies to identify any effect on emergency operating procedure operator actions, and any impact on possible initiating events and mitigating systems. The inspectors evaluated whether station personnel had identified, assessed, and reviewed operator workarounds as specified in PSEG procedure OP-AA-1-2-103, Operator Workaround Program.
The inspectors reviewed PSEGs process to identify, prioritize and resolve main control room distractions to minimize operator burdens. The inspectors reviewed the system used to track these operator workarounds and recent PSEG self assessments of the program. The inspectors also toured the control room and discussed the current operator workarounds with the operators to ensure the items were being addressed on a schedule consistent with their relative safety significance.
b. Findings and Observations
No findings were identified.
The inspectors determined that the issues reviewed did not adversely affect the capability of the operators to implement abnormal or emergency operating procedures.
The inspectors also verified that PSEG entered operator workarounds and burdens into the corrective action program at an appropriate threshold and planned or implemented corrective actions commensurate with their safety significance. Finally, the inspectors determined that PSEG had made progress in improving their Operator Workaround Program based last years self-assessment of the program.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion
.1 (Closed) Licensee Event Report (LER) 05000272/2012-002-0: Service Water Loop
Inoperable for Time Greater Than Allowed by Technical Specifications On March 13, 2012 at 8:10 a.m., the 13 SW pump was started and operated normally.
At 8:54 a.m., a nuclear equipment operator, dispatched due to a strainer trouble alarm, reported that the 13 SW strainer drive motor breaker had tripped on thermal overload.
The 13 SW pump was removed from service and declared inoperable.
The 14 SW pump had been cleared and tagged for scheduled maintenance from January 17 to January 27, 2012. A subsequent apparent cause evaluation identified that the inoperability of the 13 SW pump strainer was related to a maintenance activity on January 13, 2012. The concurrent inoperability of the 13 and 14 SW pumps resulted in a SW loop being inoperable for a time greater than that allowed by TSs.
The cause of the event was determined to be inadequate strainer drum o-ring to body wear ring clearance due to inadequate procedure adherence. The enforcement aspects of this issue are discussed in Section 1R12 of Integrated Inspection Report 05000272; 311/2012003. The inspectors did not identify any new issues during the review of the LER. This LER is closed.
.2 (Closed) LER 05000311/2012-002-0: Auxiliary Feedwater Flow Control Valve Failed
Open with Zero Demand On July 5, 2012, while performing in-service testing of the 21 AFW pump, 23AF21, the AFW flow control valve to the 23 steam generator failed open and could not be closed from the control room. The 21 AFW pump was stopped and the 23AF21 valve closed automatically. The failure of the 23AF21 valve to respond from the control console was due to a mispositioned air supply valve to the 23AF21 valve electro-pneumatic converter. The enforcement aspects of this issue are discussed in Section 1R22 of this report. The inspectors did not identify any new issues during the review of the LER.
This LER is closed.
4OA5 Other Activities
.1 Buried Piping, Temporary Instruction 2515/182, Phase 1
a. Inspection Scope
PSEGs buried piping and underground piping and tanks program were inspected in accordance with paragraphs 03.01 through 03.01.c of Temporary Instruction 2515/182 and was found to meet all applicable aspects of the Nuclear Energy Institute Document 09-14, Revision 1, as set forth in Table 1 of Temporary Instruction 2515/182.
b. Findings
No findings were identified.
.2 Temporary Instruction 2515/187 - Inspection of Near-Term Task Force Recommendation
2.3 - Flooding Walkdowns On September 17, 2012, inspectors commenced activities to independently verify that PSEG conducted external flood protection walkdown activities using an NRC-endorsed walkdown methodology. These flooding walkdowns are being performed at all sites in response to Enclosure 4 of a letter from the NRC to licensees entitled, Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, dated March 12, 2012 (ADAMS Accession No.
ML12053A340). The results of this temporary instruction will be documented in a future inspection report.
.3 Temporary Instruction 2515/188 - Inspection of Near-Term Task Force Recommendation
2.3 - Seismic Walkdowns On September 17, 2012, inspectors commenced activities to independently verify that PSEG conducted seismic walkdown activities using an NRC-endorsed seismic walkdown methodology. These seismic walkdowns are being performed at all sites in response to Enclosure 3 of a letter from the NRC to licensees entitled, Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, dated March 12, 2012 (ADAMS Accession No.
ML12053A340). When complete, the results of this temporary instruction will be documented in a future inspection report.
4OA6 Meetings, Including Exit
On October 4, 2012, the inspectors presented the inspection results to Mr. Fricker, Vice President of Salem Operations, and other members of PSEG management. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.
ATTACHMENT:
SUPPLEMENTARY INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- C. Fricker, Site Vice President
- L. Wagner, Plant Manager
- T. Cachaza, Regulatory Assurance
- J. Garecht, Operations Director
- R. Denight Jr., Operations Supervisor
- J. Kandasamy, Regulatory Affairs Manager
- K. King, Regulatory Assurance
- J. Melchionna, Corporate Underground Piping Supervisor
- D. LaFleura, Regulatory Assurance
- J. Ridgeway, Engineer, Cathodic Protection
- B. Montgomery, Underground Piping and Tanks Program Engineer
- R. Wegner, Maintenance Director
- G. Sosson, Engineering Director
- S. Taylor, Radiation Protection Manager
- J. Stavely, Nuclear Oversight Manager
- F. Leeser, Chemistry Manager
- J. Pantazes, Manager, Nuclear Environmental Affairs
LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED
Opened/Closed
- 05000311/2012004-01 NCV Inadvertent Injection of Auxiliary Feedwater into the 23 Steam Generator (Section 1R22)
Closed
- 05000272/2012-002-0 LER Service Water Loop Inoperable for Time Greater Than Allowed by Technical Specifications (Section 4OA3.1)
- 05000311/2012-002-0 LER Auxiliary Feedwater Flow Control Valve Failed Open with Zero Demand (Section 4OA3.2)