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| issue date = 05/03/2012
| issue date = 05/03/2012
| title = IR 05000272-12-002, 05000311-12-002; 01-01-12 - 03-31-12; Salem Nuclear Generating Station - NRC Integrated Inspection Report
| title = IR 05000272-12-002, 05000311-12-002; 01-01-12 - 03-31-12; Salem Nuclear Generating Station - NRC Integrated Inspection Report
| author name = Burritt A L
| author name = Burritt A
| author affiliation = NRC/RGN-I/DRP/PB3
| author affiliation = NRC/RGN-I/DRP/PB3
| addressee name = Joyce T P
| addressee name = Joyce T
| addressee affiliation = PSEG Nuclear, LLC
| addressee affiliation = PSEG Nuclear, LLC
| docket = 05000272, 05000311
| docket = 05000272, 05000311
Line 18: Line 18:


=Text=
=Text=
{{#Wiki_filter:
{{#Wiki_filter:May 3, 2012
[[Issue date::May 3, 2012]]


Mr. Thomas 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 -
SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 - NRC INTEGRATED INSPECTION REPORT 05000272/2012002 AND 05000311/2012002
NRC INTEGRATED INSPECTION REPORT 05000272/2012002 AND 05000311/2012002


==Dear Mr. Joyce:==
==Dear Mr. Joyce:==
On March 31, 2012, 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 April 5, 2012, with Mr. Fricker, Vice President of Salem Operations, and other members of your staff.
On March 31, 2012, 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 April 5, 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 Commission's rules and regulations and with the conditions of your license.
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.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.


No NRC-identified or self-revealing findings were identified during this inspection. However, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy. If you contest this NCV, 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-
No NRC-identified or self-revealing findings were identified during this inspection.
0001; and the NRC Resident Inspector at the Salem Nuclear Generating Station.
 
However, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy. If you contest this NCV, 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 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 Agencywide Document Access and Management System (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).


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 NRC's Agencywide Document Access and Management 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 Andrey Turilin Acting for/  


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


===Enclosure:===
===Enclosure:===
Inspection Report 05000272/2012002 and 05000311/2012002  
Inspection Report 05000272/2012002 and 05000311/2012002  


===w/Attachment:===
w/Attachment: Supplemental Information
Supplemental Information cc w/encl: Distribution via ListServ
 
REGION I==
Docket Nos.:
50-272, 50-311
 
License Nos.:
DPR-70, DPR-75
 
Report No.:
 
05000272/2012002 and 05000311/2012002
 
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:
 
January 1, 2012 through March 31, 2012
 
Inspectors:
 
J. Krafty, Acting Senior Resident Inspector
 
D. Schroeder, Senior Resident Inspector
 
C. Williams, Acting Resident Inspector
 
P. McKenna, Resident Inspector
 
A. Patel, Resident Inspector
 
A. Turilin, Project Engineer
 
Approved By:
Arthur L. Burritt, Chief
 
Reactor Projects Branch 3
 
Division of Reactor Projects
 
Enclosure


=SUMMARY OF FINDINGS=
=SUMMARY OF FINDINGS=
IR 05000272/2012002, 05000311/2012002; 01/01/2012 - 03/31/2012; Salem Nuclear Generating Station Units 1 and 2; Routine Integrated Inspection Report.
IR 05000272/2012002, 05000311/2012002; 01/01/2012 - 03/31/2012; Salem Nuclear  


This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional reactor inspectors. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006. No findings were identified.
Generating Station Units 1 and 2; Routine Integrated Inspection Report.
 
This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional reactor inspectors. 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.
 
No findings were identified.


===Other Findings===
===Other Findings===
A violation 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 PSEG's corrective action program (CAP). This violation and corrective action tracking number are listed in Section 4OA7 of this report.
A violation 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 corrective action program (CAP). This violation and corrective action tracking number are listed in Section 4OA7 of this report.


=REPORT DETAILS=
=REPORT DETAILS=
Summary of Plant Status Salem Nuclear Generating Station Unit No. 1 (Unit 1) operated at or near 100 percent power for the duration of the inspection period.
 
===Summary of Plant Status===
Salem Nuclear Generating Station Unit No. 1 (Unit 1) operated at or near 100 percent power for the duration of the inspection period.


Salem Nuclear Generating Station Unit No. 2 (Unit 2) began the period at 100 percent power and operated at full power until January 28, 2012, when power was reduced to 89 percent in order to troubleshoot a ground on the generator field windings. Unit 2 returned to full power on January 29, 2012, and operated at full power until March 23, 2012, when the reactor tripped due to a turbine trip on a spurious turbine overspeed signal. Unit 2 returned to 100 percent power on March 28, 2012 and remained at or near 100 percent power for the remainder of the inspection period.
Salem Nuclear Generating Station Unit No. 2 (Unit 2) began the period at 100 percent power and operated at full power until January 28, 2012, when power was reduced to 89 percent in order to troubleshoot a ground on the generator field windings. Unit 2 returned to full power on January 29, 2012, and operated at full power until March 23, 2012, when the reactor tripped due to a turbine trip on a spurious turbine overspeed signal. Unit 2 returned to 100 percent power on March 28, 2012 and remained at or near 100 percent power for the remainder of the inspection period.
Line 61: Line 122:
==REACTOR SAFETY==
==REACTOR SAFETY==
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity  
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity  
{{a|1R01}}
 
{{a|1R01}}
 
==1R01 Adverse Weather Protection==
==1R01 Adverse Weather Protection==
{{IP sample|IP=IP 71111.01|count=1}}
{{IP sample|IP=IP 71111.01|count=1}}
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====a. Inspection Scope====
====a. Inspection Scope====
The inspectors performed a review of PSEG's readiness for the onset of seasonal high levels of river detritus. The review focused on the service water (SW) and circulating water systems. The inspectors reviewed station procedures, including PSEG's seasonal weather preparation procedure, and applicable operating procedures. The inspectors conducted a review of the CAP and performed walkdowns of the water systems to verify that no unidentified issues existed that could challenge the operability of the systems during high levels of river detritus. Documents reviewed for each section of this inspection report are listed in the Attachment.
The inspectors performed a review of PSEGs readiness for the onset of seasonal high levels of river detritus. The review focused on the service water (SW) and circulating water systems. The inspectors reviewed station procedures, including PSEGs seasonal weather preparation procedure, and applicable operating procedures. The inspectors conducted a review of the CAP and performed walkdowns of the water systems to verify that no unidentified issues existed that could challenge the operability of the systems during high levels of river detritus. Documents reviewed for each section of this inspection report are listed in the Attachment.


====b. Findings====
====b. Findings====
No findings were identified.
No findings were identified. {{a|1R04}}
{{a|1R04}}
 
==1R04 Equipment Alignment==
==1R04 Equipment Alignment


==
===.1 Partial System Walkdowns===
===.1 Partial System Walkdowns===
{{IP sample|IP=IP 71111.04Q|count=3}}
{{IP sample|IP=IP 71111.04Q|count=3}}
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* 12 and 13 component cooling water (CCW) trains with 11 CCW system out-of-service (OOS) on January 25, 2012
* 12 and 13 component cooling water (CCW) trains with 11 CCW system out-of-service (OOS) on January 25, 2012
* 12 safety injection (SI) train with 11 SI pump OOS on February 1, 2012
* 12 safety injection (SI) train with 11 SI pump OOS on February 1, 2012
* 1B emergency diesel generator (EDG) with 1A EDG OOS for maintenance on February 28, 2012   The inspectors selected these systems based on their risk-significance for the current plant configuration or following realignment. The inspectors reviewed applicable operating procedures, system diagrams, the updated final safety analysis report (UFSAR), technical specifications (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.
* 1B emergency diesel generator (EDG) with 1A EDG OOS for maintenance on February 28, 2012  
 
The inspectors selected these systems based on their risk-significance for the current plant configuration or following realignment. The inspectors reviewed applicable operating procedures, system diagrams, the updated final safety analysis report (UFSAR), technical specifications (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.


====b. Findings====
====b. Findings====
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====b. Findings====
====b. Findings====
No findings were identified.
No findings were identified. {{a|1R05}}
{{a|1R05}}
 
==1R05 Fire Protection==
==1R05 Fire Protection


==
===.1 Resident Inspector Quarterly Walkdowns===
===.1 Resident Inspector Quarterly Walkdowns===
{{IP sample|IP=IP 71111.05Q|count=5}}
{{IP sample|IP=IP 71111.05Q|count=5}}


====a. Inspection Scope====
====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 out of service, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.
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 out of service, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.
* Unit 2, Spent Fuel/Component Cooling Heat Exchanger and Pump Area, 84' elevation, on January 3, 2012
* Unit 2, Spent Fuel/Component Cooling Heat Exchanger and Pump Area, 84 elevation, on January 3, 2012
* Unit 1, Demineralizer Ion Exchange Area, 100' elevation, on January 25, 2012
* Unit 1, Demineralizer Ion Exchange Area, 100 elevation, on January 25, 2012
* Unit 2, Demineralizer Ion Exchange Area, 100' elevation, on January 25, 2012
* Unit 2, Demineralizer Ion Exchange Area, 100 elevation, on January 25, 2012
* Unit 2, Outer Penetration Area on January 30, 2012
* Unit 2, Outer Penetration Area on January 30, 2012
* Unit 1, Spent Fuel/Component Cooling Heat Exchanger and Pump Area, 84' elevation, on February 2, 2012
* Unit 1, Spent Fuel/Component Cooling Heat Exchanger and Pump Area, 84 elevation, on February 2, 2012


====b. Findings====
====b. Findings====
Line 133: Line 200:


====b. Findings====
====b. Findings====
No findings were identified.  
No findings were identified.
{{a|1R06}}
 
{{a|1R06}}
 
==1R06 Flood Protection Measures==
==1R06 Flood Protection Measures==
{{IP sample|IP=IP 71111.06|count=1}}
{{IP sample|IP=IP 71111.06|count=1}}
Internal Flooding Review
Internal Flooding Review


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors reviewed the UFSAR, the site internal flooding analysis, and plant procedures to verify that PSEG's flooding mitigation plans and equipment are consistent with the design requirements and the risk analysis assumptions. The inspectors also reviewed the CAP to determine if PSEG identified and corrected flooding problems and whether operator actions for coping with flooding were adequate. The inspectors also focused on Unit 2 EDG rooms to verify the adequacy of equipment seals located below the flood line, floors and water penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, control circuits, and temporary or removable flood barriers.
The inspectors reviewed the UFSAR, the site internal flooding analysis, and plant procedures to verify that PSEGs flooding mitigation plans and equipment are consistent with the design requirements and the risk analysis assumptions. The inspectors also reviewed the CAP to determine if PSEG identified and corrected flooding problems and whether operator actions for coping with flooding were adequate. The inspectors also focused on Unit 2 EDG rooms to verify the adequacy of equipment seals located below the flood line, floors and water penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, control circuits, and temporary or removable flood barriers.


====b. Findings====
====b. Findings====
No findings were identified.
No findings were identified.


{{a|1R11}}
{{a|1R11}}
 
==1R11 Licensed Operator Requalification Program and Licensed Operator Performance==
==1R11 Licensed Operator Requalification Program and Licensed Operator Performance==
{{IP sample|IP=IP 71111.11Q|count=2}}
{{IP sample|IP=IP 71111.11Q|count=2}}


===.1 Licensed Operator Requalification Program===
===.1 Licensed Operator Requalification Program===
====a. Inspection Scope====
====a. Inspection Scope====
The inspectors observed licensed operator simulator training on January 31, 2012. The scenario included a small break loss of coolant accident and a failure of the 22 SI pump to start. 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.
The inspectors observed licensed operator simulator training on January 31, 2012. The scenario included a small break loss of coolant accident and a failure of the 22 SI pump to start. 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.
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===.2 Quarterly Review of Licensed Operator Performance in the Main Control Room===
===.2 Quarterly Review of Licensed Operator Performance in the Main Control Room===
====a. Inspection Scope====
====a. Inspection Scope====
The inspectors observed licensed operator performance during Unit 2 post-maintenance testing on the control area ventilation system and Unit 2 Delta T-Tavg surveillance testing on February 28, 2012 and March 6, 2012 respectively. 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.
The inspectors observed licensed operator performance during Unit 2 post-maintenance testing on the control area ventilation system and Unit 2 Delta T-Tavg surveillance testing on February 28, 2012 and March 6, 2012 respectively. 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.
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No findings were identified.
No findings were identified.


{{a|1R12}}
{{a|1R12}}
 
==1R12 Maintenance Effectiveness==
==1R12 Maintenance Effectiveness==
{{IP sample|IP=IP 71111.12|count=3}}
{{IP sample|IP=IP 71111.12|count=3}}
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====b. Findings====
====b. Findings====
No findings were identified.  
No findings were identified.
{{a|1R13}}
 
{{a|1R13}}
 
==1R13 Maintenance Risk Assessments and Emergent Work Control==
==1R13 Maintenance Risk Assessments and Emergent Work Control==
{{IP sample|IP=IP 71111.13|count=5}}
{{IP sample|IP=IP 71111.13|count=5}}
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* 11 component cooling heat exchanger high flow flush on January 25, 2012
* 11 component cooling heat exchanger high flow flush on January 25, 2012
* 21 control air supply fan OOS for planned maintenance on January 31, 2012
* 21 control air supply fan OOS for planned maintenance on January 31, 2012
* Emergent work on pressurizer relief block valve (2PR7) February 6 -8 , 2012
* Emergent work on pressurizer relief block valve (2PR7) February 6 -8, 2012
* 12 control air supply fan OOS for planned maintenance and 13 chiller OOS for corrective maintenance on March 6, 2012
* 12 control air supply fan OOS for planned maintenance and 13 chiller OOS for corrective maintenance on March 6, 2012


====b. Findings====
====b. Findings====
No findings were identified.  
No findings were identified.
{{a|1R15}}
 
{{a|1R15}}
 
==1R15 Operability Determinations and Functionality Assessments==
==1R15 Operability Determinations and Functionality Assessments==
{{IP sample|IP=IP 71111.15|count=6}}
{{IP sample|IP=IP 71111.15|count=6}}
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* TE 60082709, solid state protection relay TS620 (BC620) contact failure on March 7, 2012
* TE 60082709, solid state protection relay TS620 (BC620) contact failure on March 7, 2012
* OP-EVAL 12-002, Unit 1 and 2 SW bay material condition on March 2, 2012
* OP-EVAL 12-002, Unit 1 and 2 SW bay material condition on March 2, 2012
* TE 60101901, 12 Chiller trip on freeze protection on March 22, 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 PSEG's 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 assumptions in the evaluations.
* TE 60101901, 12 Chiller trip on freeze protection on March 22, 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 assumptions in the evaluations.


====b. Findings====
====b. Findings====
No findings were identified.  
No findings were identified.
{{a|1R18}}
 
{{a|1R18}}
 
==1R18 Plant Modifications==
==1R18 Plant Modifications==
{{IP sample|IP=IP 71111.18|count=1}}
{{IP sample|IP=IP 71111.18|count=1}}
Line 215: Line 293:


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors evaluated a modification to Unit 1 SW motor operated valves (MOVs)implemented by engineering change package 80105080, "Salem Unit 1 MOV Limit Switch Modification for 11SW20, 13SW20, and 1SW26."  The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the design change, including work orders, MOV diagnostic tests, valve stroke time tests, and MIDAS calculations. The inspectors also reviewed revisions to the drawings, interviewed engineering personnel, and performed a walkdown of the completed modification to ensure the modification was installed as designed.
The inspectors evaluated a modification to Unit 1 SW motor operated valves (MOVs)implemented by engineering change package 80105080, Salem Unit 1 MOV Limit Switch Modification for 11SW20, 13SW20, and 1SW26. The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the design change, including work orders, MOV diagnostic tests, valve stroke time tests, and MIDAS calculations. The inspectors also reviewed revisions to the drawings, interviewed engineering personnel, and performed a walkdown of the completed modification to ensure the modification was installed as designed.


====b. Findings====
====b. Findings====
No findings were identified.
No findings were identified.


{{a|1R19}}
{{a|1R19}}
 
==1R19 Post-Maintenance Testing==
==1R19 Post-Maintenance Testing==
{{IP sample|IP=IP 71111.19|count=8}}
{{IP sample|IP=IP 71111.19|count=8}}
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* 2CAA50 and 2CAA51, control room emergency air conditioning system supply dampers maintenance and pinning on February 29, 2012
* 2CAA50 and 2CAA51, control room emergency air conditioning system supply dampers maintenance and pinning on February 29, 2012
* 13 SW pump replacement on March 12, 2012
* 13 SW pump replacement on March 12, 2012
* Unit 1, "B" Channel Subcooled Margin Monitor repair on March 13, 2012
* Unit 1, B Channel Subcooled Margin Monitor repair on March 13, 2012
* 22CC3, component cooling pump discharge header cross connect valve repairs on March 21, 2012
* 22CC3, component cooling pump discharge header cross connect valve repairs on March 21, 2012


====b. Findings====
====b. Findings====
No findings were identified.  
No findings were identified.
{{a|1R22}}
 
{{a|1R22}}
 
==1R22 Surveillance Testing==
==1R22 Surveillance Testing==
{{IP sample|IP=IP 71111.22|count=7}}
{{IP sample|IP=IP 71111.22|count=7}}
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* S2.OP-ST.RC-0008, Reactor Coolant System (RCS) Water Inventory Balance on January 18, 2012 (RCS leak detection)
* S2.OP-ST.RC-0008, Reactor Coolant System (RCS) Water Inventory Balance on January 18, 2012 (RCS leak detection)
* S1.OP-ST.RC-0008, RCS Water Inventory Balance on January 18, 2012 (RCS leak detection)
* S1.OP-ST.RC-0008, RCS Water Inventory Balance on January 18, 2012 (RCS leak detection)
* ST.OP-ST.CS-0002, Inservice Testing - 22 Containment Spray Pump on January 19, 2012 (in-service test)
* ST.OP-ST.CS-0002, Inservice Testing - 22 Containment Spray Pump on January 19, 2012 (in-service test)
* S2.MD-FT.4KV-0003, ESFAS Instrumentation Monthly Functional Test - 2C 4KV Vital Bus Undervoltage on January 20, 2012
* S2.MD-FT.4KV-0003, ESFAS Instrumentation Monthly Functional Test - 2C 4KV Vital Bus Undervoltage on January 20, 2012
* S1.OP-ST.AF-0003, 13 Auxiliary Feedwater Pump Periodic Run on January 25, 2012
* S1.OP-ST.AF-0003, 13 Auxiliary Feedwater Pump Periodic Run on January 25, 2012
* S2.OP-ST.RCS-0001, Reactivity Control System Rod Control Assemblies on March 2, 2012
* S2.OP-ST.RCS-0001, Reactivity Control System Rod Control Assemblies on March 2, 2012


====b. Findings====
====b. Findings====
No findings were identified. Cornerstone: Emergency Preparedness  
No findings were identified.  
{{a|1EP6}}
 
===Cornerstone: Emergency Preparedness===
{{a|1EP6}}
 
==1EP6 Drill Evaluation==
==1EP6 Drill Evaluation==
{{IP sample|IP=IP 71114.06|count=1}}
{{IP sample|IP=IP 71114.06|count=1}}
Emergency Preparedness Drill Observation
Emergency Preparedness Drill Observation


====a. Inspection Scope====
====a. Inspection Scope====
The inspectors evaluated the conduct of a routine PSEG emergency drill on February 9, 2012, to identify any weaknesses and deficiencies in the classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator, technical support center, and emergency operations facility (EOF) to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the EOF and station drill critiques to compare inspector observations with those identified by PSEG staff in order to evaluate PSEG's critique and to verify whether the PSEG staff was properly identifying weaknesses and entering them into the CAP.
The inspectors evaluated the conduct of a routine PSEG emergency drill on February 9, 2012, to identify any weaknesses and deficiencies in the classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator, technical support center, and emergency operations facility (EOF) to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the EOF and station drill critiques to compare inspector observations with those identified by PSEG staff in order to evaluate PSEGs critique and to verify whether the PSEG staff was properly identifying weaknesses and entering them into the CAP.


====b. Findings====
====b. Findings====
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==OTHER ACTIVITIES==
==OTHER ACTIVITIES==
{{a|4OA1}}
{{a|4OA1}}
==4OA1 Performance Indicator Verification==
==4OA1 Performance Indicator Verification==
{{IP sample|IP=IP 71151}}
{{IP sample|IP=IP 71151}}
===.1 Safety System Functional Failures (2 samples)===
===.1 Safety System Functional Failures (2 samples)===
====a. Inspection Scope====
====a. Inspection Scope====
The inspectors sampled PSEG's submittals for the Safety System Functional Failures performance indicator for both Unit 1 and Unit 2 for the period of January 1, 2011, through December 31, 2011. To determine the accuracy of the performance indicator data reported during those periods, inspectors used definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6, and NUREG-1022, "Event Reporting Guidelines 10 CFR 50.72 and 10 CFR 50.73." The inspectors reviewed PSEG's licensee event reports (LERs) to validate the accuracy of the submittals.
The inspectors sampled PSEGs submittals for the Safety System Functional Failures performance indicator for both Unit 1 and Unit 2 for the period of January 1, 2011, through December 31, 2011. To determine the accuracy of the performance indicator data reported during those periods, inspectors used definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 10 CFR 50.73." The inspectors reviewed PSEGs licensee event reports (LERs) to validate the accuracy of the submittals.


====b. Findings====
====b. Findings====
Line 277: Line 363:


===.2 RCS Specific Activity and RCS Leak Rate (4 samples)===
===.2 RCS Specific Activity and RCS Leak Rate (4 samples)===
====a. Inspection Scope====
The inspectors reviewed PSEGs submittal for the RCS specific activity and RCS leak rate performance indicators for both Unit 1 and Unit 2 for the period of January 1, 2011, through December 31, 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors also reviewed RCS sample analysis and logs of daily measurements of RCS leakage, and compared that information to the data reported by the performance indicator. Additionally, the inspectors observed surveillance activities that determined the RCS identified leakage rate, and chemistry personnel taking and analyzing an RCS sample.


====a. Inspection Scope====
b. Inspection Findings
The inspectors reviewed PSEG's submittal for the RCS specific activity and RCS leak rate performance indicators for both Unit 1 and Unit 2 for the period of January 1, 2011, through December 31, 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6. The inspectors also reviewed RCS sample analysis and logs of daily measurements of RCS leakage, and compared that information to the data reported by the performance indicator. Additionally, the inspectors observed surveillance activities that determined the RCS identified leakage rate, and chemistry personnel taking and analyzing an RCS sample.


b. Inspection Findings  No findings were identified.
No findings were identified.
{{a|4OA2}}
{{a|4OA2}}
==4OA2 Problem Identification and Resolution==
==4OA2 Problem Identification and Resolution==
{{IP sample|IP=IP 71152}}
{{IP sample|IP=IP 71152}}
Line 288: Line 376:


====a. Inspection Scope====
====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 CAP 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.
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 CAP 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====
====b. Findings====
No findings were identified.
No findings were identified.


{{a|4OA3}}
{{a|4OA3}}
 
==4OA3 Follow-Up of Events and Notices of Enforcement Discretion==
==4OA3 Follow-Up of Events and Notices of Enforcement Discretion==
{{IP sample|IP=IP 71153|count=2}}
{{IP sample|IP=IP 71153|count=2}}


===.1 Plant Events===
===.1 Plant Events===
====a. Inspection Scope====
====a. Inspection Scope====
For the Unit 2 reactor trip due to turbine trip on March 23, 2012, the inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional personnel and compared the event details with criteria contained in Inspection Manual Chapter 0309, "Reactive Inspection Decision Basis for Reactors," for consideration of potential reactive inspection activities. As applicable, the inspectors verified PSEG made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR Parts 50.72 and 50.73. The inspectors reviewed PSEG's follow-up actions related to the events to assure that PSEG implemented appropriate corrective actions commensurate with their safety significance.
For the Unit 2 reactor trip due to turbine trip on March 23, 2012, the inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional personnel and compared the event details with criteria contained in Inspection Manual Chapter 0309, Reactive Inspection Decision Basis for Reactors, for consideration of potential reactive inspection activities. As applicable, the inspectors verified PSEG made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR Parts 50.72 and 50.73. The inspectors reviewed PSEGs follow-up actions related to the events to assure that PSEG implemented appropriate corrective actions commensurate with their safety significance.


====b. Findings====
====b. Findings====
No findings were identified.
No findings were identified.


===.2 (Closed) LER 05000272/2011-005-00: Incorrect NIS Trip Setpoints Results in TS 3.0.3 Entry===
===.2 (Closed) LER 05000272/2011-005-00: Incorrect NIS Trip Setpoints Results in TS 3.0.3===
On December 11, 2011, PSEG discovered that the Unit 1 intermediate range nuclear instrumentation system (NIS) trip setpoints were incorrect after an on-shift reactor operator noticed that the intermediate range NIS bistables were not lit on the RPS mimic panel as would be expected at 100% power. PSEG determined through a prompt investigation that the data used to calculate the intermediate range trip setpoints was improperly recorded during the intermediate range instrument at-power calibration procedure completed on November 24, 2011, and as a result, the intermediate range trip setpoints were improperly set during that procedure. Therefore, PSEG concluded that NIS was inoperable from November 24, 2011, when the intermediate range NIS setpoints were installed, until December 11, 2011, when PSEG discovered the error and entered the correct intermediate range trip setpoints. The enforcement aspects of this issue are discussed in Section 4OA7. The inspectors did not identify any new issues during the review of the LER. This LER is closed.
Entry
 
On December 11, 2011, PSEG discovered that the Unit 1 intermediate range nuclear instrumentation system (NIS) trip setpoints were incorrect after an on-shift reactor operator noticed that the intermediate range NIS bistables were not lit on the RPS mimic panel as would be expected at 100% power. PSEG determined through a prompt investigation that the data used to calculate the intermediate range trip setpoints was improperly recorded during the intermediate range instrument at-power calibration procedure completed on November 24, 2011, and as a result, the intermediate range trip setpoints were improperly set during that procedure. Therefore, PSEG concluded that NIS was inoperable from November 24, 2011, when the intermediate range NIS setpoints were installed, until December 11, 2011, when PSEG discovered the error and entered the correct intermediate range trip setpoints. The enforcement aspects of this issue are discussed in Section 4OA7. The inspectors did not identify any new issues during the review of the LER. This LER is closed.


{{a|4OA6}}
{{a|4OA6}}
==4OA6 Meetings, Including Exit==
==4OA6 Meetings, Including Exit==
On April 5, 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.
On April 5, 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.


{{a|4OA7}}
{{a|4OA7}}
==4OA7 Licensee-Identified Violations==
==4OA7 Licensee-Identified Violations==
The following violation of very low safety significance (Green) was identified by PSEG and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as a NCV.
The following violation of very low safety significance (Green) was identified by PSEG and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as a NCV.
* TS 3.3.1.1, "Reactor Trip System Instrumentation," requires one operable intermediate range instrument in Modes 1, 2, and 3. When that requirement is not met, TS 3.0.3 requires that action be initiated within one hour to place the unit in hot standby within the next six hours. Contrary to the above requirements, on November 24, 2011, after technicians input incorrect trip setpoints that rendered both TS 3.3.1.1 required intermediate range NISs inoperable, PSEG did not initiate action within one hour to place the unit in hot standby within the next six hours. Upon discovery of the inoperable instruments on December 11, 2011, PSEG took immediate corrective action to input the correct intermediate range setpoints and restore operability and entered this issue into the CAP as notification 20538425. The inspectors determined that the finding was of very low safety significance (Green) in accordance with NRC IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," Mitigating Systems Cornerstone, because the finding did not represent a loss of safety system function, an actual loss of safety function of a single train for greater than its TS allowed outage time, an actual loss of safety function of one or more non-technical specification trains of equipment designated a risk significant per 10 CFR 50.65 for greater than 24 hours, and did not screen as risk significant due to seismic, flooding or severe weather initiating event.
* TS 3.3.1.1, "Reactor Trip System Instrumentation, requires one operable intermediate range instrument in Modes 1, 2, and 3. When that requirement is not met, TS 3.0.3 requires that action be initiated within one hour to place the unit in hot standby within the next six hours. Contrary to the above requirements, on November 24, 2011, after technicians input incorrect trip setpoints that rendered both TS 3.3.1.1 required intermediate range NISs inoperable, PSEG did not initiate action within one hour to place the unit in hot standby within the next six hours. Upon discovery of the inoperable instruments on December 11, 2011, PSEG took immediate corrective action to input the correct intermediate range setpoints and restore operability and entered this issue into the CAP as notification 20538425. The inspectors determined that the finding was of very low safety significance (Green) in accordance with NRC IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," Mitigating Systems Cornerstone, because the finding did not represent a loss of safety system function, an actual loss of safety function of a single train for greater than its TS allowed outage time, an actual loss of safety function of one or more non-technical specification trains of equipment designated a risk significant per 10 CFR 50.65 for greater than 24 hours, and did not screen as risk significant due to seismic, flooding or severe weather initiating event.


ATTACHMENT:  
ATTACHMENT:  
Line 322: Line 414:


==KEY POINTS OF CONTACT==
==KEY POINTS OF CONTACT==
===Licensee Personnel===
===Licensee Personnel===
: [[contact::C. Fricker]], Site Vice President  
: [[contact::C. Fricker]], Site Vice President  
Line 347: Line 438:
: [[contact::G. Sosson]], Engineering Director  
: [[contact::G. Sosson]], Engineering Director  
: [[contact::R. Wegner]], Maintenance Director  
: [[contact::R. Wegner]], Maintenance Director  
: [[contact::M. Winkelspecht]], System Engineer
: [[contact::M. Winkelspecht]], System Engineer  


==LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED==
==LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED==
===Closed===
===Closed===
: [[Closes LER::05000272/LER-2011-005]]-00 LER Incorrect NIS Trip Setpoints Results in TS 3.0.3 Entry (Section 4OA3.2)  
: 05000272/2011-005-00 LER Incorrect NIS Trip Setpoints Results in TS 3.0.3 Entry (Section 4OA3.2)  


==LIST OF DOCUMENTS REVIEWED==
==LIST OF DOCUMENTS REVIEWED==
==Section 1R01: Adverse Weather Protection==
===Procedures===
: EN-SA-403-1001, Salem River Grass Predictive Methodology, Revision 0
: SC-OP-AB-ZZ-003(Q), Component Fouling, Revision 13
: SC-MD-PM.SW-0003, Service Water Auto Strainer Adjustment, Inspection, Repair, and Replacement, Revision 35 
: Attachment
: SC.OP-PT.ZZ-0002(Q), Station Preparations for Seasonal Conditions, Revision 11 S2.OP-AB.CW-0001(Q), Circulating Water System Malfunction, Revision 31
: WC-AA-107, Seasonal Readiness, Revision 11
===Notifications===
: 20531793
: 20532254
: 20532483
: 20534336
: 20535758
: 20536368
: 20544772
: 20546291
: 20547692
: 20547971
: 20547979
: 20547982
: 20547985
: 20548148
: 20548721
: 20549356
: Orders
: 70120968
: 70127951
: 70130763
: 70134815 
===Other Documents===
: DE-CB.CW-0028, Configuration Baseline Document for Circulating Water System,
: Revision 0
: DE-CB.SW-0047, Configuration Baseline Document for Service Water System, Revision 7
: VPPO-2011-014, 2012 Salem Grassing Seasonal Readiness Affirmation, dated January 1, 2012
==Section 1R04: Equipment Alignment==
===Procedures===
: IST-SC-I4-Basis, In-Service Testing Basis Manual, Revision 0
: S1.OP-PT.ZZ-0004, 92 Day Locked Valve Verification, Revision 2 
: S1.OP-SO.CCW-0001, Component Cooling Water System, Revision 17 S1.OP-SO.SJ-0001, Preparation of the Safety Injection System for Operations, Revision 14 S1.OP-ST.ZZ-0004, 92 Day Locked Valve Verification, Revision 3
: S2.OP-SO.AF-0001, Auxiliary Feedwater System Operation, Revision 35 S2.OP-ST.AF-0008, Auxiliary Feedwater Valve Verification Modes 1-3, Revision 4 
===Drawings===
: 205228, Sheets1 and 2, No. 1 Chemical 7 Volume Control Operation, Revisions 72 and 81
: 205234, Sheets 1-4, P&ID No. 1 Unit Safety Injection, Revisions 53, 47, 56, and 44
: 205241, Sheet 2, Diesel Engine Auxiliaries, Revision 43
: 205249, Sheet 2, Fuel Oil, Revision 34
: 205336, No. 2 Auxiliary Feedwater, Revision 50
===Notifications===
(*NRC-identified)
: 20492799
: 20493617
: 20504264
: 20544338
: 20544339
: 20508946
: 20510661
: 20520193
: 20521588
: 20529160
: 20529227
: 20545409*
: Orders
: 50143213
: 50144286
: 50145007
: 50145022
: 50146543 
===Other Documents===
: Revised Action Plan and Goals for Unit 1 Charging System dated August 2, 2011
: S1.OP-ST.SJ-0002, Inservice Testing - 12 Safety Injection Pump, performed Aug 18, 2011 S1.OP-ST.SJ-0003, Inservice Testing Safety Injection Valves Modes 1-6, performed Nov 13, 2011 System Health Report, Unit 2 Auxiliary Feedwater, Quarter 4 2011 S2.OP-ST.AF-0001, Inservice Testing - 21 Auxiliary Feedwater Pump, performed Jan 4, 2012 
: Attachment S2.OP-ST.AF-0002, Inservice Testing - 22 Auxiliary Feedwater Pump, performed Nov 13, 2011 S2.OP-ST.AF-0003, Inservice Testing - 23 Auxiliary Feedwater Pump, performed Feb 17, 2011 S2.OP-ST.AF-0004, Inservice Testing - Auxiliary Feedwater Valves, performed Jan 27, 2012 S2.OP-ST.AF-0006, Inservice Testing - Auxiliary Feedwater Valves, performed Jan 30, 2012 S2.OP-ST.AF-0008, Auxiliary Feedwater Valve Verification Modes 1-3, performed Jan 26, 2012 Unit 1 Charging and Volume Control System Health Report 4th Quarter 2011
==Section 1R05: Fire Protection==
===Procedures===
: FP-AA-001, Precautions Against Fires, Revision 0
: FP-AA-011, Control of Transient Combustible Material, Revision 2
: FRS-II-432, Salem Unit 1 (Unit 2) Pre-Fire Plan, Spent Fuel/Component Cooling Heat Exchanger and Pump Area, Elevation: 84', Revision 5
: FRS-II-444, Salem Unit 1 (Unit 2) Pre-Fire Plan, Demineralizer Ion Exchange Area, Elevation:
: 100', Revision 3
: FRS-II-914, Salem Unit 1 (Unit 2) Pre-Fire Plan, Outer Penetration Area, Revision 2
===Other Documents===
: ADS2032112, Salem Unit 2/Turbine Bldg/120/Hydrogen Skid, Revision 0
: PO304390, Fire Door Schedule and Details Used for Auxiliary Building Units 1 and 2,
: Revision 5
: TCP 2011005-06, Transient Combustible Permit for Unit 1 Auxiliary Building
: CCZ-13, dated 10/10/2011
==Section 1R06: Flood Protection Measures==
===Procedures===
: S-C-ZZ-SDC-1203, Internal Hazards Program/Flooding Analysis Moderate Energy Pipe Line Break (MELB), Revision 3
: SC.FP-SV.FBR-0026, Flood and Fire Barrier Penetration Seal Inspection, Revision 4 S1.OP-AB.SW-0001, Loss of Service Water Header Pressure, Revision 17
: S1.OP-AB.ZZ-0002, Flooding, Revision 3 
===Notifications===
: 20548493
==Section 1R11: Licensed Operator Requalification Program==
===Procedures===
: S2.IC-FT.RCP-0005, 2TE-421A-B #22 RX Coolant Loop Delta T-Tavg Protection Channel II, Revision 46
===Other Documents===
: ESG-102, Segment 5 OBE
==Section 1R12: Maintenance Effectiveness==
===Procedures===
: ER-AA-310-1004, Maintenance Rule - Performance Monitoring, Revision 8
: ER-AA-310-1005, Maintenance Rule - Dispositioning Between (a)(1) and (a)(2), Revision 7 
: Attachment
: ER-SA-310-1009, System Function Level Maintenance Rule Scoping, Revision 2
===Notifications===
: 20453113
: 20457939
: 20474170
: 20479126
: 20482172
: 20496285
: 20490858
: 20497893
: 20499204
: 20501671
: 20501672
: 20502655
: 20502656
: 20502814
: 20507830
: 20513934
: 20514960
: 20518130
: 20520665
: 20520781
: 20524917
: 20525016
: 20525822
: 20526105
: 20526525
: 20528586
: 20528912
: 20529255
: 20529386
: 20530176
: 20540170
: 20542513
: 20544292
: 20549923
: 20549924
===Other Documents===
: Chilled Water System Health Report 4th Quarter 2010 and 2011 Control Area Air Conditioning System Health Report 4th Quarter 2010 and 2011
: Gas Turbine Generator System Health Report 4th Quarter 2010 and 2011 mRule Gas Turbine Unavailability and Performance Criteria Status Report, dated January 20, 2012
: 205216 Sheets 1 through 8, No. 1 & 2 Units Chilled Water, Revision 63
: 205348 Sheets 1 and 2, Aux. Bldg. Control Area Air Conditioning & Ventilation, Revision 28
(a)(1) Action Plan Solenoid Valves  (a)(1) Goal Action Plan, 22 Chiller  (a)(1) Action Plan and Goals, Unit 3, Gas Turbine Generator, dated March 7, 2012 
(a)(1) Determination, Unit 3 Gas Turbine Generator, dated January 28, 2012
==Section 1R13: Maintenance Risk Assessments and Emergent Work Control==
===Procedures===
: ER-AA-600-1042, On-Line Risk Management, Revision 5
: MA-AA-716-004, Conduct of Troubleshooting, Revision 11
: OP-AA-101-112-1002, On-Line Risk Assessment, Revision 5
: OP-AA-108-116, Protected Equipment Program, Revision 4
: S2.OP-ST.PZR-0002, Inservice Testing PORV Block Valves Modes 1-6, Revision 10
: WC-AA-101, On-Line Work Management Process, Revision 19
: WC-AA-101-1002, On Line Scheduling Process, Revision 12
: WC-AA-106, Work Screening and Processing, Revision 11
===Other Documents===
: Salem 1 Narrative Log, dated 1/25/2012 Salem Generating Station, Unit 1 Risk Assessment, dated Jan 17, 2012
: Salem Generating Station, Unit 1 Risk Assessment, dated Mar 4, 2012
: Salem Generating Station, Unit 2 Risk Assessment, dated Jan 17, 2012
: SGS Unit 1/2 PSA Risk Assessment for Work Week 204, dated 1/22/2012 Troubleshooting Plan for 2PR7
==Section 1R15: Operability Evaluations==
===Procedures===
: S1.OP-ST.CH-0004, Chilled Water Systems - Chillers, Revision 11 S2.OP-ST.PZR-0002, Inservice Testing PORV Block Valves Modes 1-6, Revision 10 S2.OP-ST.SSP-0009, Engineered Safety Features SSPS Slave Relay Test - Train "A", Revision 33 
: Attachment Notifications
: 20258764
: 20366273
: 20377795
: 20522866
: 20541577
: 20545797
: 20546328
: 20548088
: 20548689
: 20548793
: 20548797
: 20548867
: 20548868
: 20548904
: 20548950
: 20549493
: 20551613
: 20551615
: 20541156
: Orders
: 60058942
: 60061107
: 60082242
: 60101159
: 70117404
: 70120297
: 70134875
===Other Documents===
: CC-AA-309-101, Technical Evaluation, 2PR7 will not stroke closed
: OP-EVAL 12-002, Service Water (SW) - Associated Support Systems S-C-SW-MEE-0953, SW Traveling Screen Classification Evaluation, dated July 22, 1996 Technical Evaluation
: 60101901, 12 Chiller Trip on Freeze Protection
==Section 1R18: Plant Modifications==
===Procedures===
: ER-AA-302-1002, Quarter-Turn Motor Operated Valve Sizing and Set-up Window Determination Methodology, Revision 6
: ER-AA-302-1007, MOV Limitorque Actuator Capability Determination Methodology, Revision 6
: Orders
: 60099042
: 60099043
===Other Documents===
: MIDACALC Results for 1SW26, Revision 4
: MIDACALC Results for 11SW20, Revision 2
: MIDACALC Results for 13SW20, Revision 1 MOV Post-Test Data Review Worksheet, 1SW26, dated November 12, 2011 MOV Post-Test Data Review Worksheet, 11SW20, dated October 25, 2011
: MOV Post-Test Data Review Worksheet, 13SW20, dated October 24, 2011
==Section 1R19: Post-Maintenance Testing==
===Procedures===
: S1.IC-CC.RCP-0068, 1PT-948C Containment Pressure Protection Channel II, Revision 11 
: S1.IC-CC.RHR-0215, 1FT-641B #12 RHR Pump Recirculation Flow Control Valve, Revision 7 
: S1.IC-CC.ZZ-0023, Core Exit Thermocouple Processor System (CETPS), Revision 9 
: S1.OP-SO.CAV-0001, Control Area Ventilation Operation, Revision 36
: S1.OP-ST.CVC-0003, Inservice Testing - 11 Charging Pump, Revision 23
: S1.OP-ST.INST-0001, Instrumentation - Accident Monitoring, Revision 20 
: S1.OP-ST.RHR-0002, Inservice Testing - 12 Residual Heat Removal Pump, Revision 18 
: S1.OP-ST.SW-0003, Inservice Testing - 13 Service Water Pump, Revision 33 
: S1.OP-ST.SW-0006, Inservice Testing - 16 Service Water Pump, Revision 32 
: S1.OP-ST.SW-0014, Inservice Testing Room Cooler Valves Modes 1-6, Revision 5
: S1.RA-ST.CVC-0003, Inservice Testing - 11 Charging Pump Acceptance Criteria,
: Revision 13 S1.RA-ST.SW-0003, Inservice Testing 13 Service Water Pump Acceptance Criteria,
: Revision 11 
: Attachment S1.RA-ST.SW-0006, Inservice Testing 16 Service Water Pump Acceptance Criteria,
: Revision 11 S2.OP-SO.CAV-0001, Control Area Ventilation Operation, Revision 38 S2.OP-ST.CC-0004, Inservice Testing Component Cooling Valves, Revision 14
===Notifications===
: 20545350
: 20546311
: 20549935
: 20550115
: 20550452
: 20550457
: 20551236
: Orders
: 30109236
: 30121510
: 50146122
: 50146646
: 60082244
: 60094855
: 60101854
: 60601343
: 60101985 
===Other Documents===
: S1.OP-ST.SW-0003, Inservice Testing - 13 Service Water Pump, performed March 12, 2012 S1.OP-ST.SW-0006, Inservice Testing - 16 Service Water Pump, performed February 3, 2012 22CC3 Component Cooling Heat Exchanger Cross over Motor Operated Valve Failed to close, Prompt Investigation
==Section 1R22: Surveillance Testing==
===Procedures===
: MA-AA-716-009, Use of Maintenance Procedures, Revision 5
: S1.OP-ST.AF-0003, 13 AFW Pump Periodic Run, Revision 1
: S1.OP-ST.RC-0008, Reactor Coolant System Water Inventory Balance, Revision 23 S1.RA-ST.RHR-0001, Inservice Testing - 21 Residual Heat Removal Pump Acceptance Critieria, Revision 12 S2.MD-FT.4KV-0003, ESFAS Instrumentation Monthly Functional Test 2C 4KV Vital Bus Undervoltage, Revision 33 S2.OP-ST.RHR-0001, Inservice Testing - 21 Residual Heat Removal Pump, Revision 26
===Notifications===
: 20541214 
: Orders
: 50146341
: 30172336
: 50144285
: 50145568
: 60098586
===Other Documents===
: S-C-4KV-JDC-959, Degraded Vital Bus Under-Voltage Setpoint Calculation, Revision 5
: S2-MD-FT.4KV-0003, ESFAS Instrumentation Monthly Functional Test 2C 4KV Vital Bus Undervoltage, performed January 20, 2012 Salem 1 Narrative Log, AFW, dated 1/25/2012
==Section 1EP6: Drill Evaluation==
===Procedures===
: NC.EP-EP.ZZ-0404, Protective Action Recommendations (PARS) Upgrades, Revision 03
===Other Documents===
: Emergency Preparedness Training Drill Critique Report S12-01
: S12-01, Salem - EP Training Drill Attachment
==Section 4OA1: Performance Indicator Verification==
===Procedures===
: S1.OP-ST.RC-0008, Reactor Coolant System Water Inventory Balance, Revision 23 S2.OP-ST.RC-0008, Reactor Coolant System Water Inventory Balance, Revision 32 
===Notifications===
: 20489448
: 20522574
: 20536255
: 20537524
: 20538568
: 20523368
: 20524414
: 20526108
===Other Documents===
: LER 05000272/2011001-00, Service Water Loop Inoperable for Time Greater Than Allowed by Technical Specifications
: LER 05000272/2011002-00, Bypass of Steam Generator Blowdown Valve Isolation during Testing
: LER 05000272/2011003-00, Manual Reactor Trip Due to Degraded Condenser Heat Removal
: LER 05000272/2011004-00, 11 Component Cooling Water Pump Inoperable for Greater Than Allowed By Technical Specifications
: LER 05000311/2011001-00, 21SW122 Isolation Function Inoperable for Greater Than Allowed by Technical Specifications
: LER 05000311/2011002-00, Failure to Comply With Technical Specification 3.4.5 and 3.4.10.3
: LER 05000311/2011003-00, Technical Specification Maximum Airflow in the Fuel Handling Building Exceeded
: LER 05000311/2011004-00, Automatic Reactor Trip Due to Trip of 23 Reactor Coolant Pump
: LER 05000311/2011004-01, Automatic Reactor Trip Due to Trip of 23 Reactor Coolant Pump
: LER 05000311/2011005-00, Completion of a Plant Shutdown in Accordance With Technical Specification 3.0.3
: LER 05000311/2011005-01, Completion of a Plant Shutdown in Accordance With Technical Specification 3.0.3 Safety Evaluation by NRR Related to Amendment 263 and 245 for Salem Unit 1 and 2 S1.OP-ST.RC-0008, Attachment 6, Reactor Coolant System Leakrate Trending Data Sheet, January 1, 2011 through December 31, 2011 S2.OP-ST.RC-0008, Attachment 6, Reactor Coolant System Leakrate Trending Data Sheet, January 1, 2011 through December 31, 2011
==Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion==


===Procedures===
: 2-EOP-TRIP-1, Reactor Trip or Safety Injection, Revision 28
: 2-EOP-TRIP-2, Reactor Trip Response, Revision 28S2.OP-IO.ZZ-0008, Maintaining Hot
: Standby, Revision 14
: OP-SA-108-114-1001, Post-Trip Data Collection Guidelines-Salem, Revision 2
: S2.OP-SO.RC-0001, Reactor Coolant Pump Operations, Revision 29 
===Notifications===
: 2055188
===Other Documents===
: Salem Unit 2
: EOP-Trip-1 and
: EOP-Trip-2 Flowchart, dated March 23, 2012
: Salem Unit 2 Narrative Log, dated March 23, 2012 
: Attachment Salem Unit 2 Overhead Annunciator Data, dated March 23, 2012 Salem Unit 2 Plant Parameter and Trend Data, dated March 23, 2012
: Salem Unit 2 Sequence of Events Review Data, dated March 23, 2012
==LIST OF ACRONYMS==
: [[ADAMS]] [[Agencywide Documents Access and Management System]]
: [[CAP]] [[Corrective Action Program]]
: [[CCW]] [[Component Cooling Water]]
: [[CFR]] [[Code of Federal Regulations]]
: [[EDG]] [[Emergency Diesel Generator]]
: [[EOF]] [[Emergency Operations Facility]]
: [[IMC]] [[Inspection Manual Chapter]]
: [[LER]] [[Licensee Event Report]]
: [[MOV]] [[Motor Operated Valves]]
: [[NCV]] [[Non-Cited Violation]]
: [[NEI]] [[Nuclear Energy Institute]]
: [[NIS]] [[Nuclear Instrumentation System]]
: [[NRC]] [[Nuclear Regulatory Commission]]
: [[OOS]] [[Out of Service]]
: [[PARS]] [[Publicly Available Records]]
: [[PSEG]] [[Public Service Enterprise Group Nuclear]]
: [[LLC]] [[]]
: [[RCS]] [[Reactor Coolant System]]
: [[SI]] [[Safety Injection]]
: [[SSC]] [[Structure, System, or Component]]
: [[SW]] [[Service Water]]
TS  Technical Specification
: [[UFSAR]] [[Updated Final Safety Analysis Report]]
}}
}}

Latest revision as of 02:20, 12 January 2025

IR 05000272-12-002, 05000311-12-002; 01-01-12 - 03-31-12; Salem Nuclear Generating Station - NRC Integrated Inspection Report
ML12124A138
Person / Time
Site: Salem  PSEG icon.png
Issue date: 05/03/2012
From: Arthur Burritt
Reactor Projects Branch 3
To: Joyce T
Public Service Enterprise Group
BURRITT, AL
References
IR-12-002
Download: ML12124A138 (25)
v • d • e


Text

May 3, 2012

SUBJECT:

SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 -

NRC INTEGRATED INSPECTION REPORT 05000272/2012002 AND 05000311/2012002

Dear Mr. Joyce:

On March 31, 2012, 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 April 5, 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.

No NRC-identified or self-revealing findings were identified during this inspection.

However, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy. If you contest this NCV, 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 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 Agencywide Document Access and Management 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 Andrey Turilin Acting for/

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 05000272/2012002 and 05000311/2012002

w/Attachment: Supplemental Information

REGION I==

Docket Nos.:

50-272, 50-311

License Nos.:

DPR-70, DPR-75

Report No.:

05000272/2012002 and 05000311/2012002

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:

January 1, 2012 through March 31, 2012

Inspectors:

J. Krafty, Acting Senior Resident Inspector

D. Schroeder, Senior Resident Inspector

C. Williams, Acting Resident Inspector

P. McKenna, Resident Inspector

A. Patel, Resident Inspector

A. Turilin, Project Engineer

Approved By:

Arthur L. Burritt, Chief

Reactor Projects Branch 3

Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000272/2012002, 05000311/2012002; 01/01/2012 - 03/31/2012; Salem Nuclear

Generating Station Units 1 and 2; Routine Integrated Inspection Report.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional reactor inspectors. 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.

No findings were identified.

Other Findings

A violation 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 corrective action program (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 No. 1 (Unit 1) operated at or near 100 percent power for the duration of the inspection period.

Salem Nuclear Generating Station Unit No. 2 (Unit 2) began the period at 100 percent power and operated at full power until January 28, 2012, when power was reduced to 89 percent in order to troubleshoot a ground on the generator field windings. Unit 2 returned to full power on January 29, 2012, and operated at full power until March 23, 2012, when the reactor tripped due to a turbine trip on a spurious turbine overspeed signal. Unit 2 returned to 100 percent power on March 28, 2012 and remained at or near 100 percent power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Main article: IP 71111.01

Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors performed a review of PSEGs readiness for the onset of seasonal high levels of river detritus. The review focused on the service water (SW) and circulating water systems. The inspectors reviewed station procedures, including PSEGs seasonal weather preparation procedure, and applicable operating procedures. The inspectors conducted a review of the CAP and performed walkdowns of the water systems to verify that no unidentified issues existed that could challenge the operability of the systems during high levels of river detritus. 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

Main article: IP 71111.04Q

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

  • 12 and 13 component cooling water (CCW) trains with 11 CCW system out-of-service (OOS) on January 25, 2012
  • 12 safety injection (SI) train with 11 SI pump OOS on February 1, 2012

The inspectors selected these systems based on their risk-significance for the current plant configuration or following realignment. The inspectors reviewed applicable operating procedures, system diagrams, the updated final safety analysis report (UFSAR), technical specifications (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.

b. Findings

No findings were identified.

.2 Full System Walkdown

Main article: IP 71111.04S

a. Inspection Scope

The inspectors performed complete system walkdowns of accessible portions of the systems listed below to verify the equipment lineups were correct. The inspectors reviewed operating procedures, surveillance tests, drawings, equipment lineup procedures, and the UFSAR to verify the system was aligned to perform its required safety functions. The inspectors also reviewed electrical power availability, component lubrication and equipment cooling, hangar and support functionality, and operability of support systems. The inspectors performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and 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 CAP for resolution with the appropriate significance characterization. Additionally, the inspectors reviewed a sample of related notifications and work orders to ensure PSEG appropriately evaluated and resolved any deficiencies.

  • Unit 1, charging system on March 6 through 14, 2012

b. Findings

No findings were identified.

==1R05 Fire Protection

==

.1 Resident Inspector Quarterly Walkdowns

Main article: IP 71111.05Q

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 out of service, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.

  • Unit 2, Spent Fuel/Component Cooling Heat Exchanger and Pump Area, 84 elevation, on January 3, 2012
  • Unit 1, Demineralizer Ion Exchange Area, 100 elevation, on January 25, 2012
  • Unit 2, Demineralizer Ion Exchange Area, 100 elevation, on January 25, 2012
  • Unit 1, Spent Fuel/Component Cooling Heat Exchanger and Pump Area, 84 elevation, on February 2, 2012

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

Main article: IP 71111.05A

a. Inspection Scope

The inspectors observed a fire brigade drill scenario conducted on March 21, 2012, that involved a fire in the turbine building. The inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that PSEG personnel identified deficiencies, openly discussed them in a self-critical manner at the debrief, and took appropriate corrective actions as required. The inspectors evaluated specific attributes as follows:

  • Proper wearing of turnout gear and self-contained breathing apparatus
  • Proper use and layout of fire hoses
  • Employment of appropriate fire-fighting techniques
  • Sufficient fire-fighting equipment brought to the scene
  • Effectiveness of command and control
  • Search for victims and propagation of the fire into other plant areas
  • Smoke removal operations
  • Utilization of pre-planned strategies
  • Adherence to the pre-planned drill scenario
  • Drill objectives met

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Main article: IP 71111.06

Internal Flooding Review

a. Inspection Scope

The inspectors reviewed the UFSAR, the site internal flooding analysis, and plant procedures to verify that PSEGs flooding mitigation plans and equipment are consistent with the design requirements and the risk analysis assumptions. The inspectors also reviewed the CAP to determine if PSEG identified and corrected flooding problems and whether operator actions for coping with flooding were adequate. The inspectors also focused on Unit 2 EDG rooms to verify the adequacy of equipment seals located below the flood line, floors and water penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, control circuits, and temporary or removable flood barriers.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

Main article: IP 71111.11Q

.1 Licensed Operator Requalification Program

a. Inspection Scope

The inspectors observed licensed operator simulator training on January 31, 2012. The scenario included a small break loss of coolant accident and a failure of the 22 SI pump to start. 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 licensed operator performance during Unit 2 post-maintenance testing on the control area ventilation system and Unit 2 Delta T-Tavg surveillance testing on February 28, 2012 and March 6, 2012 respectively. 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

Main article: IP 71111.12

a. Inspection Scope

The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, or component (SSC) performance and reliability. The inspectors reviewed system health reports, CAP 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. As applicable, 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; for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2); and, the inspectors independently verified that appropriate work practices were followed for the SSCs reviewed. Additionally, the inspectors ensured that PSEG staff was identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries.

  • Unit 1, chilled water from January 31 through February 10, 2012
  • Unit 2, control area air conditioning from March 4 - 9, 2012
  • Unit 3, gas turbine generator from February 2 - 8 and March 15 - 16, 2012

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

Main article: IP 71111.13

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. As applicable for each activity, the inspectors verified that PSEG personnel performed risk assessments as required by 10 CFR 60.65(a)(4) and applicable station procedures, 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 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.

  • 12 spent fuel pump OOS for planned maintenance on January 19, 2012
  • 11 component cooling heat exchanger high flow flush on January 25, 2012
  • 21 control air supply fan OOS for planned maintenance on January 31, 2012
  • Emergent work on pressurizer relief block valve (2PR7) February 6 -8, 2012
  • 12 control air supply fan OOS for planned maintenance and 13 chiller OOS for corrective maintenance on March 6, 2012

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

Main article: IP 71111.15

a. Inspection Scope

The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:

  • Notification 20541156, Unit 1 Subcooled margin monitor channel A on January 9, 2012
  • CC-AA-309-101, Technical Evaluation 2PR7, pressurizer block valve failing to stroke on February 6, 2012
  • Notification 20548088, adverse trend in closing stroke time for S1SS-1SS49, pressurizer liquid sample isolation valve on February 24, 2012
  • TE 60082709, solid state protection relay TS620 (BC620) contact failure on March 7, 2012
  • OP-EVAL 12-002, Unit 1 and 2 SW bay material condition on March 2, 2012
  • TE 60101901, 12 Chiller trip on freeze protection on March 22, 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 assumptions in the evaluations.

b. Findings

No findings were identified.

1R18 Plant Modifications

Main article: IP 71111.18

Permanent Modifications

a. Inspection Scope

The inspectors evaluated a modification to Unit 1 SW motor operated valves (MOVs)implemented by engineering change package 80105080, Salem Unit 1 MOV Limit Switch Modification for 11SW20, 13SW20, and 1SW26. The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the design change, including work orders, MOV diagnostic tests, valve stroke time tests, and MIDAS calculations. The inspectors also reviewed revisions to the drawings, interviewed engineering personnel, and performed a walkdown of the completed modification to ensure the modification was installed as designed.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

Main article: IP 71111.19

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.

  • 1SW191, 11 charging pump room cooler service water valve repairs on January 11, 2012
  • 22CS2 containment spray discharge valve thermal overload replacement on January 18, 2012
  • 16 SW pump and motor maintenance on February 3, 2012
  • 12 residual heat removal pump recirculation flow control valve flow control loop repairs on February 10, 2012
  • 2CAA50 and 2CAA51, control room emergency air conditioning system supply dampers maintenance and pinning on February 29, 2012
  • 13 SW pump replacement on March 12, 2012
  • Unit 1, B Channel Subcooled Margin Monitor repair on March 13, 2012
  • 22CC3, component cooling pump discharge header cross connect valve repairs on March 21, 2012

b. Findings

No findings were identified.

1R22 Surveillance Testing

Main article: IP 71111.22

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.RHR-0001, Inservice Testing - 21 Residual Heat Removal Pump on January 4, 2012 (in-service test)
  • S1.OP-ST.RC-0008, RCS Water Inventory Balance on January 18, 2012 (RCS leak detection)
  • S2.MD-FT.4KV-0003, ESFAS Instrumentation Monthly Functional Test - 2C 4KV Vital Bus Undervoltage on January 20, 2012
  • S2.OP-ST.RCS-0001, Reactivity Control System Rod Control Assemblies on March 2, 2012

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

Main article: IP 71114.06

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine PSEG emergency drill on February 9, 2012, to identify any weaknesses and deficiencies in the classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator, technical support center, and emergency operations facility (EOF) to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the EOF and station drill critiques to compare inspector observations with those identified by PSEG staff in order to evaluate PSEGs critique and to verify whether the PSEG staff was properly identifying weaknesses and entering them into the CAP.

b. Findings

No findings were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification

Main article: IP 71151

.1 Safety System Functional Failures (2 samples)

a. Inspection Scope

The inspectors sampled PSEGs submittals for the Safety System Functional Failures performance indicator for both Unit 1 and Unit 2 for the period of January 1, 2011, through December 31, 2011. To determine the accuracy of the performance indicator data reported during those periods, inspectors used definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 10 CFR 50.73." The inspectors reviewed PSEGs licensee event reports (LERs) to validate the accuracy of the submittals.

b. Findings

No findings were identified.

.2 RCS Specific Activity and RCS Leak Rate (4 samples)

a. Inspection Scope

The inspectors reviewed PSEGs submittal for the RCS specific activity and RCS leak rate performance indicators for both Unit 1 and Unit 2 for the period of January 1, 2011, through December 31, 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors also reviewed RCS sample analysis and logs of daily measurements of RCS leakage, and compared that information to the data reported by the performance indicator. Additionally, the inspectors observed surveillance activities that determined the RCS identified leakage rate, and chemistry personnel taking and analyzing an RCS sample.

b. Inspection Findings

No findings were identified.

4OA2 Problem Identification and Resolution

Main article: IP 71152

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 CAP 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.

4OA3 Follow-Up of Events and Notices of Enforcement Discretion

Main article: IP 71153

.1 Plant Events

a. Inspection Scope

For the Unit 2 reactor trip due to turbine trip on March 23, 2012, the inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional personnel and compared the event details with criteria contained in Inspection Manual Chapter 0309, Reactive Inspection Decision Basis for Reactors, for consideration of potential reactive inspection activities. As applicable, the inspectors verified PSEG made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR Parts 50.72 and 50.73. The inspectors reviewed PSEGs follow-up actions related to the events to assure that PSEG implemented appropriate corrective actions commensurate with their safety significance.

b. Findings

No findings were identified.

.2 (Closed) LER 05000272/2011-005-00: Incorrect NIS Trip Setpoints Results in TS 3.0.3

Entry

On December 11, 2011, PSEG discovered that the Unit 1 intermediate range nuclear instrumentation system (NIS) trip setpoints were incorrect after an on-shift reactor operator noticed that the intermediate range NIS bistables were not lit on the RPS mimic panel as would be expected at 100% power. PSEG determined through a prompt investigation that the data used to calculate the intermediate range trip setpoints was improperly recorded during the intermediate range instrument at-power calibration procedure completed on November 24, 2011, and as a result, the intermediate range trip setpoints were improperly set during that procedure. Therefore, PSEG concluded that NIS was inoperable from November 24, 2011, when the intermediate range NIS setpoints were installed, until December 11, 2011, when PSEG discovered the error and entered the correct intermediate range trip setpoints. The enforcement aspects of this issue are discussed in Section 4OA7. The inspectors did not identify any new issues during the review of the LER. This LER is closed.

4OA6 Meetings, Including Exit

On April 5, 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.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by PSEG and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as a NCV.

  • TS 3.3.1.1, "Reactor Trip System Instrumentation, requires one operable intermediate range instrument in Modes 1, 2, and 3. When that requirement is not met, TS 3.0.3 requires that action be initiated within one hour to place the unit in hot standby within the next six hours. Contrary to the above requirements, on November 24, 2011, after technicians input incorrect trip setpoints that rendered both TS 3.3.1.1 required intermediate range NISs inoperable, PSEG did not initiate action within one hour to place the unit in hot standby within the next six hours. Upon discovery of the inoperable instruments on December 11, 2011, PSEG took immediate corrective action to input the correct intermediate range setpoints and restore operability and entered this issue into the CAP as notification 20538425. The inspectors determined that the finding was of very low safety significance (Green) in accordance with NRC IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," Mitigating Systems Cornerstone, because the finding did not represent a loss of safety system function, an actual loss of safety function of a single train for greater than its TS allowed outage time, an actual loss of safety function of one or more non-technical specification trains of equipment designated a risk significant per 10 CFR 50.65 for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and did not screen as risk significant due to seismic, flooding or severe weather initiating event.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

C. Fricker, Site Vice President
L. Wagner, Plant Manager
H. Berrick, Regulatory Assurance
D. Boyle, Salem Maintenance Rule Coordinator
D. Burgin, Manager, Emergency Preparedness
T. Cachaza, Regulatory Assurance
R. DeNight Jr., Operations Supervisor
J. Garecht, Operations Director
G. Greer, System Engineer
W. Hawthorne, I&C Supervisor
D. Johnson, System Engineer
D. Kabachinski, Emergency Preparedness Specialist
J. Kandasamy, Regulatory Affairs Manager
B. Ketterer, System Engineer
K. King, Regulatory Assurance
D. Maxey, System Engineer
R. Quon, Electrical Supervisor
G. Rich, Chemistry Supervisor
F. Rossetti, System Engineer
S. Rund, System Engineer
M. Schultz, Training Instructor
G. Sosson, Engineering Director
R. Wegner, Maintenance Director
M. Winkelspecht, System Engineer

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Closed

05000272/2011-005-00 LER Incorrect NIS Trip Setpoints Results in TS 3.0.3 Entry (Section 4OA3.2)

LIST OF DOCUMENTS REVIEWED

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