IR 05000272/2012002
| ML12124A138 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| 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) | |
Text
UNITED STATES 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
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
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
- 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
No findings were identified.
.2 Full System Walkdown
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 2, auxiliary feedwater system on February 22 through 27, 2012
- Unit 1, charging system on March 6 through 14, 2012
b. Findings
No findings were identified.
1R05 Fire Protection
.1 Resident Inspector Quarterly Walkdowns
a. Inspection Scope
The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that PSEG controlled combustible materials and ignition sources in accordance with administrative procedures. The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan, and passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for 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 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
b. Findings
No findings were identified.
.2 Fire Protection - Drill Observation
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
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
.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
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
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
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
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
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
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)
- S2.OP-ST.RC-0008, Reactor Coolant System (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)
- 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
- 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
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
.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
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
.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)