IR 05000293/2014002

IR 05000293-14-002; 01/01/2014 - 03/31/2014; Pilgrim Nuclear Power Station (Pnps); Problem Identification and Resolution

ML14129A282
Person / Time
Site:	Pilgrim
Issue date:	05/07/2014
From:	Raymond Mckinley NRC/RGN-I/DRP/PB5
To:	Dent J Entergy Nuclear Operations
McKinley R
References
IR-14-002
Download: ML14129A282 (41)

Text

May 7, 2014

SUBJECT:

PILGRIM NUCLEAR POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000293/2014002

Dear Mr. Dent:

On March 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Pilgrim Nuclear Power Station (PNPS). The enclosed inspection report documents the inspection results, which were discussed on April 16, 2014, with you and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

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

This report documents one violation of NRC requirements of very low safety significance (Green). However, because of the very low safety significance, and because it is entered into your corrective action program, the NRC is treating this finding as a non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest the non-cited violation in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at PNPS. In addition, if you disagree with the cross-cutting aspect assigned to the finding in the report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Resident at PNPS.

Additionally, as we informed you in the most recent NRC integrated inspection report, cross-cutting aspects identified in the last six months of 2013 using the previous terminology were being converted in accordance with the cross-reference in Inspection Manual Chapter 0310.

Section 4OA5 of the enclosed report documents the conversion of these cross-cutting aspects which will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with Inspection Manual Chapter 0305 starting with the 2014 mid-cycle assessment review. If you disagree with the cross-cutting aspect assigned, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Resident Inspector at PNPS.

In accordance with Title 10 of the Code of Federal Regulations (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 NRCs Public Document Room or from the Publicly Available Records component of the NRCs Agencywide Documents 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/

Raymond R. McKinley, Chief Reactor Projects Branch 5 Division of Reactor Projects Docket No. 50-293 License No. DPR-35

Enclosure:

Inspection Report 05000293/2014002 w/Attachment: Supplementary Information

REGION I==

Docket No. 50-293 License No. DPR-35 Report No. 05000293/2014002 Licensee: Entergy Nuclear Operations, Inc. (Entergy)

Facility: Pilgrim Nuclear Power Station Location: 600 Rocky Hill Road Plymouth, MA 02360 Dates: January 1, 2014 through March 31, 2014 Inspectors: M. Schneider, Senior Resident Inspector, Division of Reactor Projects (DRP)

B. Scrabeck, Resident Inspector, DRP B. Dionne, Health Physicist, Division of Reactor Safety (DRS)

C. Lally, Operations Engineer, DRS J. Patel, Reactor Inspector, DRS Approved By: Raymond R. McKinley, Chief Reactor Projects Branch 5 Division of Reactor Projects Enclosure

SUMMARY

IR 05000293/2014002; 01/01/2014 03/31/2014; Pilgrim Nuclear Power Station (PNPS);

Problem Identification and Resolution.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. The inspectors identified one non-cited violation (NCV) of very low safety significance (Green). The significance of most findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Aspects Within the Cross-Cutting Areas, dated December 19, 2013. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated July 9, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5.

Cornerstone: Mitigating Systems

Green.

The inspectors identified an NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion III, Design Control, in that Entergy did not correctly translate the design basis into procedures. Specifically, as of February 26, 2014, procedure 2.4.A.23 did not provide correct information for determining operability of the shutdown transformer (SDT) when the SDT is energized from one of its alternate sources. Entergy entered this issue into their corrective action program (CAP) as condition report (CR)-PNP-2014-00861.

The inspectors determined that Entergys failure to provide adequate control for determining operability of the SDT was a performance deficiency that was reasonably within Entergys ability to foresee and prevent. The performance deficiency was determined to be more than minor because it was associated with the configuration control attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the capability of systems that respond to initiating events to prevent undesirable consequences. Using IMC 0609, Appendix A, the inspectors determined that the finding was very low safety-significance because this finding did not represent an actual loss of function of the SDT for greater than its technical specification (TS) allowed outage time. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, in that Entergy personnel did not thoroughly evaluate the problems, which included understanding the results of the calculation and subsequently translating those results into the operating procedure. [P.2] (Section 4OA2)

REPORT DETAILS

Summary of Plant Status

Pilgrim Nuclear Power Station began the inspection period operating at 100 percent reactor power. On March 19, Pilgrim reduced power to 45 percent to perform a condenser thermal backwash, and returned to 100 percent power on March 20. On March 21, Pilgrim reduced power to 87 percent to perform a control rod pattern adjustment, returned to 100 percent power on the same day, and continued to operate at 100 percent power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors performed a review of Entergys readiness for Winter Storm Hercules on January 2, 2014, Winter Storm Janus on January 21, and a winter storm on March 25. The review focused on Entergys preparations for the storm. The inspectors reviewed station procedures including Entergys coastal storm, high wind, and severe weather procedures. The inspectors performed walkdowns of the site to ensure that station personnel had identified issues that could challenge the operability of systems during high wind and winter storm conditions. 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:

Residual Heat Removal (RHR) system Loop A during maintenance on B and D RHR Pumps on January 6 Emergency Diesel Generator (EDG) A during maintenance on EDG B on January 14 High Pressure Coolant Injection (HPCI) system during maintenance on Reactor Core Isolation Cooling (RCIC) system on January 28 RCIC system during power maneuvers on March 29 The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the Updated Final Safety Analysis Report (UFSAR), TS, work orders (WO), CRs, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. The inspectors also reviewed whether Entergy staff had properly identified equipment issues and entered them into the CAP for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Resident Inspector Quarterly Walkdowns

a. Inspection Scope

The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that Entergy 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.

Fire Area 1.10, Fire Zone 1.28, Reactor Recirculation Pump Motor Generator Room on February 7 Fire Area 3.2, Fire Zone 3.2, Cable Spreading Room on February 7 Fire Area 1.10, Fire Zone 2.8, Condensate Pumps Area on March 8 Fire Area 1.10, Fire Zone 2.12, Feedwater Pumps C Area on March 8 Fire Area 5.3, Fire Zone 5.5, Diesel Fire Pump Day Tank Room on March 8

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

The inspectors observed a fire brigade drill scenario conducted on February 27, which involved a fire in the operations and maintenance building. The inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that Entergy 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 The inspectors also evaluated the fire brigades response actions to determine whether their actions were in accordance with Entergys fire-fighting strategies.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on February 10, which included an inadvertent RCIC initiation; a leak in Salt Service Water (SSW) piping requiring crosstie of Reactor Building Closed Cooling Water (RBCCW) subsystems and splitting of SSW loops; a non-recoverable loss of seal cooling to seawater pumps requiring a manual reactor scram and isolation of Main Steam Isolation Valves (MSIVs);several stuck control rods requiring manual insertion; and an unisolable leak in the HPCI system resulting in emergency depressurization and declaration of a Site Area Emergency. 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 TS 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

For the plant activities listed below, the inspectors observed and reviewed operator performance in the main control room. The inspectors reviewed operational and alarm response and implementation of procedural guidance. The inspectors also observed control room conduct and control of evolutions and events.

Reactor Plant power maneuvers to support condenser thermal backwash on March 19 and 20

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 WOs, and maintenance rule basis documents to ensure that Entergy was identifying and properly evaluating performance problems within the scope of the maintenance rule. For each sample selected, the inspectors verified that the SSC was properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and verified that the (a)(2) performance criteria established by Entergy staff was reasonable. As applicable, for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2). Additionally, the inspectors ensured that Entergy staff were identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries.

Maintenance Rule Functional Failure determination for the failure of the security diesel generator to supply loads on March 10 Maintenance Rule Functional Failure determination for the failure of the Rod Worth Minimizer on January 11 Maintenance Rule Functional Failure determination for the failure of the neutron monitoring digital recorder on January 19

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 Entergy performed the appropriate risk assessments prior to removing equipment for work. The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that Entergy personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When Entergy 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.

Planned Yellow risk condition during maintenance on B RHR loop on January 6 Emergent work controls and risk assessment due to unscheduled maintenance on the HPCI system on January 27 Planned Yellow risk condition during RCIC maintenance on January 28 Planned Green risk condition during HPCI maintenance outage on February 10 Planned Yellow risk condition during B EDG and B RHR pump logic system functional test on February 14 Planned Green risk condition during maintenance on the K-117 diesel air compressor and the RBCCW system on February 21

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:

Low EDG room temperatures on January 2 Control rod drive A pump oil leak on February 12 Reactor feedwater A check valve leakage on February 13 Leak in SSW piping downstream from RBCCW Heat Exchanger B on February 24 Supply Breaker to Bus A5 unexpectedly recharged during trip testing on February 27 Shutdown transformer 125 volts direct current (VDC) battery capacity on March 2 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 from the TSs and UFSAR to Entergys 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 Entergy. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.

b. Findings

No findings were identified.

1R18 Plant Modifications

Temporary Modifications

a. Inspection Scope

The inspectors reviewed the temporary modifications listed below to determine whether the modifications affected the safety functions of systems that are important to safety.

The inspectors reviewed 10 CFR 50.59 documentation and post-modification testing results, and conducted field walkdowns of the modifications to verify that the temporary modifications did not degrade the design bases, licensing bases, and performance capability of the affected systems.

Supplemental Heating to EDG Building on February 24 Temporary Power to Outdoor Lighting Panel on March 5

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.

B EDG maintenance on January 18 Replacement of RCIC drain valve on January 30 Instrument air compressor K-110 unloader air leak and time delay relay replacement on February 14 Replacement of RBCCW pump P-202E time delay relay on February 20 HPCI pump and valve maintenance on March 4 HPCI seal weld repair on March 4 EDG A Turbo Assist Air Receiver Valve, Open, Inspect & Replace on March 4

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 Entergy 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:

RCIC Valve Quarterly Operability Test Containment Isolation Valve (CIV) on January 2 RCIC Pump Quarterly Operability and Flow Test In-service Test (IST) on January 2 B EDG monthly surveillance on January 20 Station Blackout Diesel Generator surveillance on February 27 HPCI valve operability test (IST) on March 5 Reactor Coolant System (RCS) leakage surveillance on March 28

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Training Observations

a. Inspection Scope

The inspectors observed a simulator training evolution for licensed operators on February 10, which required emergency plan implementation by an operations crew.

Entergy planned for this evolution to be evaluated and included in performance indicator (PI) data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors activities was to note any weakness and deficiencies in the crews performance and ensure that Entergy evaluators noted the same issues and entered them into their CAP.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

During February 18-21, 2014, the inspectors reviewed Entergys performance in assessing the radiological hazards and exposure control in the workplace. The inspectors used the requirements in 10 CFR 20 and guidance in Regulatory Guide (RG)8.38, Control of Access to High and Very High Radiation Areas for Nuclear Plants, TSs, and the PNPS procedures required by TSs as criteria for determining compliance.

a. Inspection Scope

The inspectors reviewed the PNPS 2013 PIs for the occupational exposure cornerstone.

The inspectors reviewed the results of Radiation Protection program audits. The inspectors reviewed any reports of operational occurrences related to occupational radiation safety since the last inspection.

Radiological Hazard Assessment The inspectors reviewed any changes to plant operations since the last inspection that resulted in new radiological hazards for onsite workers or members of the public. The inspectors reviewed the radiological surveys from the Reactor Building 74 Elevation Skimmer Corridor and the Radwaste Building 13 Elevation and Spent Resin Rooms.

The inspectors conducted walk-downs and independent radiation measurements in the facility, including reactor building, advanced off-gas building, and radioactive material tool and equipment storage areas.

Instructions to Workers The inspectors selected three containers of radioactive materials and assessed whether they were labeled and controlled in accordance with 10 CFR 20 requirements. The inspectors reviewed the following radiation work permits (RWP) used to access high radiation areas (HRA).

RWP No 2014076, Independent Spent Fuel Storage Installation (ISFSI) Activities RWP No. 2014009, NRC Observations and Inspections For these RWPs, the inspectors assessed the permissible dose and electronic personal dosimeter alarm set-points were in conformance with survey indications and plant procedural requirements.

Radiological Hazards Control and Work Coverage The inspectors examined the physical and programmatic controls for highly activated materials stored within spent fuel and other storage pools. The inspectors examined the posting and physical controls for selected HRAs and very high radiation areas (VHRAs).

Risk-Significant HRA and VHRA Controls The inspectors discussed with the Radiation Protection Manager (RPM), any changes to the controls and procedures for high-risk HRAs and VHRAs. The inspectors discussed with first-line health physics supervisors the controls in place for potential transient VHRAs during certain plant operations. The inspectors evaluated the access controls for VHRAs.

Miscellaneous Since the last inspection of this area, Entergy hired a new individual to serve as the RPM. The inspectors reviewed the qualifications of this new individual for this position.

The specific training and qualifications are set forth in the Entergy Quality Assurance Program Manual, Revision 25, which endorses RG 1.8.

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls

The inspectors assessed performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspectors used the requirements in 10 CFR 20, RG 8.8, Information Relevant to Ensuring that Occupational Radiation Exposures at Nuclear Power Plants will be As Low As Is Reasonably Achievable, RG 8.10, Operating Philosophy for Maintaining Occupational Radiation Exposure As Low as Is Reasonably Achievable, TSs, and PNPS procedures required by TSs as criteria for determining compliance.

a. Inspection Scope

The inspectors reviewed PNPSs collective dose history, current exposure trends, and planned work activities in order to assess current performance and exposure challenges.

The inspectors reviewed the plants three year rolling average collective exposure.

The inspectors compared the site-specific trends in collective exposures against the industry average values and those values from similar vintage reactors. In addition, the inspectors reviewed any changes in the radioactive source term by reviewing the trend in average contact dose rate with recirculation piping.

The inspectors reviewed site-specific procedures associated with maintaining occupational exposures ALARA, which included a review of processes used to estimate and track exposures from specific work activities.

Radiological Work Planning The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure reduction requirements. The inspectors determined whether Entergy grouped the radiological work into work activities, based on historical precedence and industry norms. The inspectors assessed whether Entergys work planning identified appropriate dose reduction techniques; considered alternate dose reduction features; and estimated reasonable dose goals. The inspectors evaluated whether the ALARA assessments had taken into account decreased worker efficiency from use of respiratory protective devices. The inspectors determined whether Entergys work planning considered the use of remote technologies and the use of dose reduction insights from industry operating experience. The inspectors assessed the integration of ALARA requirements into work procedures and RWP documents.

Verification of Dose Estimates and Exposure Tracking Systems The inspectors evaluated whether the licensee had established measures to track, trend, and to reduce occupational doses for ongoing work activities.

b. Findings

No findings were identified

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

The inspectors verified that gaseous and liquid effluent processing systems are maintained so radiological discharges are properly reduced, monitored, and released.

The inspectors verified the accuracy of the calculations for effluent releases and public doses.

The inspectors used the requirements in 10 CFR 20; 10 CFR 50.35(a); TSs; 10 CFR 50, Appendix A, Criterion 60, Control of Release of Radioactivity to the Environment, and Criterion 64, Monitoring Radioactive Releases; 10 CFR 50, Appendix I, Numerical Guides for Design Objectives and Limiting Conditions for Operations to Meet the Criterion As Low as is Reasonably Achievable for Radioactive Material in Light-Water-Cooled Nuclear Power Reactor Effluents; 10 CFR 50.75(g), Reporting and Recordkeeping for Decommissioning Planning; 40 CFR Part 141, Maximum Contaminant Levels for Radionuclides; 40 CFR Part 190, Environmental Radiation Protection Standards for Nuclear Power Operations; RG 1.109, Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents; RG 1.21, Measuring, Evaluating, Reporting Radioactive Material in Liquid and Gaseous Effluents and Solid Waste; NUREG 1302, Offsite Dose Calculation Manual (ODCM) Guidance: Standard Radiological Effluent Controls; applicable Industry standards; and licensee procedures required by TSs/ODCM as criteria for determining compliance.

a. Inspection Scope

Groundwater Protection Initiative (GPI) Program The inspectors reviewed groundwater monitoring results and changes to PNPSs written program for identifying and controlling contaminated spills/leaks to groundwater.

GPI Implementation The inspectors reviewed the voluntary implementation of Nuclear Energy Institute (NEI)

GPI to determine if Entergy has continued to effectively implement the GPI as intended.

Tritium Spill Reported as Event Notification 48909 On April 10, 2013, while investigating a water leak from an electrical penetration inside the Reactor Building, a tritiated water leak was discovered. This leak was reported to the NRC in Event Notification 48909 on April 10, 2013. A boroscopic investigation into the related neutralizer sump discharge line identified a pipe joint separation about 6 - 8 feet underground. Subsequently, further discharges through this underground discharge line were terminated until the discharge line could be rerouted above ground.

Subsequently, in December 2013, a new ground water monitoring well was installed to monitor leaks from the neutralizer sump discharge piping. As expected, the initial sampling of ground water from this well obtained during monitoring well development and testing indicated elevated tritium concentrations.

A sample collected from the new Monitoring Well (MW)-219 on December 30, 2013, resulted in a tritium concentration of 69,000 picoCuries/Liter (pCi/L). No other plant-related radionuclides were detected. MW-219 is located about 8 feet down gradient from Catch Basin (CB) 10 and is on the east side of the plant about 200 feet south east from the Discharge Canal and west of the Reactor Building Auxiliary Bay.

Currently, no further discharges are being made until the investigation is completed to ensure there are no other piping system leaks associated with the neutralizer sump discharge piping. Recent sampling from this MW has indicated a downward trend: on January 6, 2014, the tritium concentration was 20,000 pCi/L; on January 9, 2014, the concentration was 14,300 pCi/L; and on February 3, 2014, the concentration was 5,120 pCi/L. A preliminary dose estimate based on the consumption of fish and shellfish based on tritium contaminated groundwater migration into the Massachusetts Bay, is less than one millirem (mrem) per year and this conservative bounding evaluation to a maximum member of the public represents an insignificant fraction of the NRC public dose limit of 100 mrem/yr.

The NRC Inspectors will continue to follow the licensee's performance closely to assure:

1) conformance with applicable regulatory requirements, 2) the new piping system integrity is verified prior to any future radionuclide discharges through this piping system, 3) remediation of soil and groundwater is performed, if necessary, and 4) to assure that public health and safety is maintained.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Safety System Functional Failures (1 sample)

a. Inspection Scope

The inspectors sampled Entergys submittals for the Safety System Functional Failures (SSFF) PI for the period of January 1, 2013 through December 31, 2013. To determine the accuracy of the PI data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 10 CFR 50.73. The inspectors reviewed Entergys plant logs, CRs, licensee event reports (LERs), and NRC integrated inspection reports to validate the accuracy of the submittals.

b. Findings

Introduction.

The inspectors identified an Unresolved Item (URI) associated with Entergys reporting of SSFF PI data for the third quarter of 2013.

Description.

On July 16 and again on July 17, due to increased sea water surface temperature and the contribution of recirculation water from the plants outfall, Pilgrim declared the ultimate heat sink (UHS) and SSW system inoperable due to exceeding the high sea water inlet temperature of 75 degrees Fahrenheit. These events were reported under LER 05000293/2013-007-00. Although there were two instances of the UHS and SSW system being declared inoperable, the Entergy submittal of PI data for the third quarter of 2013 reported these instances as a single SSFF.

This issue is a URI pending resolution of the differing interpretation of guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, at the next regularly scheduled Reactor Oversight Process Working Group Meeting. (URI 05000293/2014002-01, Reporting of Safety System Functional Failure Performance Indicator for Ultimate Heat Sink Inoperability)

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

a. Inspection Scope

The inspectors reviewed Entergys submittal for the RCS specific activity and RCS leak rate PIs for the period of January 1, 2013 through December 31, 2013. To determine the accuracy of the PI data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that Entergy entered issues into their 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 CAP and periodically attended CR review group meetings.

b. Findings

No findings were identified.

.2 Annual Sample: Trip of Panel Y-1 breaker and Resultant Trip of All Reactor Feed Pumps

and Manual Reactor Scram

a. Inspection Scope

The inspectors performed an in-depth review of Entergys cause analysis, troubleshooting plans, extent of condition reviews, and corrective actions associated with the trip of the Panel Y-1 breaker and loss of all reactor feed pumps and manual reactor scram on August 22. This inspection focused on Entergys problem identification, evaluation, and resolution of issues arising from the trip of the Panel Y-1 breaker.

The inspectors assessed Entergys cause analysis, troubleshooting plans, extent of condition reviews, and corrective actions to determine whether Entergy was appropriately identifying, characterizing, and correcting problems associated with the trip of the Panel Y-1 breaker and whether the planned or completed corrective actions were appropriate. The inspectors compared the actions taken to the requirements of Entergys CAP and 10 CFR 50, Appendix B, Criterion XVI, Corrective Action.

b. Findings

No findings were identified.

The inspectors determined that Entergy appropriately identified, characterized, and implemented corrective actions associated with the trip of the Panel Y-1 breaker and subsequent trip of all reactor feed pumps and manual reactor scram. Entergy took appropriate actions to identify the cause of the issue. The cause was determined to be an improperly fabricated splice near a solenoid valve that had failed, resulting in a short to ground and tripping of the breaker. This resulted in a loss of power to cooling water sensing switches and relays resulting in the tripping of the reactor feed pumps. This was an unintended consequence of an engineering design change. The inspectors noted a missed opportunity by Entergy to identify the design flaw in the engineering design change due to insufficient peer review and technical challenge, and an improperly reviewed CR. Entergy promptly investigated the cause and extent of condition for other improperly fabricated splices, and continued with previous corrective actions to resolve programmatic weaknesses in the Engineering department.

The inspectors determined Entergys overall response to the issue was commensurate with the safety significance, was timely, and the actions taken and planned were reasonable to resolve the issues identified by the trip of the Panel Y-1 breaker.

.2 Annual Sample: Manomet Substation Loads Affecting the SDT Operability

a. Inspection Scope

The inspectors performed an in-depth review of Entergys operability evaluation and corrective actions associated with CR-PNP-2013-01819. The CR documented an issue that was identified in an NSTAR calculation performed for the Pilgrim 23 kilovolt (kV)system under the Nuclear Plant Interface Requirement (NPIR). The calculation determined that under certain conditions, when the system loads at the 23 kV Manomet Substation exceed 22.2 megawatts, Pilgrims post-contingency voltage requirements cannot be met which affects the operability of the SDT. On March 3, 2013, Entergy entered this issue in their CAP, completed an operability evaluation, and assigned corrective actions to provide permanent solution to this issue.

The SDT is the secondary offsite alternating current (AC) power source to essential station auxiliaries. The SDT supplies voltage to either 4 kV safeguard buses A5 or A6 in the event the unit auxiliary transformer, startup transformer, and/or an EDG fail to energize a safeguard bus during a postulated accident. In normal conditions, the SDT is energized by the 23 kV system Line 72 via the F15 circuit switcher that is powered from the Manomet Substation Line 108. As a result of the NSTAR calculation, a condition was identified that affected the SDT operability.

The inspectors assessed Entergys problem identification threshold, extent of condition reviews, operability evaluations, and the prioritization and timeliness of corrective actions to determine whether Entergy was appropriately identifying, characterizing, and correcting problems associated with the identified issues and whether the planned or completed corrective actions were appropriate to prevent recurrence. Additionally, the inspectors performed walkdowns of the SDT and safeguard buses A5 and A6 to assess if abnormal conditions existed and to assess the material condition of the equipment.

The inspectors also interviewed plant personnel and reviewed the operability evaluation and corrective actions.

The inspectors determined that Entergy properly implemented their corrective action process regarding the initial discovery of the issue. The CR package was complete and included an operability evaluation, reportability determination, and corrective actions.

The operability evaluation determined that the SDT was operable with compensatory measures in place. The inspectors reviewed the operability evaluation and two compensatory measures identified in the evaluation. Entergy implemented the two compensatory measures to monitor the system loads on the 23 kV system. Entergy issued a standing order for control room operators to perform a daily call with the NSTAR distribution system operator to verify the system load and determine if the load was exceeded since previously contacted. Entergy has also set up a formal notification system with NSTAR to monitor the Manomet Substation load and notify the Pilgrim control room when load exceeds 22.2 megawatts. This notification is currently being performed by an automated message sent to a pager located at the control room supervisor desk. These compensatory measures are considered interim solutions.

Entergy has planned corrective actions to work with the NSTAR operator to implement a permanent solution to monitor the load in real time.

b. Findings

Introduction.

The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, in that Entergy did not correctly translate the design basis into procedures. Specifically, as of February 26, 2014, procedure 2.4.A.23, Loss/Degradation of 23kV Line, was not updated to include the results of the NSTAR calculation that was performed to support operability of the SDT. As a result, the procedure did not provide correct information for determining operability of the SDT when the SDT is energized from one of its alternate sources.

Description.

PNPS UFSAR Chapter 8, Electrical Power Systems, describes the SDT as the secondary offsite AC power source that provides AC power to essential station auxiliaries. In section 8.3.2, Safety Design Basis, it is described that the secondary source is designed to be available following a loss of all onsite AC power supplies and the preferred AC power source, to assure that fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded. The SDT is capable of supplying the loads on the emergency service portion of the auxiliary power distribution system in the time required for safe shutdown of the reactor as a result of the anticipated operational occurrences.

The SDT is connected to 23 kV Line 72, which is normally energized from the Manomet Substation of the NSTAR distribution system. The Manomet 23 kV substation is normally supplied from Line 108. The West Pond 23 kV substation Line 71 and the Valley 23 kV substation Line 73 are two alternate sources of 23 kV supply to the SDT via Line 72 in the event that the supply from the Manomet 23 kV substation is not available.

In order to maintain operability of the SDT, Entergy had to implement measures to ensure that post-contingency voltage (i.e. voltage following trip of the unit) does not drop below the calculated minimum voltage requirement at the point of interconnection. The NPIR required the 23 kV voltage to be at 95 percent or higher within 12 seconds of the PNPS generator trip. This was accomplished at PNPS by calculating post-contingency voltage using a real time contingency analyzer maintained by the distribution system operator NSTAR Electric. The calculation performed by NSTAR Electric, titled Pilgrim 23 kV NPIR Study Steady State and Stability Analysis, was issued on September 13, 2012. The calculation results indicated that the normal supply from Manomet substation Line 108 marginally meets the requirement; the alternate supply from West Pond substation Line 71 meets the requirement at reduced load level; while the alternate supply from Valley substation Line 73 does not meet the requirement at any reduced load levels.

Interface agreements between the station and the distribution system operator required the distribution system operator to notify the PNPS control room of a nonconforming alignment or change in 23 kV supply line. When notified, the PNPS control room then performs procedure 2.4.A.23 for Loss/Degradation of 23 kV Line and executes appropriate sections of that procedure. The inspectors reviewed the procedure to verify that the results of the NSTAR calculation are adequately captured in the procedure via procedural revisions. The inspectors noted that step 4.2[2] states If NSTAR Line # 72 which feeds the Shutdown Transformer is being fed from NSTAR Line # 73 (Alternate Source) instead of NSTAR Line # 108 (Normal Feed), then: The Shutdown Transformer is OPERABLE. The inspectors questioned this step and asked how this is translated from the NSTAR calculation and the design requirements.

In response to the inspectors question, Entergy initiated CR-PNP-2014-00861 on February 26, 2014. Entergy agreed that the procedure had incorrect information in it and that it could have affected the operators ability to evaluate operability of the SDT.

Consequently, this could have resulted in increased risk due to other redundant plant components or mitigating systems being out of service for maintenance at the same time. Entergy performed a review of control room logs and contacted the distribution system operator to determine if PNPS was in the configuration described in procedure step 4.2[2] between September 13, 2012, and February 26, 2014. The review identified that on February 21, 2013, at 8:45 am, NSTAR reported to the PNPS control room that the 23 kV Line 72 was being fed from Line 73 (alternate feed to PNPS). At 10:22 am, the PNPS control room was notified that the 23 kV Line 72 was restored to its normal supply. This condition existed for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 37 minutes. The PNPS TS allowed outage time for the SDT is 7 days provided that during this time period both diesel generators and associated buses, and the start-up transformer remain operable. Entergy verified that during that time period both diesel generators and associated buses, and the start-up transformer were operable.

Analysis.

The inspectors determined that Entergys failure to provide adequate control for determining operability of the SDT was a performance deficiency that was reasonably within Entergys ability to foresee and prevent. The performance deficiency was determined to be more than minor because it was associated with the configuration control attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors assessed this finding in accordance with the NRC IMC 0609, Significance Determination Process, Appendix A, The Significance Determination Process for Findings At-Power. Using Exhibit 2, Mitigating Systems Screening Questions, Section A, Mitigating SSCs and Functionality, the inspectors concluded that this finding did not represent an actual loss of function of the SDT for greater than its TS allowed outage time. Therefore, the finding was determined to be of very low safety significance (Green).

The inspectors determined that this finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, in that Entergy personnel did not thoroughly evaluate the problems, which included properly understanding results of the calculation and subsequently translating those results to the operating procedure. [P.2]

Enforcement.

The inspectors identified a violation of 10 CFR 50, Appendix B, Criterion III, Design Control, which states, in part, Measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, Entergy did not establish measures to assure that the design basis was correctly translated into procedures and instructions. Specifically, as of February 26, 2014, Entergy had not correctly translated the design basis into procedures, in that procedure 2.4.A.23 was not updated to include the results of the NSTAR calculation that was performed to support operability of the SDT. As a result, the procedure did not provide correct information regarding operability of the SDT. Because this violation was of very low safety-significance (Green) and was entered into Entergys CAP as CR-PNP-2014-00861, this violation is being treated as a NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000293/2014002-02, Inadequate Procedure for Determining Operability of the Shutdown Transformer)

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

.1 Plant Events

a. Inspection Scope

For the plant events listed below, 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 IMC 0309, Reactive Inspection Decision Basis for Reactors, for consideration of potential reactive inspection activities. As applicable, the inspectors verified that Entergy made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR Parts 50.72 and 50.73. The inspectors reviewed Entergys follow-up actions related to the events to assure that Entergy implemented appropriate corrective actions commensurate with their safety significance.

Operator conduct of a plant downpower to approximately 50 percent power to support a condenser thermal backwash and subsequent return to 100 percent power on March 19 through 20 Operator response to an unplanned TS shutdown action statement entry when the B SSW was declared inoperable on March 23

b. Findings

No findings were identified.

.2 (Closed) LER 05000293/2013-002-00 and LER 05000293/2013-002-01: SRV-3B Safety

Relief Valve Inoperable Due to Leakage and Setpoint Drift The inspectors reviewed Entergys actions and reportability criteria associated with LERs 05000293/2013-002-00 and 05000293/2013-002-01, which is addressed in CR-PNP-2013-0378. On January 20, 3013, with the reactor at 100 percent power, Pilgrim operators declared safety relief valve (SRV)-3B inoperable and entered TS 3.6.D.2 requiring an orderly reactor shutdown. SRV-3B had been declared inoperable in accordance with PNPS procedures which state an SRV is inoperable if the first stage pilot thermocouple temperature is 35 degrees Fahrenheit below its baseline temperature. The cause of the SRV leakage was that the natural frequency of the pilot assembly was close to the resonant frequency of the valve assembly when installed on the PNPS main steam line, as well as wear and looseness of parts in the main stage of SRV-3B. Corrective actions that have been completed include the replacement of the SRV-3B pilot with a refurbished and tested pilot, and to revise station procedures to reduce reactor power and pressure to stop leakage if it were to occur. Additional planned corrective actions are to adjust pilot setpoints within the allowed band to minimize leakage potential, to replace pilots that contain bellows springs of the same material and heat treatment, and to order new pilot assemblies that have been designed to raise the natural frequency of the pilot. The inspectors did not identify any new issues during the review of these LERs. These LERs are closed.

.3 (Closed) LER 05000293/2013-010-00: Automatic Group I Primary Containment Isolation

Actuation During Plant Startup Due to Reactor High Water Level The inspectors reviewed Entergys actions and reportability criteria associated with LER 05000293/2013-010-00, which is addressed in CR-PNP-2013-7066. On October 19, 2013, with the reactor at one percent power and the mode switch in START UP, and reactor pressure at approximately 290 psig, Pilgrim experienced an automatic Group I primary containment isolation and resultant closure of the MSIVs, due to a high reactor water level condition. Reactor water level was recovered and maintained within the normal bands, and the reactor was shut down. The cause of the reactor high water level was a malfunction of the pilot valve bushing in the mechanical pressure regulator of the turbine generator control system. The pilot valve bushing failed to rotate as designed, resulting in excessive friction in the pilot valve, and increased error between turbine steam pressure and the mechanical pressure regulator setpoint, which resulted in the unexpected opening of three turbine steam bypass valves, and the resultant reactor water level swell. Additionally, degraded oil quality was identified as a contributing cause. Immediate corrective actions were to flush the needle valve that controls flow to the mechanical pressure regulator pilot valve bushing, to exercise the pilot valve bushing, and to implement an operations compensatory measure to verify proper rotation during plant startups. Corrective actions that have since been completed include the incorporation of the aforementioned operations compensatory measures into plant operating procedures and establishing a periodic preventive maintenance task for the replacement of turbine lube oil filter elements in the main turbine lube oil filter assembly. The inspectors did not identify any new issues during the review of this LER.

This LER is closed.

4OA5 Other Activities

.1 Groundwater Protection Initiative (GPI)

a. Inspection Scope

The inspectors reviewed the voluntary NEI GPI and changes to Entergys written program for identifying and controlling contaminated spills/leaks to the groundwater.

The objective of the review was to determine if Entergy has effectively implemented the GPI in light of the recent groundwater concentrations of tritium from the leak in the neutralizer sump discharge line and catch basins.

b. Findings and Observations

No findings were identified.

Three observations were identified concerning non-compliance with the NEI 07-07 GPI.

The associated acceptance criteria for items 1.1.c, 1.4. b and 1.4.c are as follows:

1.1.c - Identify potential pathways for ground water migration from on-site locations to off-site locations through ground water.

Entergy fleet procedure for the GPI, EN-CY-111, Radiological GW Monitoring Program, Revision 2, step 5.13 [2] requires, in part, that each facility shall establish protocols to prevent the migration of licensed material offsite. This shall include establishing documentation outlining the decision making process for remediation of leaks and spills or other instances of inadvertent releases which is site specific and shall consider migration pathways, and evaluating the dose to members of the public from the leak or spill using realistic exposure scenarios. The methodology for calculating dose to the public is described in Pilgrim procedure PNPS 7.9.15, Dose Assessment, Revision 0, and PNPS ODCM, Revision 10.

The methodology for calculating effluent releases and the associated public dose from a radioactive spill/leak to groundwater has not been included in these dose assessment documents. CR-2014-01321 has been written to revise the ODCM and applicable procedure(s) to include the appropriate dose assessment methodology in order to evaluate the impact of groundwater migration for remediation decision making.

1.4.b - Evaluate the potential for detectable levels of licensed material resulting from planned releases of liquids and/or airborne materials.

Entergy fleet procedure for the GPI, EN-CY-111, Radiological GW Monitoring Program, Revision 2, step 5.13 [2] requires Each facility shall establish protocols to prevent the migration of licensed material offsite. This shall include:

(d) Evaluating the potential for detectable levels of licensed material resulting from planned releases of liquids and/or airborne materials. In addition, step 5.5 [1] Atmospheric Deposition Collection and Analysis states the Chemistry Manager or designee shall assess the potential contribution of atmospheric deposition of tritium to groundwater using Attachment 9.3 Atmospheric Deposition

Analysis.

No completed Attachment 9.3 or report was provided that demonstrated an evaluation was performed to estimate the radiological impacts on the environment from routine gaseous and liquid releases. The study is underway but the results have not yet been summarized.

CR-2014-01321 has been written to document the need to draft a report to summarize the impact of routine radioactive releases on the onsite environment.

1.4.c - Evaluate and document, as appropriate, decommissioning impacts resulting from remediation activities or the absence thereof.

Entergy fleet procedure for the GPI, EN-CY-111, Radiological GW Monitoring Program, Revision 2, step 5.13 [2] requires Each facility shall establish protocols to prevent the migration of licensed material offsite. This shall include:

(e) Evaluating and documenting, as appropriate, decommissioning impacts resulting from remediation activities or the absence thereof. In addition, Pilgrim procedure 1.

3.140, Decision Making Remediation Efforts for Inadvertent Releases, Revision 1, in step 6.6 [2] requires, Once the costs have been estimated, perform a cost benefit analysis which should be factored into the business decision regarding the remediation option. As of the date of this inspection, no cost-benefit analysis has been performed or documented. The licensee is preparing cost information on the options to repair the leak to the neutralizer sump discharge line. The licensee is also awaiting the results of a characterization survey near the break in the neutralizer sump discharge line and near CB 10. CR 2014-01321 has been written to document the need to perform a cost-benefit analysis for the various remediation options including the natural attenuation option.

All three of these issues are considered to be minor, since they do not affect safety-related SSCs. Also, none of these issues impacted any requirements for radioactive effluent monitoring/environmental sampling contained in TS and ODCM.

.2 Cross-cutting Aspect Conversion

The table below provides a cross-reference from the 2013 and earlier findings and associated cross-cutting aspects to the new cross-cutting aspects resulting from the common language initiative. These aspects and any others identified since January 2014, will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review.

Finding Old Cross-Cutting Aspect New Cross-Cutting Aspect 05000293/2013004-01 P.1

(d) P.3 05000293/2013008-01 P.1

(c) P.2 05000293/2013008-02 P.1

(d) P.3 05000293/2013008-03 H.1

(b) H.14 05000293/2013005-01 P.1

(c) P.2 05000293/2013005-02 H.2

(c) H.7 05000293/2013403-02 H.1

(b) H.14 05000293/2013403-03 H.4

(c) H.2 05000293/2013403-04 P.1

(d) P.3 05000293/2013403-05 P.1

(d) P.3

4OA6 Meetings, Including Exit

On February 27, 2014, the inspectors presented the inspection results to Mr. Norman Eisenmann, Acting Design Engineering Supervisor, and other members of the PNPS staff. The inspectors discussed one open item which required additional information from the Entergy staff to determine if the performance deficiency was more than minor.

On April 10, 2014, the inspectors reviewed the additional information, finalized a finding and discussed the results via phone with Mr. Robert Byrne, Licensing Engineer.

On March 26, 2014, the inspectors presented the inspection results to Mr. Ted Bordelon, Acting Director Regulatory Assurance and Performance Improvement, and other members of the PNPS staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

On April 16, 2014, the inspectors presented the quarterly baseline inspection results to Mr. John Dent, Site Vice President, and other members of the PNPS staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Dent Site Vice President

G. Blankenbiller Chemistry Manager

T. Bordelon Performance & Improvement Manager

J. Bracken Assistant Operations Manager

S. Brewer Radiation Protection Manager

D. Brugman Supervisor ALARA/Technical Support

D. Burke Security Manager

R. Byrne Licensing Engineer

B. Chenard Engineering Director

F. Clifford Operations Support Manager

J. Cotter Operations Training Supervisor

J. Cox Radiation Protection Operations Supervisor

B. Deevy System Engineer

M. Gatslick Security Compliance Supervisor

W. Grieves Quality Assurance

J. House Operations Training Supervisor

J. Keene System Engineer

W. Lobo Compliance Engineer

J. Lynch Regulatory Assurance Manager

J. Macdonald Senior Operations Manager

V. Magnetta Senior Operations Instructor

W. Mauro Supervisor Radiation Protection Support

C. McDonald Training Manager

F. McGinnis Licensing Engineer

C. Minott Project Manager

D. Noyes Director of Regulatory & Performance Improvement

J. Ohrenberger Senior Maintenance Manager

J. Priest Emergency Preparedness Manager

B. Rancourt Senior Lead Engineer, Design Engineering

K. Sejkora Senior Chemist

D. Sitkowski Design Engineer

M. Thornhill Radiation Protection Supervisor

G. Vazquez Quality Assurance Supervisor

S. Verrochi General Manager Plant Operations

T. F. White Design & Program Engineering Manager

M. Williams Nuclear Safety Licensing Specialist

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Opened/Closed

05000293/2014002-02 NCV Inadequate Procedure for Determining Operability of the Shutdown Transformer (Section 4OA2)

Opened

05000293/2014-002-01 URI Reporting of Safety System Functional Failure Performance Indicator for Ultimate Heat Sink Inoperability (Section 4OA1)

Closed

05000293/2013-002-00 & LER SRV-3B Safety Relief Valve Inoperable Due to

05000293/2013-002-01 Leakage and Setpoint Drift (Section 4OA3)

05000293/2013-010-00 LER Automatic Group I Primary Containment Isolation Actuation During Plant Start Up Due to High Reactor Water Level (Section 4OA3)