IR 05000354/2012003
| ML12223A393 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 08/10/2012 |
| From: | Arthur Burritt Reactor Projects Branch 3 |
| To: | Joyce T Public Service Enterprise Group |
| Burritt A | |
| References | |
| IR-12-003 | |
| Download: ML12223A393 (56) | |
Text
August 10, 2012
SUBJECT:
HOPE CREEK GENERATING STATION UNIT 1 - NRC INTEGRATED INSPECTION REPORT 05000354/2012003
Dear Mr. Joyce:
On June 30, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Hope Creek Generating Station. The enclosed inspection report documents the inspection results which were discussed on July 19, 2012, with Mr. D. Lewis, Plant Manager 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.
The report documents two findings of very low safety significance (Green). Both of these findings were determined to involve violations of NRC requirements. Additionally, a licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. However, because of their very low safety significance and because they were entered into your corrective action program (CAP), the NRC is treating these findings as non-cited violations (NCVs) consistent with Section 2.3.2 of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Hope Creek Generating Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Resident Inspector at the Hope Creek 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 Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Arthur L. Burritt, Chief Reactor Projects Branch 3 Division of Reactor Projects
Docket No:
50-354 License No:
Enclosure:
Inspection Report 05000354/2012003 w/Attachment: Supplemental Information
REGION I==
Docket No:
50-354
License No:
Report No:
Licensee:
Facility:
Hope Creek Generating Station
Location:
P.O. Box 236
Hancocks Bridge, NJ 08038
Dates:
April 1, 2012 through June 30, 2012
Inspectors:
F. Bower, Senior Resident Inspector A. Patel, Resident Inspector C. Williams, Resident Inspector E. H. Gray, Senior Reactor Inspector T. Burns, Reactor Inspector R. Nimitz, Senior Health Physicist
Approved By:
Arthur L. Burritt, Chief
Reactor Projects Branch 3
Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000354/2012003; 04/01/2012 - 06/30/2012; Hope Creek Generating Station; Maintenance
Effectiveness, Follow-Up of Events and Notices of Enforcement Discretion.
This report covered a three-month period of inspection by resident inspectors and announced inspections performed by a Senior Reactor Inspector, a Senior Health Physicist, and a Reactor Inspector. The inspectors identified two findings of very low safety significance (Green). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). The cross-cutting aspects for the findings are determined using IMC 0310, Components Within Cross-Cutting Areas. Findings for which the SDP does not apply may be Green, or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.
Cornerstone: Barrier Integrity
- Green.
The inspectors identified a non-cited violation (NCV) of very low safety significance of 10 CFR 50, Appendix B, Criterion XI, Test Control, because PSEG conducted unacceptable preconditioning of the reactor building to torus vacuum relief valve.
Specifically, PSEGs surveillance test procedure for these valves cycled the valve (H1GS-1GSPSV-5032) prior to recording the as-found opening setpoint required to meet Technical Specification (TS) Surveillance Requirement (SR) 4.6.4.2.b.2.a. PSEGs immediate corrective actions included revising the surveillance test procedure to record the as-found setpoint before cycling the valve manually. The violation was entered into the corrective action program (CAP) as notification 20554080.
The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers (containment)protect the public from radionuclide releases caused by accidents or events. Specifically, preconditioning of the reactor building to torus vacuum relief opening setpoint could mask its actual as-found condition and result in an inability to verify its operability and potentially make it difficult to determine whether the vacuum breaker would perform its intended safety function during an event. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, and determined the finding was of very low safety significance (Green) because it was not a degradation of the radiological barrier function provided for the control room, auxiliary building, spent fuel pool, or standby gas treatment system, did not represent a degradation of the barrier function of the control room against smoke or toxic atmosphere, did not represent an actual open pathway in the physical integrity of reactor containment and heat removal components, and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The finding had a cross-cutting aspect in the area of problem identification and resolution, corrective action component, because PSEG did not thoroughly evaluate a prior problem such that the problem resolution addressed the extent of condition. Specifically, PSEGs extent of condition for notification 20370021, Potential Preconditioning BJHV-F004, did not go beyond operations procedures and review maintenance procedures for unacceptable preconditioning. Therefore, PSEG did not identify the unacceptable preconditioning of the reactor building to torus vacuum relief valve opening setpoint because the surveillance test was in a maintenance procedure. (P.1(c)) (Section 1R12)
- Green.
The inspectors identified an NCV of very low safety significance of TSs 3.3.1 and 6.8.1 because PSEGs written procedure (HC.IC-CC.SE-0032) was not adequately established and implemented for performing the weekly channel test and calibration of the flow biased APRMs that input into the simulated thermal power upscale RPS trip.
Specifically, the procedure provided inadequate instructions for calculating total reactor recirculation drive flow while in single loop operations (SLO). PSEGs corrective actions included revision of the appropriate procedures and development of a schedule template (including required surveillances) for entry into and return from SLO. The violation was entered into the CAP as notification 20549760.
The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, incorrect calibration of the APRM flow units resulted in the APRM flow biased setpoint being non-conservative and exceeding the associated TS limiting safety system setpoint (LSSS) allowable value for a period of time that was considered a condition prohibited by TS. The inspectors performed a Phase I screening of the finding using IMC 0609, Attachment 0609.04, Table 4a,
Mitigating Systems cornerstone and determined the issue was of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not result in an actual loss of safety function, and was not potentially risk significant for external events. The finding had a cross-cutting aspect in the area of human performance, resources component, because PSEG did not ensure that a TS-required RPS calibration procedure was complete, accurate, and adequate to assure nuclear safety. Specifically, the formula provided in the APRM flow unit summer procedure that calculated the drive flow was incorrect. The formula provided in the procedure was for dual loop operation, not for SLO. (H.2(c)) (Section 4OA3.2)
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. This violation and corrective action tracking number are listed in Section 4OA7 of this report.
REPORT DETAILS
Summary of Plant Status
The Hope Creek Generating Station began the inspection period at approximately 98 percent of rated thermal power (RTP) in end-of-cycle coastdown where it generally remained until the unit was manually shutdown on April 13, 2012, to start Hope Creeks planned 17th refueling outage (H1R17). On May 7, 2012, the reactor mode switch was placed in start-up, criticality was reached on May 8, 2012, and the unit was synchronized to the grid on May 9, 2012. On May 12, 2012, the unit was returned to full power and remained at or near for the duration of the inspection period except for brief periods to support planned testing and rod pattern adjustments.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
.1 Summer Readiness of Offsite and Alternate Alternating Current (AC) Power Systems
a. Inspection Scope
The inspectors performed a review of plant features and procedures for the operation and continued availability of the offsite and alternate AC power system to evaluate readiness of the systems prior to seasonal high grid loading. The inspectors reviewed PSEGs procedures affecting these areas and the communications protocols between the transmission system operator and PSEG. This review focused on changes to the established program and material condition of offsite alternate AC power equipment.
When required, the inspectors assessed whether PSEG established and implemented appropriate procedures and protocols to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system. The inspectors evaluated the material condition of the associated equipment by interviewing responsible PSEG personnel, reviewing switchyard summer readiness letter, and walking down portions of the offsite and alternate AC power systems including the 500 kilovolt and 13.8 kilovolt switchyards. Documents reviewed for each section of this inspection report are listed in the Attachment.
.2 Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
The inspectors performed a review of PSEGs readiness for the onset of seasonal high temperatures. The review focused on the emergency diesel generators (EDGs),circulating water, and service water (SW). The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and TSs to determine what temperatures or other seasonal weather could challenge these systems and to ensure PSEG personnel had adequately prepared for these challenges. The inspectors reviewed station procedures, including PSEGs seasonal weather preparation procedure and applicable operating procedures. The inspectors performed walkdowns of the selected systems to verify that no unidentified issues existed that could challenge the operability of the systems during hot weather conditions.
b. Findings
No findings were identified.
==1R04 Equipment Alignment
Partial System Walkdowns (71111.04Q - 4 samples)
a. Inspection Scope
==
The inspectors performed partial walkdowns of the following systems:
A and C EDGs while B EDG out-of-service on April 17, 2012
B residual heat removal (RHR) shutdown cooling while A RHR shutdown cooling out-of-service on April 27, 2012
D SW pump while B SW out-of-service on May 15, 2012
Reactor core isolation cooling (RCIC) while high pressure coolant injection (HPCI)out-of-service on June 5, 2012
The inspectors selected these systems based on their risk-significance for the current plant configuration or following realignment. The inspectors reviewed applicable procedures, system diagrams, the UFSAR, TSs, work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable.
b. Findings
No findings were identified.
==1R05 Fire Protection
Resident Inspector Quarterly Walkdowns (71111.05Q - 5 samples)
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.
FRH-II-413, HPCI pump & turbine room
FRH-II-433, A & C safety auxiliaries cooling system (SACS) rooms
FRH-II-432, B & D SACS rooms
FRH-II-423, A RHR heat exchanger room
FRH-II-442, Containment instrument gas compressor rooms, filtration recirculation and ventilation system (FRVS) unit areas, and steam vent and equipment area
b. Findings
No findings were identified.
1R08 Inservice Inspection (ISI)
a. Inspection Scope
The purpose of this inspection was to assess the effectiveness of PSEGs ISI activities for monitoring degradation of reactor pressure vessel (RPV) internals, reactor coolant system boundary, risk-significant piping system boundaries, and the containment boundary. The inspectors assessed the ISI activities using requirements and acceptance criteria for component examination specified in the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI, and applicable NRC regulatory requirements.
The inspectors selected a sample of nondestructive examination (NDE) activities and reviewed the inspection reports developed from performance of those examinations to verify the test activities comply with the requirements of ASME Section XI and applicable regulatory requirements. The sample selection was based on the inspection procedure objectives and risk priority of those components and systems where degradation could result in a significant increase in risk of core damage in the event of loss of structural integrity or pressure retaining capability.
The inspectors verified by documentation review that test procedures and examiner qualifications were current and in accordance with the ASME Code requirements.
Also, the inspectors reviewed examiner qualifications for use of the performance demonstration initiative manual ultrasonic test (UT) procedures. The inspectors selected a sample of notifications and corrective actions for review of PSEGs effectiveness in the identification and resolution of relevant indications discovered during ISI activities. The inspectors review of selected samples of nondestructive testing included the following:
Manual UT examination of carbon steel pipe to elbow butt weld in the core spray (CS)system using UT procedure GEH-PDI-UT-1, Version 8. The inspectors verified the examination was performed in accordance with ASME Section XI and 100 percent weld coverage was achieved. The inspectors confirmed the examination was performed with Work Order 50137098 and the results documented in Report No. UT-12-025. No recordable indications were identified.
Magnetic particle test (MT) of integral attached lug, item C-C/C3.20, welded to carbon steel pipe in the HPCI system, component 1-FD-20HBB-9LG (1-8) using MT procedure OU-AA-335-003, Revision 2. The inspectors confirmed the examination results were documented in Report No. MT-12-003. No recordable indications were identified.
Liquid Penetrant test (PT) of B recirculation loop outside radius at one inch instrument line to nozzle weld of component 1-BB-1CCA-225-1 using PT procedure OU-AA-335-002, Revision 2. The inspectors confirmed the examination results were documented in Report No.12-006. No indications were identified.
Radiographic test (RT) examination of carbon steel grove butt weld, item HC-1-P-BD-203-13 in the RCIC piping system using RT procedure OU-AA-335-005, Revision 1. No recordable indications were identified.
The inspectors reviewed visual test (VT)-1 and VT-3 examination using NDE-VT-003, Revision 9, and VT-005, Revision 8, of the RPV internals consisting of jet pump main wedges, auxiliary wedges, steam dryer, shroud baffle support plate, and additional structural members. Various welds of in-vessel CS piping were also visually inspected.
Indications noted in the weld of the shroud support plate to the inside diameter of the RPV were identified and recorded for characterization and disposition. The indications were documented in notification 20556380.
The inspectors selected two ASME Section XI repair/replacement plans for review where welding was performed. The review was performed to confirm that appropriately qualified weld procedures and welders were assigned this work and that essential welding parameters were indicated as hold points on the weld traveler. The inspectors noted these hold point attributes were examined by inspection personnel and documented on the weld traveler. The inspectors reviewed base materials and weld filler metal specifications to verify they were in accordance with ASME Code requirements. Also, the inspectors reviewed documentation that the completed weld examinations were performed in accordance with the ASME Section XI code requirements. The two ASME Section XI repair/replacement activities reviewed were:
Work Order 60088924: This work order governs replacement of two valves and associated piping in the Main Steam system (system AB). This replacement consisted of performing an ASME Section XI replacement of valves 1-AB-V063 and V064. The inspectors verified replacement activity was governed by ASME Section XI, Safety Class 1 and Seismic Class 1. The inspectors verified the welding was performed by qualified welders using qualified welding procedures and weld filler materials meeting the requirements of ASME Section XI. The inspectors verified final acceptance of the replacement welds was based on satisfactory liquid PT, pressure test, and visual surface examination. No recordable indications were identified and no leakage was noted.
Work Order 60101260: This work order governs the installation of a portion of RCIC piping ASME Class 2 and Seismic Class 1. The inspectors reviewed the four welds that were made to replace the existing portion of failed carbon steel suction piping. The inspectors verified the replacement welding was governed by the requirements of ASME Section XI with final acceptance as specified in ASME Section III. The inspectors confirmed the final acceptance of these replacement welds was based on satisfactory nondestructive testing (PT) and system pressure test (VT-2). The inspectors verified that appropriate verification of weld hold points was established on the replacement work instruction. No recordable indications were identified and no leakage was noted.
The inspectors performed a walkdown to view portions of the primary containment and additional structural members attached to the liner for assessment of the condition of the protective coating. The inspectors performed this visual assessment of limited locations at the equipment hatch entrance elevation. The assessment included the extent of any peeling, blistering, coating loss or other damage or degradation as a result of corrosion, foreign material impact, or lack of maintenance. Also, the inspectors evaluated coating integrity at accessible locations where the primary containment liner intersects the containment floor. The evaluation was consistent with the requirements provided in ASME Section XI.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program
.1 Quarterly Review of Licensed Operator Performance in the Main Control Room
a. Inspection Scope
On April 13, 2012, the inspectors observed the planned power reduction for Hope Creek refueling outage 17 and subsequent operational placement of the mode switch from run to shutdown. During these control room observations, the inspectors assessed the adequacy of: procedure use, crew communications, human performance tool use, supervisory oversight, and coordination of activities between work groups to verify that PSEGs established expectations and standards were met.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, and component (SSC) performance and reliability. The inspectors reviewed CAP documents, maintenance work orders, and maintenance rule program 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.
Reactor building to torus vacuum relief valves (Notification 20554080)
b. Findings
Introduction.
The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XI, Test Control, because PSEG conducted unacceptable preconditioning of the reactor building to torus vacuum relief valve. Specifically, PSEGs surveillance test procedure for these valves cycled the valve (H1GS-1GSPSV-5032) prior to recording the as-found opening setpoint required to meet TS SR 4.6.4.2.b.2.a.
Description.
The function of the reactor building to torus vacuum relief valves is to relieve vacuum when primary containment depressurizes below reactor building pressure. PSEGs surveillance test HC.MD-ST.GS-0002, Reactor Building to Torus Vacuum Relief Valve 18 Month Testing, Revision 8, is used to satisfy TS SR 4.6.4.2.b.2.a. This surveillance requirement verifies that each vacuum relief valve opens at a setpoint of less than or equal to 0.25 psid.
On April 10, during a surveillance test review, the inspectors identified what they believed to be unacceptable preconditioning during performance of surveillance test procedure HC.MD-ST.GS-0002. Specifically, procedure section 5.2, Vacuum Relief Valve Visual Inspection, step 5.2.3, states, Check pallet operation for interference or binding of hinge by manually operating pallet several times. While the next section, section 5.3, Vacuum Relief Valve As-Found Setpoint Checks, step 5.3.1, VERIFY Vacuum Relief Valve As-Found Setpoint, records the as-found opening setpoint of the relief valve and is used to verify TS SR 4.6.4.2.b.2.a.
The inspectors reviewed regulatory positions and guidance regarding preconditioning, including NRC IMC Part 9900: Technical Guidance, Maintenance-Preconditioning of Structures, Systems, and Components before Determining Operability, and PSEGs procedure PP-AA-3001, Position Paper on Preconditioning. IMC Part 9900 and PP-AA-3001 states, in part, that unacceptable preconditioning is defined as the alteration, variation, manipulation, or adjustment of the physical condition of a SSC before or during a TS surveillance that will alter one or more SSCs operational parameters, which results in acceptable test results. Such changes could mask the actual as-found condition of the SSC and possibly result in an inability to verify the operability of the SSC. In addition, unacceptable preconditioning could make it difficult to determine whether the SSC would perform its intended function during an event in which the SSC might be needed.
Based on the review of the technical guidance, the inspectors determined that, as written and implemented, HC.MD-ST.GS-0002, which included steps that obtained as-found data only after manually cycling the valve several times, was unacceptable preconditioning of the valves it tested. Specifically, manually cycling the valve several times before the actual test altered the physical condition of the valve and could have masked an unacceptable condition.
PSEG entered the issue into their CAP (Notification 20554080) and evaluated the inspectors concerns. PSEG verified that the procedure contained unacceptable preconditioning steps and revised the testing sequence.
The inspectors reviewed PSEG procedure LS-AA-125, Corrective Action Program, which defines extent of condition as the extent to which the identified condition has the potential to impact other plant processes, equipment, or human performance in the same manner as identified in the condition report. The inspectors found that in November 2009 (Notification 20370021/70085313 operation 110), in response to a potential unacceptable preconditioning of the HPCI condensate storage suction valve, PSEGs extent of condition reviewed operations department procedures to determine unacceptable preconditioning. Specifically, notification 20370021/70085313 operation 110 stated that PSEG performed the expanded extent of condition review for all quarterly inservice test (IST) valve surveillances and additionally performed a review of all cold shutdown IST valve surveillances and all quarterly pump IST surveillances, and a sample population of over 50 percent of the operations department surveillance test procedures. However, this extent of condition review narrowly focused on IST procedures and operations procedures used to test TS SR. Therefore, the extent of condition review did not identify the impact of unacceptable preconditioning in other plant processes such as maintenance procedures that are used to test TS SR, and specifically test procedure HC.MD-ST.GS-0002 that tests the reactor building to torus vacuum relief valve opening setpoint in accordance with TS SR 4.6.4.2.b.2.a.
Analysis.
The inspectors determined that PSEGs performance of unacceptable preconditioning prior to recording the as-found setpoint of the reactor building to torus vacuum relief valve opening setpoint was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. Specifically, preconditioning of the reactor building to torus vacuum relief valves opening setpoint could mask its actual as-found condition and result in an inability to verify its operability and potentially make it difficult to determine whether the vacuum breaker would perform its intended safety function during an event. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, and determined the finding was of very low safety significance (Green) because all of the containment barrier questions in Table 4a were answered no. Specifically, the finding was not a degradation of the radiological barrier function provided for the control room, or auxiliary building, or spent fuel pool, or standby gas treatment system, did not represent a degradation of the barrier function of the control room against smoke or toxic atmosphere, did not represent an actual open pathway in the physical integrity of reactor containment and heat removal components, and did not involve an actual reduction in function of hydrogen igniters in the reactor containment.
The finding had a cross-cutting aspect in the area of problem identification and resolution, corrective action component, because PSEG did not thoroughly evaluate a prior problem such that the problem resolution addressed the extent of condition.
Specifically, PSEGs extent of condition for notification 20370021, Potential Preconditioning BJHV-F004, did not go beyond operations procedures and review maintenance procedures for unacceptable preconditioning. Therefore, PSEG did not identify the unacceptable preconditioning of the reactor building to torus vacuum relief valves opening setpoint because the surveillance test was in a maintenance procedure.
(P.1(c))
Enforcement.
10 CFR 50, Appendix B, Criterion XI, Test Control, requires, in part, that a test program shall be established to assure that all testing required to demonstrate that SSCs will perform satisfactorily in service, is identified and performed in accordance with written test procedures, and incorporate the requirements and acceptable limits contained in applicable design documents. Contrary to the above, on April 10, 2012, PSEG did not establish a test program that assured that all testing required to demonstrate that the reactor building to torus vacuum relief valves will perform satisfactorily in service was identified and performed in accordance with written test procedures, and incorporated the requirements and acceptable limits contained in applicable design documents. Specifically, due to an inadequate test sequence that resulted in an unacceptable preconditioning of the reactor building to torus vacuum relief valves, the testing performed in accordance with PSEGs written test procedures did not determine the as-found condition of the valves. This issue was entered into the CAP as notification 20554080, and PSEGs immediate corrective actions included revising the surveillance test procedure to record the as-found setpoint before cycling the valve manually. Because the violation was of very low safety significance (Green) and has been entered into the CAP, this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000354/2012003-01, Preconditioning of the Reactor Building to Torus Vacuum Relief Valves)
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.
A torus spray out-of-service for the torus spray valve failure to close on April 4, 2012 (Order 60102294)
A RPS voltage regulator failure resulting in a half-scram on April 6, 2012 (Notification 20553616)
Risk assessment associated with the emergent recovery of GE 14i fuel bundle parts including potential for damage of adjacent spent fuel bundles from foreign material, potential for overexposure during recovery activities and the potential effects on the spent fuel pool on April 22, 2012 (Order 60097577-0550)
B & D EDGs out-of-service for preventive maintenance (Orders 80102248 and 60097819)
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:
A control room ventilation degraded temperature controller (Order 70135888)
HPCI with unsecured restraint chain falls (Order 80106266)
Technical evaluation of the dose impacts of loaded isotope rod cask basket and dropped rod segment during H1R17 outage (Order 80105996-0040)
J safety relief valve with failed tailpipe temperature indicator (Notification 20559654)
Secondary containment with FRVS controller setpoint low (Notifications 20559654 and 20563290)
Rising trend in drywell floor drain flow (Notification 20559476)
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
.1 Temporary Modifications
a. Inspection Scope
The inspectors reviewed the temporary configuration change package (TCCP) listed below to determine whether the temporary modification affected the safety functions of systems that are important to safety. The inspectors reviewed 10 CFR 50.59 documentation and post-modification testing results of the modification to verify that the temporary modification did not degrade the design bases, licensing bases, and performance capability of the affected systems.
TCCP 4HT12-007 - East Fuel Prep Machine Grapple Operate Zone Setpoint Change (NUCP Order 80106352)
b. Findings
No findings were identified.
Permanent Modifications
a. Inspection Scope
The inspectors evaluated the below listed modifications to determine whether these permanent modifications affected the safety functions of systems that are important to safety. The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modifications. As applicable, the inspectors also reviewed revisions to the drawings, interviewed engineering personnel, and performed a walkdown of the completed modification to ensure the modifications were installed as designed.
Engineering change package 80102248, B Emergency Diesel Generator Governor Control System Replacement. The inspectors reviewed a selected sample of the modification documents associated with the replacement of B EDG governor control system with an upgraded digital model and with the installation of a new magnetic speed pickup device.
Engineering change package 80103199, Removal of N2 Pressure and Floating Roofs from Safety and Turbine Auxiliary Cooling System (STACS) Accumulators. The inspectors reviewed a selected sample of the modification documents associated with the removal of the STACS accumulator floating roofs, removal of STACS 2522E/F isolation valves, and removal of the nitrogen supply to the STACS system.
Design change package 80106279, Revision 1, Installation of Alignment Tools on HPCI Main Pump, Booster Pump and Gearbox. The inspectors reviewed a selected sample of the modification documents associated with the design change to permanently install new alignment devices, including technical evaluations of piping stress due to displacement of the HPCI skid mounted equipment in relation to the attached piping.
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.
HPCI after electronic governor remote replacement on March 17, 2012 (Order 60101966)
BD411 1E 125 volt battery after bank replacement on April 22, 2012 (Order 50136300)
B standby liquid control pump after squib valve replacement on April 30, 2012 (Order 50135996)
HPCI after HPCI turbine overhaul on May 7, 2012 (Orders 30200513 and 30097435)
B SW pump after pump packing replacement on May 17, 2012 (Order 60101423)
New A RHR heat exchanger supply side vent valve (1-BC-V631) after installation from May 6 to May 31, 2012 (Order 60099665-0420)
B EDG room recirculation fan (1B-V-412) after associated breaker replacement from June 11 - 20, 2012 (Order 60103000)
B primary containment instrument gas compressor after preventive maintenance from June 25 - 26 2012 (Order 30203239)
b. Findings
No findings were identified.
1R20 Refueling and Other Outage Activities
a. Inspection Scope
The inspectors reviewed the stations work schedule and outage risk plan for Hope Creeks 17th refueling outage (H1R17), which was conducted April 13 through May 9, 2012. The inspectors reviewed PSEGs development and implementation of outage plans and schedules to verify that risk, industry experience, previous site-specific problems, and defense-in-depth were considered. During the outage, the inspectors observed portions of the shutdown and cooldown processes and monitored controls associated with the following outage activities:
Configuration management, including maintenance of defense-in-depth, commensurate with the outage plan for the key safety functions and compliance with the applicable TSs when taking equipment out of service
Implementation of clearance activities and confirmation that tags were properly hung and that equipment was appropriately configured to safely support the associated work or testing
Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication and instrument error accounting
Status and configuration of electrical systems and switchyard activities to ensure that TSs were met
Monitoring of decay heat removal operations
Impact of outage work on the ability of the operators to operate the spent fuel pool cooling system
Reactor water inventory controls, including flow paths, configurations, alternative means for inventory additions, and controls to prevent inventory loss
Activities that could affect reactivity
Maintenance of secondary containment as required by TSs
Refueling activities, including fuel handling and fuel receipt inspections Fatigue management
Identification and resolution of problems related to refueling outage activities
PSEG reported the use of EGM 11-003 in licensee event report (LER) 05000354/2012-003-00. This LER and PSEGs use of EGM 11-003 will be reviewed and dispositioned in a subsequent inspection report.
Additionally, the H1R17 refueling outage included activities associated with PSEGs pilot project to produce the isotope Cobalt-60 in the reactor for commercial and medical purposes. Therefore, the inspectors reviewed a selected sample of the applicable procedures and work orders and observed a sample of the associated fuel handling activities in the spent fuel pool to ensure PSEG and PSEGs contractors were performing these first time evolutions safely and in accordance with their procedures.
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:
HC.OP-ST.BC-0004, A low pressure coolant injection time response test on April 3, 2012
HC.IC-FT.SE-0034, Nuclear Instrumentation System, Channel A Rod Block Monitor, Single Loop Flow Operation; from June 2 - June 20, 2012
HC.OP-ST.BC-0009, B RHR heat exchanger flow measurement test on April 11, 2012
HC.OP-LR.AB-0001, 2, 3 & 4, Containment Isolation Valve Type C Leak Rate Test - CIVs 1ABHV-F022A, B, C, & D and 1ABHV-F028A, B, C, & D - Penetration P1A, B, C, & D: A, B, C, & D Main Steam Line; from April 18 - 24, 2012
HC.OP-ST.KJ-0006, B EDG simulated loss of offsite power and loss of coolant accident test on April 26, 2012
HC.OP-IS.JE-0003, B EDG fuel oil transfer pump inservice test on May 16, 2012
NWS-T-25, NWS test procedure for Public Service Electric & Gas - Hope Creek Nuclear Station Target Rock 7567F 2 stage main steam safety relief valves; from April 23 to May 7, 2012
b. Findings
No findings were identified.
RADIATION SAFETY
Cornerstone: Radiation Safety - Public and Occupational
2RS1 Radiological Hazard Assessment and Exposure Controls
a. Inspection Scope
The inspectors reviewed selected activities and associated documentation in the areas below. The evaluation of PSEGs performance was against criteria contained in 10 CFR Part 20, applicable TSs, and applicable station procedures.
Inspection Planning
The inspectors reviewed performance indicators for the Occupational Exposure Cornerstone. The inspectors also reviewed the results of recent radiation protection program audits and assessments, as available, and any reports of operational occurrences related to occupational radiation safety since the last inspection.
Radiological Hazard Assessment
The inspectors discussed plant operations during the outage to identify any significant new radiological hazards for onsite workers or members of the public. The inspectors assessed the potential impact of the changes and monitoring, as appropriate, to detect and quantify the radiological hazards.
The inspectors toured and conducted walkdowns of radiological controlled areas (RCAs)and reviewed radiological surveys from selected plant areas (e.g., refueling floor, reactor cavity, reactor building, turbine buildings, condenser areas, drywell, and suppression pool) to verify that the thoroughness and frequency of the surveys were appropriate for the given radiological hazard. The inspectors also evaluated material conditions and potential radiological conditions. The inspectors made independent radiation measurements to verify radiological conditions.
The inspectors selected various radiological risk-significant work activities (e.g., reactor cavity work, in-vessel work activities, drywell work activities, condenser work, reactor cavity platform work, turbine work, and suppression pool work) that involved exposure to radiation to verify that appropriate pre-work surveys were performed to identify and quantify the radiological hazards and to establish adequate protective measures. The evaluation included, as applicable: identification of discrete particles; the presence of alpha emitters; the potential for airborne radioactive materials; potential changes in radiological conditions; and non-uniform exposures of the body.
The inspectors selectively reviewed and discussed air sample survey records associated with various radiological work activities to verify that samples were representative of breathing zone and collected and counted in accordance with procedures.
The inspectors reviewed ongoing radiological work activities to evaluate methods used to update workers on changes in radiological conditions.
Instructions to Workers
The inspectors toured the RCAs, including H1R17 refueling outage work areas, and reviewed labeling of containers of radioactive materials to verify labeling was consistent with requirements and was informative to workers.
The inspectors reviewed various radiation work permits (RWPs), as low as reasonably achievable (ALARA) reviews, ALARA work-in-progress reviews, and radiological surveys used to access high radiation areas (HRAs) to identify work control instructions or control barriers specified, use of stay times or permissible dose, and appropriate electronic personal dosimeter (EPD) alarm setpoints were in conformance with survey indications. The inspectors evaluated changes to EPD setpoints for specified conditions and updating of RWPs. The inspectors reviewed ongoing remote monitoring via teledosimetry.
Contamination and Radioactive Material Control
The inspectors observed locations where PSEG monitors potentially contaminated material leaving the RCA and inspected the methods used for control, survey, and release from these areas. The inspectors observed the performance of personnel surveying and the releasing of material for unrestricted use to verify that it was performed in accordance with plant procedures and the procedures were sufficient to control the spread of contamination and prevent unintended release of radioactive materials from the site. The inspectors selectively evaluated the radiation monitoring instrumentation sensitivity for the type(s) of radiation present.
The inspectors reviewed PSEGs criteria for the survey and release of potentially contaminated material. The inspectors verified that there was guidance on how to respond to an alarm that indicates the presence of radioactive material.
The inspectors reviewed PSEGs procedures and records to verify that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters including application of alarm setpoints based on the instruments typical sensitivity. The inspectors also discussed alarm setpoints and typical detection capabilities with cognizant PSEG personnel.
Radiological Hazards Control and Work Coverage
The inspectors toured the facility and reviewed ongoing work and evaluated ambient radiological conditions (e.g., radiation levels or potential radiation levels). The inspectors verified the existing conditions were consistent with posted surveys, RWPs, and worker briefings. Areas toured by the inspectors included the drywell, reactor building, refueling floor, and turbine condenser areas.
The inspectors observed ongoing work activities and verified the adequacy of radiological controls, such as required surveys (including system breach radiation, contamination and airborne surveys, and surveys of radiation dose rate gradients),radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls. The inspectors selectively evaluated PSEGs means of using EPDs in high noise areas as HRA monitoring devices (e.g., use of teledosimetry).
The inspectors verified that thermoluminescent dosimeters were placed on the individuals body consistent with the method that PSEG is employing to monitor dose from external radiation sources. The inspectors conducted direct observations of selected work to verify that the dosimeters were placed in the location of highest expected dose. The inspectors reviewed for HRAs with significant dose rate gradients the use of dosimetry to effectively monitor exposure to personnel. The inspectors evaluated implementation of external effective dose equivalent measurement (EDEX).
The inspectors selectively reviewed RWPs for work within areas with the potential for individual worker internal exposures. The inspectors evaluated airborne radioactive controls and monitoring, including potentials for significant airborne levels. The inspectors directly observed welding and grinding activities, including use of local ventilation system and respiratory protection equipment, to minimize airborne radioactive exposure. The inspectors reviewed contamination system breach survey results. The inspectors reviewed control rod drive replacement activities.
The inspectors observed ongoing work activities within flooded pools (e.g., reactor cavity) and selectively reviewed physical and programmatic controls for highly activated or contaminated materials (non-fuel) stored within storage pools. The inspectors evaluated controls to preclude inadvertent removal of these materials from the pool.
The inspectors conducted selective inspection of postings and physical controls for HRAs and very high radiation areas (VHRAs) to verify conformance with the Occupational performance indicator. The inspectors evaluated down-posting of areas from HRAs.
Risk-Significant HRA and VHRA Controls
The inspectors selectively discussed with the Radiation Protection Manager, supervisors, and technicians the controls and procedures for high-risk HRAs and VHRAs and any procedural changes since the last inspection. The inspectors discussed methods employed by PSEG to provide control of VHRA access including potential reduction in the effectiveness and level of worker protection (e.g., use of lock boxes).
The inspectors discussed, with health physics supervisors, controls for special areas that had the potential to become VHRAs during certain plant operations including controls to ensure that an individual was not able to gain unauthorized access to the VHRA.
The inspectors conducted a locked HRA key inventory and discussed locked HRA key control and issuance with health physics staff.
Radiation Worker Performance
The inspectors toured RCAs and observed radiation worker performance with respect to stated radiation protection work requirements to determine if performance reflected the level of radiological hazards present. The inspectors interviewed numerous workers conducting work activities in the RCA to determine if workers were aware of the radiological conditions in their workplace and the RWP controls/limits in place.
The inspectors selectively reviewed radiological problem reports since the last inspection to identify human performance errors and determine if there were any observable patterns. The inspectors discussed corrective actions for identified concerns with PSEG personnel.
Radiation Protection Technician Proficiency
The inspectors toured RCAs and observed the performance of radiation protection technicians with respect to radiation protection work requirements to determine if technicians were aware of the radiological conditions in their workplace and the RWP controls/limits and it their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.
The inspectors selectively reviewed outage radiological problem reports to identify those that indicate the cause of the events due to radiation protection technician error and to evaluate corrective action approach taken by PSEG to resolve the reported problems.
Problem Identification and Resolution
The inspectors determined if problems associated with radiation monitoring and exposure control were being identified by PSEG at an appropriate threshold and were properly addressed for resolution in their CAP. The inspectors discussed corrective actions for identified concerns.
b. Findings
No findings were identified.
2RS2 Occupational ALARA Planning and Controls
a. Inspection Scope
Inspection Planning
The inspectors reviewed pertinent information regarding plant collective exposure history, current exposure trends, and ongoing or planned activities in order to assess current performance and exposure challenges. The inspectors reviewed the plants three-year rolling average collective exposure.
The inspectors evaluated and determined the site-specific trends in collective exposures using various methods such as plant historical data, including outage work activity dose, evaluation of ALARA data, and source term data.
The inspectors reviewed site-specific procedures associated with maintaining occupational exposures ALARA, including the processes used to estimate and track exposures from specific work activities.
Radiological Work Planning
The inspectors obtained from PSEG a list of work activities ranked by actual or estimated exposure that were planned for H1R17 refueling outage and selected work activities of the highest exposure significance. These included reactor disassembly, reactor cavity decontamination, scaffolding, in-service inspection, control rod drive work, and valve work.
The inspectors reviewed ALARA work activity plans and evaluations, exposure estimates, and exposure mitigation requirements. The inspectors determined if PSEG reasonably grouped the radiological work into work activities based on historical precedence, industry norms, and/or special circumstances.
The inspectors determined if PSEGs planning identified appropriate dose mitigation features, considered commensurate with the risk of the work activity, alternate mitigation features, and defined reasonable dose goals. As applicable, the inspectors evaluated verified use of respiratory protective devices from an ALARA perspective.
The inspectors determined if work planning considered the use of remote technologies (such as teledosimetry, remote visual monitoring, and robotics) as a means to reduce dose and the use of dose reduction insights from industry operating experience and plant-specific lessons learned. The inspectors verified the integration of ALARA requirements into work procedure and RWP documents.
The inspectors selectively compared accrued results achieved (dose rate reductions, person-rem used) with the intended dose established in PSEGs ALARA planning for these work activities including person-hour estimates. The inspectors determined the reasons for inconsistencies between intended and actual work activity doses, as necessary. During the H1R17 refueling outage, the inspectors selectively evaluated reasons for increased doses for work as compared to original estimates. As part of this review, the inspectors reviewed ongoing ALARA work-in-progress reviews.
Verification of Dose Estimates and Exposure Tracking Systems
The inspectors selected various ALARA work packages and reviewed the assumptions and bases for the collective exposure estimate for reasonable accuracy. The inspectors reviewed applicable procedures to determine the methodology for estimating exposures for specific work activities and the intended dose outcome. The inspectors also reviewed approvals by the station ALARA committee as applicable.
The inspectors verified, for the selected work activities, that PSEG established measures to track, trend, and if necessary to reduce, occupational doses for ongoing work activities including criteria to prompt additional reviews and/or controls.
During the H1R17 refueling outage, the inspectors selectively evaluated the methods used to adjust exposure estimates, replanning work due to emergent work, and changes in work scope when identified, as well as variations in expected radiation dose rates.
Source Term Reduction and Control
The inspectors used PSEG records to determine the historical trends and current status of significant tracked plant source term known to contribute to elevated facility aggregate exposure. The inspectors discussed the Chemistry Plan and long term plans for source term reduction (e.g., Cobalt reduction). The inspectors discussed contingency plans for potential changes in the source term as the result of changes in plant fuel performance issues or changes in plant primary chemistry. The inspectors discussed source term reduction efforts including system flushing and use of additional demineralization and filtration systems.
Radiation Worker and Radiation Protection Technician Performance
The inspectors observed both radiation workers and radiation protection technicians performance during work activities being performed in radiation areas, HRAs, and airborne radioactivity areas. The inspectors determined if workers demonstrated the ALARA philosophy in practice and whether there were any procedure compliance issues. The inspectors observed performance to determine whether the training and skill level were sufficient with respect to the radiological hazards and the work involved.
Problem Identification and Resolution
The inspectors determined if problems associated with ALARA planning and controls were being identified by PSEG at an appropriate threshold and were properly addressed for resolution in their CAP. The inspectors discussed corrective actions for identified ALARA concerns with the health physics staff.
b. Findings
No findings were identified.
2RS3 In-Plant Airborne Radioactivity Control and Mitigation
a. Inspection Scope
Inspection Planning
The inspectors selectively reviewed the plant UFSAR to identify areas of the plant designed as potential airborne radiation areas and any associated ventilation systems or airborne monitoring instrumentation. The inspectors also reviewed the UFSAR for overview of the respiratory protection program and a description of the types of devices used.
The inspectors reviewed procedures for maintenance, inspection, and use of respiratory protection equipment including procedures for air quality maintenance. The inspectors also reviewed and directly observed the use of respiratory protection equipment during ongoing work activities.
The inspectors reviewed the reported performance indicators to identify any related to unintended dose resulting from personnel intakes of radioactive materials.
Engineering Controls
The inspectors evaluated the use of selected ventilation systems as to control airborne radioactivity. The inspectors discussed controls and procedural guidance for use of installed plant systems to verify system use, to the extent practicable, during high-risk activities. The inspectors discussed verification of plant ventilation systems during reactor cavity work.
The inspectors reviewed selected installed ventilation systems used to mitigate the potential for airborne radioactivity. The inspectors discussed use of installed systems during work activities with health physics staff.
The inspectors selected various temporary ventilation system setups (high efficiency particulate air filters) to support work in contaminated areas. The inspectors discussed the use of these systems with regard to procedural guidance and ALARA with health physics staff.
The inspectors selected various installed systems to monitor and warn of changing airborne concentrations in the plant. The inspectors evaluated the alarms and setpoints used to prompt PSEG/worker action to ensure that doses are maintained within the limits of 10 CFR Part 20 and ALARA.
The inspectors evaluated PSEGs use of decision criteria for evaluating levels of hard-to-detect airborne radionuclides.
Use of Respiratory Protection Devices
The inspectors evaluated PSEGs use of respiratory protective devices to maintain occupational doses ALARA.
The inspectors evaluated the use of certified respiratory protection devices to limit the intake of radioactive materials and evaluated that the devices were used consistent with their National Institute for Occupational Safety and Health/Mine Safety and Health Administration certification or conditions of NRC approval.
The inspectors reviewed air quality test records for use of air supplied respiratory protection devices.
Problem Identification and Resolution
The inspectors reviewed and discussed problems associated with the control and mitigation of in-plant airborne radioactivity to evaluate PSEGs identification and resolution in their CAP.
b. Findings
No findings were identified.
2RS4 Occupational Dose Assessment
a. Inspection Scope
Inspection Planning
The inspectors reviewed PSEG procedures associated with dosimetry operations, including issuance/use of external dosimetry (routine, multi-badging, extremity, neutron, etc.), assessment of internal dose (operation of whole body counter, assignment of dose based on derived air concentration-hours, urinalysis, etc.), and evaluation of and dose assessment for radiological incidents. The inspectors evaluated implementation of dose determination by use of EDEX. The inspectors evaluated procedure guidance for personnel monitoring.
External Dosimetry
The inspectors evaluated the use of personnel dosimeters that require processing, to verify National Voluntary Laboratory Accreditation Program (NVLAP) accreditation. The inspectors determined if PSEG uses a correction factor to address the response of the electronic dosimeter as compared to its NVLAP accredited dosimeter for situations when the electronic dosimeter must be used to assign dose.
Internal Dosimetry
The inspectors selectively evaluated the routine whole body counting program, including use of passive monitoring provided, for detection and measurement of intakes of radioactive materials.
The inspectors evaluated the minimum detectable activity of PSEGs instrumentation used for passive whole body counting to determine if the minimum detectable activity was adequate to determine the potential for internally deposited radionuclides sufficient to prompt additional investigation.
Special Dosimetric Situations
The inspectors reviewed PSEGs methodology for monitoring external dose in situations in which non-uniform fields are expected or large dose gradients could exist. The inspectors selectively reviewed use of multi-badging.
Problem Identification and Resolution
The inspectors selectively reviewed corrective action documents to verify that problems associated with occupational dose assessment were being identified by PSEG at an appropriate threshold and were properly addressed for resolution in their CAP.
b. Findings
No findings were identified.
2RS5 Radiation Monitoring Instrumentation
a. Inspection Scope
Inspection Planning
The inspectors reviewed the plant UFSAR to identify radiation instruments associated with monitoring area radiological conditions including airborne radioactivity, process streams, effluents, materials/articles, and workers.
Walkdowns and Observations
The inspectors selected various portable survey instruments in use for risk-significant radiological work or available for issuance and checked calibration and source check stickers for currency and to assess instrument material condition and operability.
The inspectors walked down portable area radiation monitors and continuous air monitors to determine whether they were appropriately positioned relative to the radiation source(s) or area(s) they were intended to monitor. The inspectors selectively compared monitor response (via local or remote indication) with actual area conditions for consistency. The inspectors evaluated instrumentation in-place on the refueling bridge and work platforms.
The inspectors selected personnel contamination monitors, portal monitors, and small article monitors and verified that the periodic source checks were performed in accordance with PSEG procedures.
Calibration and Testing Program
The inspectors reviewed alarm setpoint data for various personnel and equipment monitors at RCA exits to verify that the alarm setpoint values were reasonable under the circumstances to ensure that licensed material was not released from the site.
Calibration and Check Sources
The inspectors selectively reviewed PSEGs latest 10 CFR Part 61 waste stream report to determine if the calibration sources used were representative of the types and energies of radiation encountered in the plant.
Problem Identification and Resolution
The inspectors selectively reviewed corrective action documents associated with radiation monitoring instrumentation to determine if PSEG identified issues at an appropriate threshold and placed the issues in their CAP for resolution.
2RS6 Radioactive Gaseous and Liquid Effluent Treatment
a. Inspection Scope
The inspectors selectively reviewed aspects of PSEGs gaseous and liquid effluent control program in the below listed areas.
Inspection Planning and In-Office Inspection
The inspectors reviewed the Radiological Effluent Release Reports, issued since the last inspection, to determine if the reports were submitted as required by the Offsite Dose Calculation Manual (ODCM)/TSs. The inspectors reviewed the reports for any anomalous results, unexpected trends, or abnormal releases identified by PSEG for further inspection.
The inspectors reviewed the reports to identify radioactive effluent monitor operability issues reported by PSEG as provided in effluent release reports.
The inspectors also reviewed groundwater remediation reports.
The inspectors reviewed the UFSAR descriptions of the radioactive effluent monitoring systems, treatment systems, and effluent flow paths to verify during inspection walkdowns.
b. Findings
No findings were identified.
2RS7 Radiological Environmental Monitoring Program (REMP)
a. Inspection Scope
Inspection Planning
The inspectors reviewed the annual radiological environmental operating reports, since the last inspection, to verify that the REMP was implemented in accordance with the TS and ODCM. The inspectors reviewed the report for changes to the ODCM with respect to environmental monitoring, commitments in terms of sampling locations, monitoring and measurement frequencies, land use census, inter-laboratory comparison program, and analysis of data.
The inspectors reviewed the ODCM and the UFSAR to identify locations of environmental monitoring stations and to review for information regarding the environmental monitoring program and meteorological monitoring instrumentation.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA2 Problem Identification and Resolution
.1 Routine Review of Problem Identification and Resolution Activities
a. Inspection Scope
As required by Inspection Procedure 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that PSEG entered issues into the 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 regular screening of items entered into the CAP and periodically attended management review committee meetings.
b. Findings
No findings were identified.
.2 Semi-Annual Trend Review
a. Inspection Scope
The inspectors performed a semi-annual review of site issues, as required by Inspection Procedure 71152, Problem Identification and Resolution, to identify trends that might indicate the existence of more significant safety issues. In this review, the inspectors included repetitive or closely-related issues that may have been documented by PSEG outside of the CAP, such as trend reports, performance indicators, major equipment problem lists, system health reports, maintenance rule assessments, and maintenance or CAP backlogs. The inspectors also reviewed PSEGs CAP database for the period from November 2011 to June 2012 to assess the notifications written as well as individual issues identified during the NRCs daily condition report review (Section 4OA2.1). The inspectors reviewed the Hope Creek station performance improvement integrated matrix (PIIM) for the 3rd cycle of 2011, conducted under procedure LS-AA-125-1006, Performance Improvement Integrated Matrix, to verify that PSEG personnel were appropriately evaluating and trending adverse conditions in accordance with applicable procedures.
b. Findings and Observations
No findings were identified.
The inspectors noted that an adverse trend of main steam safety/relief valve as-found setpoint test failures existed. In 2011, PSEG performed a root cause evaluation (Order 70128407) of this chronic trend of setpoint drift beyond the tolerances allowed by the TS and the ASME Code. This problem recurred in 2012, when 6 of the 14 safety/relief valves that were removed during the refueling outage, failed testing due to setpoint drift.
PSEG evaluated this problem in a work group evaluation (Order 70138789).
The inspectors also reviewed the results of the 2011 3rd cycle Hope Creek Station PIIM meeting and noted that PSEG identified the following fundamentals in variance: CAP oversight (Order 70111712); accountability for high standards (Order 70111714);housekeeping (Order 70125481); security (Order 70133952); leak management (Order 70134165); and, negative trend in industrial safety (Order 70136751). These efforts were identified for focused station effort to enhance future performance. Based on the overall review of the selected sample, the inspectors concluded that PSEG was appropriately identifying and entering issues into the CAP, adequately evaluating the identified issues, and acceptably identifying adverse trends before they became more safety significant problems.
.3 Annual Sample:
Instrument Inaccuracies Unaccounted for in RHR Suppression Pool Cooling Procedure
a. Inspection Scope
The inspectors performed an in-depth review of PSEGs corrective actions for inadequate RHR suppression pool cooling flow rate in operation procedures documented in notifications 20525566, 20540094, and 20541537. The inspectors had identified that the procedure to establish RHR suppression pool cooling flow did not account for instrument inaccuracies.
The inspectors assessed PSEGs extent of condition review and the prioritization and timeliness of corrective actions to determine whether they were appropriately identifying, characterizing, and correcting problems associated with the RHR suppression pool cooling procedure which did not account for instrument inaccuracies. In addition, the inspectors interviewed station personnel and reviewed selected extent of condition evaluations that were completed to assess the effectiveness of PSEGs corrective actions. The inspectors reviewed relevant procedures, corrective action notifications, and engineering evaluation related documents to verify PSEG addressed any instrument inaccuracies issues in abnormal procedures.
b. Findings and Observations
No findings were identified.
The inspectors determined that PSEGs overall response to the issue was commensurate with the safety significance, was timely, and included appropriate corrective actions such as increasing the RHR suppression pool cooling flow rate in the abnormal procedures to include instrument inaccuracies (Order 80105705). Additionally, the inspectors determined that the actions taken were reasonable to resolve the issue and that PSEG had appropriately evaluated the extent of condition. Further, the inspectors determined, based upon review of a technical evaluation of RHR suppression pool cooling flow (Order 70133354), PSEG appropriately performed an instrument uncertainty and design margin analysis. The inspectors concluded these actions were adequate.
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 PSEG made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR 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.
J Safety/Relief Valve Position Indicators - Special Report (Notification 20559654)
Technical support center out of service for planned maintenance (Event # 48010)
b. Findings
No findings were identified.
.2 (Closed) Licensee Event Report (LER) 05000354/2012-001-00: Average Power Range
Monitor Flow Unit Summers out of Tech Spec Tolerance
a. Inspection Scope
On March 1, 2012, the B reactor recirculation pump (RRP) tripped causing entry into single loop operations (SLO). During SLO the APRM flow unit summers were adjusted on March 4, 2012, during the performance of a weekly channel calibration procedure.
After restoring the B RRP to service and power ascension, several alarms were received indicating that the D APRM flow unit was upscale. PSEGs investigation discovered that all four APRM flow units were out of tolerance. All of the APRMs were declared inoperable and TS 3.3.1, action b was entered for the number of operable channels being less than the required minimum operable channels for both trip systems.
Subsequently, the channel calibration procedure HC.IC-CC.SE-0032, Average Power Range Monitor Flow Unit Summers, was completed satisfactorily and the APRM flow units were declared operable.
This event was reported under 10 CFR 50.36(c)(1)(ii)(A) for exceeding the allowable value for a LSSS; 50.73(a)(2)(i)(B) for a condition prohibited by TS; and, 50.73(a)(2)(vii)for a common-cause inoperability of independent trains or channels. The inspectors reviewed PSEGs LER, apparent cause evaluation (ACE), and supporting documentation and interviewed several members of station staff and management regarding the event. A finding was identified and is discussed below. This LER is closed.
b. Findings
Introduction.
The inspectors identified an NCV of very low safety significance (Green) of TSs 3.3.1 and 6.8.1 because PSEGs written procedure was not adequately established and implemented for completing the RPS test and calibration listed in TS table 4.3.1.1-1, function 2.b, footnote e. Specifically, procedure HC.IC-CC.SE-0032 for performing the weekly channel calibration of the flow biased APRMs that input into the simulated thermal power upscale RPS trip provided inadequate instructions for calculating total reactor recirculation drive flow while in single loop operations (SLO).
Description.
On March 1, 2012, the B RRP unexpectedly tripped and caused entry into SLO. The plant remained in SLO to conduct repairs. On March 4, 2012, at 0025 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br />, I&C technicians performed the weekly channel calibration procedure, HC.IC-CC.SE-0032, "Average Power Range Monitor Flow Unit Summers," to fulfill the weekly surveillance requirement listed in TS table 4.3.1.1-1, function 2.b, footnote e, for APRM flow biased simulated thermal power - upscale. The calibration procedure directs the I&C technician to obtain the value of total reactor recirculation drive flow from the plant process computer OD-3 and OD-3d reports to calculate the desired output voltage of the APRM flow unit. In SLO, the process computer is unable to accurately calculate the value of total reactor recirculation drive flow due to the unavailability of drive flow in the inactive loop. I&C technicians obtained the value for total recirculation drive flow from reactor engineering personnel. The reactor engineer calculated the recirculation drive flow using the formula provided in HC.IC-CC.SE-0032, but did not recognize that the formula could be incorrect under certain conditions during SLO. Using the flow value calculated by reactor engineering, I&C technicians calculated the desired output voltage.
When the APRM Flow Units were found to be out of the desired voltage range in the surveillance procedure, I&C technicians made adjustments to bring all four flow units into the desired voltage range.
The plant was returned to dual loop operations on March 5, 2012, and operators began to raise reactor power. On March 6, 2012, with the reactor at 92 percent, the Control Room received an Overhead Alarm C6-D1 "APRM/RBM FLOW REF OFF NORMAL" and "ROD OUT MOTION BLOCK" with computer point C028. In addition, the D APRM flow unit upscale light was illuminated. The Control Room entered the appropriate abnormal procedure and performed actions to bypass the D Flow Unit. Operators discovered that all of the Flow Units were reading abnormally high for the current plant condition. To validate the condition, operators performed the TS daily channel check for upscale APRM flow biased simulated thermal power and concluded three of six RPS APRM had failed the channel check in a non-conservative direction. Initially, operators entered TS 3.3.1 (action a) for the number of operable channels being less than the required minimum operable channels for one trip system.
The I&C Department promptly started calibration procedure HC.IC-CC.SE-0032 and discovered that all four APRM flow units were out of tolerance. Operators then entered TS 3.3.1 (action b) for the number of operable channels being less than the required minimum operable channels for both trip systems. Subsequently, I&C technicians completed HC.IC-CC.SE-0032 to restore all APRM flow units within calibration tolerances. All required testing was completed satisfactorily, the APRM flow units were declared operable, and the LCO and abnormal procedure were exited at 1524 hours0.0176 days <br />0.423 hours <br />0.00252 weeks <br />5.79882e-4 months <br /> on March 6, 2012. The inspectors noted that the APRM flow units had been non-conservatively calibrated for approximately 63 hours7.291667e-4 days <br />0.0175 hours <br />1.041667e-4 weeks <br />2.39715e-5 months <br />.
The inspectors reviewed the event and questioned why PSEG was not performing calculations to determine if the LSSS allowable value for the APRM Flow Biased Simulated Thermal Power-Upscale, as listed in TS Table 2.2.1-1, Reactor Protection System Instrumentation Setpoints, had been exceeded. The inspectors also reminded PSEG that exceeding a LSSS allowable value such that the automatic safety system does not function as required would be reportable in accordance with 10 CFR 50.36(c)(1)(ii)(A). Subsequently, PSEG determined that the LSSS allowable value had been exceeded for approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
The inspectors reviewed PSEGs apparent cause evaluation (ACE) for this event.
The ACE determined that the cause of the APRM flow units setpoints being non-conservative was that the procedure did not provide I&C technicians and reactor engineers with the proper method for determining drive flow values for the surveillance.
The formula provided in the procedure (HC.IC-CC.SE-0032) that calculated the drive flow was incorrect because the formula was for dual loop operation, not for SLO.
Corrective actions included revising the appropriate procedures and developing a schedule template (including required surveillances) for entry into and return from SLO.
The inspectors determined that PSEGs inadequate procedural guidance and instructions for calculating the percent recirculation drive flow values in the TS channel calibration procedure for the APRM flow unit summers, during SLO, was a performance deficiency. In addition, although the condition where the APRM Flow Unit setpoints was self-revealed by overhead alarms in the main control room, in accordance with IMC 0612, the inspectors considered this finding NRC-identified because the inspectors review of this issue added significant value. Specifically, the inspectors questions led PSEG to perform the calculations necessary to determine that LSSS allowable values had been exceeded; therefore, this issue was reportable in accordance with 10 CFR 50.36(c)(1)(ii)(A).
Analysis.
The inspectors determined that PSEGs inadequate procedural guidance and instructions for calculating the percent recirculation recirculation drive flow values in the TS channel calibration procedure for the APRM flow unit summers during SLO, was a performance deficiency. Specifically, the formula provided in the procedure for calculating drive flow was for dual loop operation, not for SLO. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, incorrect calibration of the APRM flow units resulted in the APRM flow biased setpoint being non-conservative and exceeding the associated TS LSSS allowable value for a period of time that was considered a condition prohibited by TS. The inspectors performed a Phase I screening of the finding using IMC 0609, Attachment 0609.04, Table 4a, Mitigating Systems cornerstone and determined the issue was of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not result in an actual loss of safety function, and was not potentially risk significant for external events.
The finding had a cross-cutting aspect in the area of human performance, resources component, because PSEG did not ensures that a TS-required RPS calibration procedure was complete, accurate and adequate to assure nuclear safety. Specifically, the formula provided in the APRM flow unit summer procedure that calculated the drive flow was incorrect. The formula provided in the procedure was for dual loop operation, not for SLO. H.2(c)
Enforcement.
Technical Specification (TS) 3.3.1, Reactor Protection System Instrumentation, requires that as a minimum, the reactor protection system instrumentation channels shown in Table 3.3.1-1 shall be operable with the applicability shown in Table 3.3.1-1. Table 3.3.1-1, Function 2.b, Average Power Range Monitor, Flow Biased Simulated Thermal Power - Upscale, is applicable in Mode 1 and requires a minimum of two
- (2) operable channels per trip system. The associated Limiting Condition for Operation Action Statement 3.7.1.2(a) states that with the number of operable channels less than required by the minimum operable channels per trip system requirement for both trip systems, place at least one trip system** in the tripped condition within one hour and take the action required by Table 3.3.1-1. Action 4 from Table 3.3.1-1 states that the mode switch be placed in at least startup within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
TS 6.8.1 requires, that written procedures shall be established, implemented, and maintained covering the activities in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Section 8.b(2)(l) of Appendix A of Regulatory Guide 1.33 states, in part, that specific implementing procedures are required to be for each surveillance test or calibration listed in the technical specifications, including those for Reactor Protection System Tests and Calibrations.
Contrary to the above, between 0025 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> on March 4, 2012, and 1524 hours0.0176 days <br />0.423 hours <br />0.00252 weeks <br />5.79882e-4 months <br /> on March 6, 2012, PSEGs written procedure (HC.IC-CC.SE-0032) was not adequately established and implemented for completing a reactor protection system test and calibration listed in the technical specification table 4.3.1.1-1, function 2.b, footnote e.
Specifically, the procedure for performing the weekly channel calibration of the APRMs that input into the flow biased simulated thermal power upscale reactor protection system trip, HC.IC-CC.SE-0032, provided inadequate instructions for calculating reactor recirculation drive flow while in single loop operations. This rendered both trip systems for the Average Power Range Monitor, Flow Biased Simulated Thermal Power - Upscale inoperable for greater than six
- (6) hours and the mode switch was not taken to STARTUP. This issue was entered into CAP as notification 20549760, and PSEGs corrective actions included revision of the appropriate procedures and development of a schedule template (including required surveillances) for entry into and return from SLO.
Because the violation was of very low safety significance (Green) and has been entered into the CAP this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000354/2012-003-02, Average Power Range Monitor Flow Unit Summers out of Tech Spec Tolerance)
4OA5 Other Activities (OA)
Inspection Procedure 71003, License Renewal Condition Numbers 26 and 27 Regarding the Drywell Air Gap Drainage Capability and Monitoring
a. Inspection Scope
An inspection, performed during April 23 - 25, 2012, evaluated activities related to the renewed license condition numbers 2.C(26) and 2.C(27) applicable to the drywell air gap drainage capability and monitoring at the Hope Creek Generating Station. During the 2012 refueling outage, the plant staff was in the process of establishing drainage from the drywell air gap region and conducting the work items specified in license condition number 2.C(26).
License condition number 2.C(26) requires that until drainage is established from the drywell air gap region, boroscope examinations be made in the bottom of the drywell air gap, ultrasonic thickness measurements be performed of the drywell shell at specific locations, the penetration sleeve J13 be monitored for water leakage when the drywell reactor cavity is flooded up, the torus room be monitored for leakage from other penetrations, and a report be submitted to NRC within 90 days after each refueling outage summarizing the results.
License condition number 2.C(27) provides the requirements to be met after drainage is established from the drywell air gap region.
The inspectors walked down portions of the outside of the drywell and the torus to confirm the acceptance of a sample of visual examinations was in accordance with site procedures and ASME Code IWE requirements. External portions of the containment boundary were also observed at the location of the J13 penetration and the 4 diameter drain lines from the air gap between the drywell steel shell and concrete to the torus room floor. The inspectors went into the tunnels in the concrete surrounding the drywell at the 135 and 270 degree locations to view the drywell outer surface and concrete conditions in the lower portion of the air gap. The performance of boroscope examinations by qualified visual examiners through two penetration sleeves of the lower air gap to drywell locations was observed. Additionally, the inspectors reviewed video records of the air gap region and the results of ultrasonic thickness measurements that were made within the scope of license condition number 2.C(26).
During an inspection, performed July 26, 2012, followup was done to review the concrete to drywell surface condition under the drywell. This was to determine if the concrete under the drywell was sufficiently dry to prevent drywell underside lower head corrosion by moisture. The inspector met with licensee engineering staff to review their work on this topic.
The applicable drawing is C-0935-0, Rev 11, Drywell Construction Sequence which along with specifications 10855-C-102, Rev 17 (Concrete Mix Designs), C-101(Q), Rev 13 (Concrete), C-152 (Q) Rev 10 &12 (Inorganic Zinc coating) and the ACI 506R-05, Standard on Shotcrete provide a basis for understanding the condition of the drywell underside. The engineering staff presented the conditions that the concrete placement sequence including Shotcrete application to the underside of the drywell and drying times with openings for venting did not allow for an excess of water buildup under the drywell. The zinc coating on the drywell underside provides an additional means of protection to the drywell material.
b. Findings
No findings were identified.
4OA6 Meetings, including Exit
On July 19, 2012, the inspectors presented inspection results to with Mr. D. Lewis and other members of his staff. The inspectors asked PSEG whether any materials examined during the inspection were proprietary. No proprietary information was identified.
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 an NCV.
10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by documented instructions or procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions or procedures. PSEG procedure OP-HC-108-115-1001, Operability Assessment and Equipment Control Program, step 5.3.4.2.D states that if an inoperable SSC will impact secondary containment integrity during fuel handling and core alterations, then develop a contingency plan for sealing secondary containment penetrations for each inoperable penetration.
Contrary to OP-HC-108-115-1001, a contingency plan for sealing an inoperable secondary containment penetration was not established on April 18 and 19, 2012, during core alterations, while a rupture disk (H1EA-1EAPSE-2210B) in the B station SW piping (secondary containment penetration) was removed for replacement. The inspectors evaluated the finding using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, and Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs. Specifically, Checklist 7, BWR Refueling Operation with RCS Level >23, was reviewed and the finding was determined to be of very low safety significance (Green) because it challenged the containment control guidelines, but did not meet the criteria that would require phase 2 or phase 3 analyses. PSEG documented the issue in Notification 20555753.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
PSEG Personnel
- J. Perry, Hope Creek Site Vice President
- D. Lewis, Hope Creek Plant Manager
- E. Carr, Operations Director
- K. Knaide, Work Management Director
- W. Kopchick, Engineering Director
- F. Mooney, Maintenance Director
- P. Duca, Senior Engineer, Regulatory Assurance
- M. Gaffney, Regulatory Assurance Manager
- P. Bonnett, Senior Compliance Engineer
- H. Trimble, Radiation Protection Manager
- D. Boyle, Operations Support Manager
- J. Krall, Reactor Engineering Manager
- B. Brammeier, ISI Program Engineer
- A. Enilo, Mechanical Design Engineer
- G. Holoman, Project Manager (Drywell)
- E. Maloney, Principal Nuclear Engineer (ISI)
- R. Schmidt, Principal Nuclear Engineer (IVVI)
- F. Leeser, Chemistry Manager
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened/Closed
Preconditioning of the Reactor Building to Torus
Vacuum Relief Valves (Section 1R12)
Average Power Range Monitor Flow Unit Summers
Out of Tech Spec Tolerance (Section 4OA3.2)
Closed
- 05000354/2012-001-00 LER
Average Power Range Monitor Flow Unit Summers
Out of Tech Spec Tolerance (Section 4OA3.2)