IR 05000277/2012004

IR 05000277-12-004 and 05000278-12-004; Peach Bottom Atomic Power Station, 07-01-12 - 09-30-12; NRC Integrated Inspection Report

ML12319A024
Person / Time
Site:	Peach Bottom
Issue date:	11/14/2012
From:	Paul Krohn Reactor Projects Region 1 Branch 4
To:	Pacilio M Exelon Nuclear, Exelon Nuclear Generation Corp
krohn, pg
References
IR-12-004
Download: ML12319A024 (39)

Text

UNITED STATES ember 14, 2012

SUBJECT:

PEACH BOTTOM ATOMIC POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000277/2012004 AND 05000278/2012004

Dear Mr. Pacilio:

On September 30, 2012, the U. S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Peach Bottom Atomic Power Station (PBAPS), Units 2 and 3.

The enclosed integrated inspection report documents the inspection results, which were discussed on October 22, 2012, with Mr. Garey Stathes, Peach Bottom Site Vice President, and other members of your staff.

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

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

This report documents one self-revealing finding of very low safety significance (Green). The finding was determined to involve a violation 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 the very low safety significance, and because it is entered into your corrective action program (CAP), the NRC is treating this finding as a non-cited violation (NCV), consistent with Section 2.3.2 of the NRC Enforcement Policy. If you contest any NCVs in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, U. S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at PBAPS. 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 PBAPS.

In accordance with Title 10 of the Code of Federal Regulations (10 CFR), Section 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any), will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRCs Agencywide Documents Access Management System (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Paul G. Krohn, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos.: 50-277, 50-278 License Nos.: DPR-44, DPR-56 Enclosure: Inspection Report 05000277/2012004 and 05000278/2012004 w/Attachment: Supplementary Information cc w/encl: Distribution via ListServ

SUMMARY OF FINDINGS

IR 05000277/2012004, 05000278/2012004; 07/01/2012 - 09/30/2012; Peach Bottom Atomic

Power Station (PBAPS), Units 2 and 3; Maintenance Risk Assessments and Emergency Work Control.

The report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. This report documents one Green, self-revealing finding. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). The cross-cutting aspect associated with the finding was determined using IMC 0310,

Components Within the Cross-Cutting Areas. Findings for which the SDP does not apply may be Green, or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green, self-revealing non-cited violation (NCV) of Technical Specification (TS) 5.4.1, Procedures. The inspectors determined that PBAPS did not properly preplan and perform maintenance/modifications to the Unit 2 low pressure coolant injection (LPCI) swing bus B motor control cabinet (MCC) while energized. Specifically, PBAPS did not appropriately consider the potential plant impact due to sensitive energized components within the MCC that could be activated and did not utilize sufficient physical barriers to prevent such activation. Consequently, on July 25, 2012, the B loop of the residual heat removal (RHR) system was declared inoperable and unavailable after workers pulling an electrical cable into the Unit 2 energized LPCI swing bus B MCC inadvertently contacted and actuated the LPCI inboard injection valve motor relay. The motor operated valve (MOV) relay actuation caused a potential over-thrust event and had the potential to impact the valves qualification and reliability. PBAPS conducted detailed examinations and diagnostic stroke testing on the MOV assembly and concluded that the design limits of the MOV assembly were not exceeded.

This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating System cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that this finding was of very low safety significance (Green) because it did not represent an actual loss of safety function of a single LPCI train for greater than its TS allowed outage time. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, work control, because PBAPS did not appropriately incorporate risk insights and job site conditions that could impact plant structures, systems, and components (SSCs) into its work activities. Specifically,

PBAPS did not appropriately consider and reduce the potential for an over-thrust event on the B loop LPCI inboard injection valve MO-2-10-25B when performing work in the LPCI swing bus B MCC while it was energized. H.3(a) (Section 1R13)

Other Findings

One violation of very low safety significance, which was identified by Exelon, was reviewed by the inspectors. Corrective actions taken or planned by Exelon have been entered into the CAP.

This violation and the corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 2 began the inspection period at 100 percent power. On June 30, the unit began its end-of-cycle (EOC) coast down period. Planned power reductions of approximately 5-to-10 percent of rated thermal power (RTP) were performed on July 7 and 21, 2012, respectively, to remove the fifth and fourth stage feedwater (FW) heat exchangers (HXs) from service during the EOC coast down. On September 9, a planned shutdown from approximately 80 percent power was commenced, and the main generator breaker was opened to start the units 19th refueling outage (RFO) P2R19. During the shutdown, operators inserted a planned manual scram from approximately five percent reactor power. The unit remained in P2R19 through the end of the inspection period.

Unit 3 began the inspection period at 100 percent power where it remained until power was reduced to approximately 85 percent on August 19, to support planned hydraulic control unit (HCU) maintenance and associated control rod pattern adjustment. On August 20, the unit was returned to 100 percent until August 24, when power was reduced to approximately 60 percent to support planned maintenance and testing, to recover HCUs from the previous weeks maintenance, and perform the associated control rod pattern adjustment. On August 25, the unit was returned to 100 percent RTP until August 26, when power was reduced to approximately 85 percent for a follow-up control rod pattern adjustment. The unit was returned to full power on August 27, where it remained until the end of the inspection period, except for brief periods to support planned testing.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Condition (1 Adverse Weather Sample)

a. Inspection Scope

The inspectors reviewed plant features and procedures for key outage safety function on Unit 2 during a severe thunderstorm warning on September 18, 2012, concurrent with yellow outage risk on Unit 2 due to fuel moves, which elevated plant risk conditions to orange. The inspectors reviewed communication protocols between the control room personnel and electrical system operations, as well as measures prescribed and taken to maintain the availability and reliability of these electrical power systems.

Additionally, the inspectors reviewed procedures for severe weather preparation, main control room (MCR) logs, and condition reports (CRs). Documents reviewed for each section of this inspection report are listed in the Attachment.

b. Findings

No findings were identified.

.2 External Flooding (1 External Flooding sample)

a. Inspection Scope

On September 18, 2012, the inspectors performed an inspection of the external flood protection measures for PBAPS. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), Chapter 2.4.3.5, which depicted the design flood levels and protection areas containing safety-related equipment to identify areas that may be affected by external flooding. The inspectors conducted a general site walkdown of the emergency diesel generator (EDG) rooms and the EDG fire protection cardox room to ensure that the external flood protection features were in accordance with design specifications. The inspectors also reviewed operating procedures for mitigating external flooding to determine if PBAPS planned or established adequate measures to protect against external flooding events.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Partial System Walkdowns (71111.04Q - 3 samples)

a. Inspection Scope

The inspectors performed partial walkdowns of the following three systems:

Electric motor-driven fire pump with the diesel-driven fire pump inoperable on August 1, 2012 Standby gas treatment (SBGT) A' train with B train unavailable on August 7, 2012 E-1, 2 & 4 EDGs with E-3 unavailable on September 4, 2012 The inspectors selected these systems based on their risk-significance relative to the Reactor Safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the UFSAR, TSs, work orders (WOs), CRs, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. The inspectors also reviewed whether PBAPS staff had properly identified equipment issues and entered them into the licensees corrective action program (CAP) for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

1R05 Fire Protection

Resident Inspector Quarterly Walkdowns (71111.05Q - 3 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 PBAPS 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 (OOS),degraded or inoperable fire protection equipment, as applicable, in accordance with procedures.

Unit 2 reactor outage work - elevation 135 on August 24 Unit 2 and Unit 3 turbine building (TB) - elevation 165 on August 24 Unit 2 reactor building (RB) - elevation 165 during RFO on August 19

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Annual Review of Cables Located in Underground Bunkers/Manholes

a. Inspection Scope

The inspectors conducted an inspection of underground bunkers/manholes subject to flooding that contain cables whose failure could disable risk-significant equipment. The inspectors performed walkdowns of risk-significant areas, including manhole 91C containing 'C' emergency cooling tower (ECT) load center cables, to verify that the cables were not submerged in water, that cables and/or splices appeared intact, and to observe the condition of cable support structures. When applicable, the inspectors verified proper sump pump operation and verified level alarm circuits were set in accordance with station procedures and calculations to ensure that the cables will not be submerged. The inspectors also ensured that drainage was provided and functioning properly in areas where dewatering devices were not installed.

b. Findings

No findings were identified.

1R08 In-service Inspection

a. Inspection Scope

The inspectors examined a sample of non-destructive examinations (NDE) by performance of a documentation review and direct observation of selected NDE to verify activities were implemented in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI.

Activities inspected during the PBAPS Unit 2 RFO 19 (P2R19) included observations of ultrasonic testing (UT), calibration practices and analysis of test results using traditional UT, the Phased Array UT technique, and manual based UT, where the Performance Demonstration Initiative (PDI) practices were required. The inspectors reviewed the applicable UT procedures, observed UT data analysis review and confirmed that relevant indications were properly documented and presented to the licensee for disposition. The inspectors observation and documentation review of non-destructive testing included the following:

The reactor pressure vessel (RPV) UT observations included the upper head meridian weld CH-MB done per the GE-UT-716, Revision 3, procedure for the examination of reactor pressure vessel welds from the outside surface with MicroTomo in accordance with Appendix VIII, as the third re-examination of previously identified indications in this weld.

For the dissimilar metal (DM) weld N8A, the 4 inch diameter jet pump nozzle that was UT examined with the phased array technique, using procedure EPRI-DMW-PA-1, Revision 3. The inspectors observed the pretest equipment setup, calibration, testing conditions in the drywell and the post-test results. The UT preparations and results for N2A, a 14 inch diameter RPV nozzle to safe-end DM weld examined in a similar manner to N8A was reviewed.

The Peach Bottom Unit 2, vessel drain line flow accelerated corrosion (FAC) UT inspection results of the thickness measurements made in the vicinity of the stainless steel pipe, 2 inch diameter, to carbon steel (CS) socket weld were reviewed. The FAC parameter based calculation showed low susceptibility for the piping to FAC which was confirmed by no wall loss on UT thickness measurement at 14 circum-ferential thickness scans over the stainless steel pipe, elbow, and CS pipe.

The preparation, work package instructions, pre-job briefing, and procedure for the penetrant testing (PT) of the integral attachment weld H1A at elevation 135 feet, per procedure PT ER-AA-335-02, were reviewed.

For in-vessel visual inspection (IVVI), the inspectors sampled the remote enhanced visual examination records of reactor vessel internals as done under water inside the reactor vessel per procedure GEH-UT-204, Version 14. IVVI video records of both previously identified indications and their current appearance during the P2R19 RFO were reviewed. The inspection scope included portions of the core shroud, steam dryer, steam separator, jet pump components, and top guide bars. Also, the applicable parts of the IVVI procedure, observation of a sample of digital video records, the analysis process for the observations, and documentation of indications were reviewed.

The inspectors observed the condition of the drained torus as visible from the full circumference of the internal catwalk. The torus was to be internal surface prepared, inspected, and coated. The work plans for the existing coating removal, recoating requirements, and coating inspection controls were reviewed.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator requalification simulator training on August 20, 2012, which included two simulated plant events related to an inadvertent stuck open reactor safety relief valve (SRV), reactor water level restoration combined with an electrical malfunction that resulted in a failure of the reactor to scram, and an emergency reactor vessel de-pressurization due to high primary containment drywell temperature.

The inspectors evaluated operator performance during the simulated events and verified completion of risk significant operator actions, including the use of abnormal and emergency operating procedures. The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. The inspectors verified the accuracy and timeliness of the emergency classification made by the shift manager and the TS action statements entered by the shift technical advisor.

Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the MCR

a. Inspection Scope

The inspectors observed the following activities in the MCR:

E-3 EDG MCR observations after the lube oil pump discharge pipe weld was repaired during night shift on September 5, 2012 The inspectors observed infrequently performed test or evolution briefings, pre-shift briefings, and reactivity control briefings to verify that the briefings met the criteria specified in Exelons procedure HU-AA-1211, Pre-Job Briefings, Revision 7.

Additionally, the inspectors observed test performance to verify that procedure use, crew communications, and coordination of activities between work groups similarly met established expectations and standards.

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 SSC performance and reliability. The inspectors reviewed system health reports, CAP documents, maintenance WOs, and maintenance rule (MR)basis documents to ensure that PBAPS was identifying and properly evaluating performance problems within the scope of the MR. For each sample selected, the inspectors verified that the SSC was properly scoped into the MR in accordance with 10 CFR 50.65 and verified that the (a)(2) performance criteria established by the PBAPS staff were reasonable. As applicable, for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2).

Additionally, the inspectors ensured that PBAPS staff was identifying and addressing common cause failures that occurred within and across MR system boundaries.

Unit 2 and 3 core spray system pump differential switch failures on July 3 and 5, 2012 ECT cell C unavailability on July 12 and 13, 2012 Unit 2 electro-hydraulic control failure on August 24, 2012

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed station evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that PBAPS performed the appropriate risk assessments prior to removing equipment for work. The inspectors selected these activities based on potential risk significance relative to the Reactor Safety cornerstones. As applicable for each activity, the inspectors verified that PBAPS personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When PBAPS performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work and discussed the results of the assessment with the stations probabilistic risk analyst to verify plant conditions were consistent with the risk assessment. The inspectors also reviewed the TS requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

Unit 2 reactor core isolation cooling (RCIC) pump and turbine pressure switch testing on July 2, 2012 E-1 emergency core cooling system (ECCS) simulator auto start on July 11 and 12, 2012 Unit 2 primary containment isolation valve system unplanned half group I isolation on July 16, 2012 Unit 2 RHR low pressure coolant injection motor-operated valve MO-2-10-25B on July 25, 2012 E-3 EDG lube oil pipe leak on September 4, 2012

b. Findings

Introduction.

A self-revealing Green NCV of TS 5.4.1 was identified when PBAPS did not properly preplan and perform maintenance/modifications to the Unit 2 LPCI swing bus B MCC while energized. Specifically, PBAPS did not appropriately consider the potential plant impact due to sensitive energized components within the MCC that could be activated and did not utilize sufficient physical barriers to prevent such activation.

Description.

On July 25, 2012, electricians were performing an electrical cable pull for the multiple spurious operations project into the Unit 2 energized LPCI swing bus B MCC. To allow a smooth pull of the cable, lubrication was applied to the chase nipple at the bottom of the cabinet. During the pull, the lubrication contacted one of the electricians gloved hands and caused the hand to suddenly slide up the cable and inadvertently contact the edge of an adjacent interposing closing (PC) relay. The contact actuated the relay and resulted in an over current alarm in the control room and a close signal to the B loop LPCI inboard injection isolation valve, MO-2-10-25B. The inspectors noted that the workers performed a 2-Minute-Drill to assess the hazards and safety concerns in the work area, but did not consider the possibility of lubrication contacting their work gloves and causing their hands to slip during the cable pull. The inspectors also noted that the operational risk of the cable pull was not communicated to the workers.

The MO-2-10-25B valve was in its normal full-closed position at the time of the event, and PBAPS determined that the contact made by the electrician with the PC relay energized the motor-operator control circuit, causing the valve actuator to drive the valve disc slightly further into the valve seat. The resultant forces applied by the valve actuator represented a potential over-thrust event wherein the MOV assembly sub-components may have been damaged. Such damage could adversely affect the ability of the valve to perform its isolation capability or its ability to open or close as required.

Based on the relay actuation, and in an effort to evaluate the condition of the valve, PBAPS opened the MO-2-10-25B MOV electrical breaker, declared the B loop of RHR inoperable and unavailable, and entered TS Limiting Condition for Operation (LCO)3.5.1, Condition A, for One Low Pressure ECCS Injection/Spray Subsystem Inoperable. The 'B' loop of RHR was unavailable for over three days, between July 25 and July 28, 2012, for troubleshooting, inspection, and testing.

PBAPS conducted detailed examinations and diagnostic stroke testing on the MOV assembly. Current measurements during unwedging from the valve seat in the initial open stroke indicated that the valve had likely experienced closing over-thrust when the PC relay was bumped. The RHR LPCI injection valve 480-volt supply breaker thermal overload design specifications were also reviewed during the troubleshooting, and indicated that an actual overload condition was credible. During subsequent diagnostic testing, the RHR LPCI injection valve met all design basis criteria, and showed no signs of damage. Spring pack compensator measurements in the MOV actuator taken prior to and following the initial open stroke were compared to vendor data to estimate the closing force applied during the potential over-thrust event. PBAPS concluded that the design limits of the MOV assembly were not exceeded. The inspectors reviewed PBAPS's evaluations, performed local inspections of the valve body and MOV assembly in the field, discussed the event with operators and engineers, and concluded that PBAPS's response to the event and engineering evaluations was appropriate to the circumstances. The MO-2-10-25B valve and B RHR loop were subsequently restored to an operable status on July 28, 2012.

Analysis.

The inspectors determined that PBAPS did not properly preplan and perform maintenance/modifications to the LPCI swing bus B MCC while energized. Specifically, PBAPS did not appropriately consider the potential plant impact due to sensitive energized components within the MCC that could be activated and did not utilize sufficient physical barriers to prevent such activation, which created a condition adverse to quality related to the LPCI inboard injection valve and constituted a performance deficiency. Consequently, on July 25, 2012, electricians performing an electrical cable pull in the Unit 2 energized LPCI swing bus B MCC inadvertently contacted a PC relay, causing a close signal to the B loop LPCI inboard injection isolation valve that resulted in a potential over-thrust event. The potential over-thrust event called into question the qualification and operability of the valve. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating System cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the B loop of RHR was declared inoperable and unavailable for over three days so that the condition and performance of the valve could be determined. Using Inspection Manual Chapter (IMC) 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, and IMC 0609, Appendix A, The Significant Determination Process (SDP) for Findings At-Power, the inspectors determined that this finding was of very low safety significance (Green) because it did not represent an actual loss of safety function of a single LPCI train for greater than its TS allowed outage time.

The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, work control, because PBAPS did not appropriately incorporate risk insights and job site conditions that could impact plant SSCs into its work activities

H.3(a). Specifically, PBAPS did not appropriately consider and reduce the potential for an over-thrust event on the B loop LPCI inboard injection valve MO-2-10-25B when performing work in the LPCI swing bus B MCC while it was energized.

Enforcement.

TS 5.4.1, Procedures, states, in part, that written procedures shall be implemented and maintained as recommended in RG 1.33, Appendix A, "Quality Assurance Program Requirements," dated November 1972. RG 1.33, Appendix A,Section I, Procedures for Performing Maintenance, states, in part, that Maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. RG 1.33, Appendix A,Section I, also indicates that general procedures for the control of maintenance, repair, replacement, and modification work should include information on factors to be taken into account when preparing the detailed work procedures. Contrary to the above, PBAPS did not properly preplan and perform maintenance/modifications to the LPCI swing bus B MCC. Additionally, when preparing the detailed work procedures for modifications to the LPCI swing bus B MCC, PBAPS did not properly take into consideration and provide information on the potential impact to safety systems when performing work in the cabinet while it is energized. Consequently, on July 25, 2012, when working in the Unit 2 LPCI swing bus B MCC, workers pulling an electrical cable inadvertently contacted a PC relay, causing a close signal to the B loop LPCI inboard injection valve that resulted in a potential over-thrust condition and called into question the qualification and operability of the valve. The B loop of RHR was subsequently declared inoperable to perform a detailed examination of the valve. Because this finding was of very low safety significance and it was entered into the licensees CAP via IR

===1392865, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRCs Enforcement Policy. (NCV 05000277/2012004-01, Inadequate Preplanning and Performance of Maintenance/Modifications Resulted in Unavailability of RHR B Loop)

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed six operability determinations (ODs) for the following degraded or non-conforming conditions:

Rosemount trip units Part 21 notification on July 9 and 10, 2012 Unit 2 RHR 'B' LPCI injection valve MO-2-10-025B following over-thrust event on July 26 and 27, 2012 Diesel driven fire pump strainer on August 2, 2012 Unit 2 high-pressure coolant injection (HPCI) followi ng discovery of check valve in-body out of tolerance alignment on August 9 and 10, 2012 500kV voltage high on August 21, 2012 E-1 EDG following discovery of lube oil system partial penetration welds on September 9 and 10, 2012 The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determinations (ODs) 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 PBAPSs 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 PBAPS. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.

b. Findings

No findings were identified.

1R18 Plant Modifications

Temporary Modification

a. Inspection Scope

The inspectors evaluated the temporary modification to the Unit 2 B recirculation pump seal cooling to determine whether the modification affected functions that are important to safety. The inspectors reviewed modification documents associated with the temporary change, discussed the modification with engineers and operators, and walked down the temporary cooler to verify that the modification did not degrade the current design bases, licensing bases, and performance capability of the affected systems, and also to verify that the temporary installation did not introduce a trip risk to the unit.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post-maintenance tests (PMTs) 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 (DBDs), 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.

Unit 2 RHR LPCI injection valve stroke time testing following planned maintenance, troubleshooting, and testing on July 28, 2012 E-3 EDG NDE after weld repair on September 5, 2012 E-12 4 kV bus loss-of-coolant accident (LOCA)/LOOP test on September 20, 2012

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

Peach Bottom Unit 2 Outage - Refueling (P2R19)

a. Inspection Scope

The inspectors reviewed the stations work schedule and outage risk plan for the Unit 2 maintenance and RFO (P2R19), which began on September 9, 2012, and continued for the duration of the inspection period. The inspectors reviewed PBAPS's 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 technical specifications when taking equipment OOS 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 Fatigue management Refueling activities, including fuel handling and fuel receipt inspections Control of heatup and startup activities Identification and resolution of problems related to RFO activities

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

(4 routine surveillances, 1 in-service test sample, 1 reactor coolant system (RCS), and 1 isolation valve sample)

The inspectors observed performance of surveillance tests (STs) and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied TSs, the UFSAR, and PBAPS 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 STs:

ST-O-014-301-3, Unit 3 A Core Spray Quarterly ST on July 19, 2012 (in-service test sample)

ST-O-020-560-2(3), Reactor Coolant Leakage Test, on July 23, 2012 (RCS leakage sample)

ST-O-013-302-3, RCIC Pump, Valve, Flow and Unit Cooler Functional and In-service Comprehensive Test" on July 25, 2012 Emergency Service Water (ESW) flow to the EDG and ECCS HX on July 24, 2012 E-3 EDG ECCS simulated auto start on August 9, 2012 ST-O-07G-475-2, "Main Steam Isolation Valve (MSIV) Closure Timing at Shutdown,"

on September 10, 2012 (isolation valve sample)

Safety Relief Valve as-found lift setpoint testing on September 27, 2012

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

The inspectors used the requirements in 10 CFR Part 20 and guidance in RG 8.38, Control of Access to High and Very High Radiation Areas (VHRA) for Nuclear Plants, the TSs, and the licensees procedures required by TSs criteria for determining compliance.

The inspectors observed work activities performed during the Unit 2 RFO (2R19).

Significant work activities being performed included: condenser bay turbine retrofit; outboard MSIV valve scaffold; drywell SRVs; drywell nozzle in-service inspection and NDE; and, torus coating project.

On September 11, 2012, the inspectors reviewed radiological issues which resulted from the release of steam during the opening of the reactor vent line flange, including a walk down of the refueling floor and other affected areas of the Unit 2 RB. A total of 47 individuals received internal uptakes and were whole body counted. There was no radioactive release from the RB due to this event. Total effective dose equivalent for the maximally exposed individual was determined to be less than one percent of the annual occupational exposure limit. Additional event details are documented in report section 4OA3, Follow-up of Events.

The inspectors reviewed licensee Performance Indicators (PIs) for the Occupational Exposure cornerstone. The inspectors reviewed the results of radiation protection program audits. The inspectors reviewed reports of operational occurrences related to occupational radiation safety since the last inspection.

The inspectors determined if, since the last inspection, there have been changes to plant operations that may result in a significant new radiological hazard for onsite workers or members of the public. The inspectors verified the licensee has assessed the potential impact of these changes and has implemented periodic monitoring, as appropriate, to detect and quantify the radiological hazard.

The inspectors selected radiologically risk-significant work activities that involved exposure to radiation. The inspectors verified that appropriate pre-work surveys were performed which were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures. The inspectors evaluated the radiological survey program to determine if hazards were identified properly, including the following:

identification of hot particles the presence of alpha emitters the potential for airborne radioactive materials, including the potential presence of transuranics and/or other hard-to-detect radioactive materials the hazards associated with work activities that could suddenly and significantly increase radiological conditions significant radiation field dose gradients that can result in non-uniform exposures of the body.

The inspectors selected air sample survey records and verified that samples were collected and counted in accordance with licensee procedures. The inspectors observed work in potential airborne areas, and verified that air samples were representative of the breathing air zone. The inspectors verified that the licensee has a program for monitoring levels of loose surface contamination in areas of the plant with the potential for the contamination to become airborne.

The inspectors reviewed radiation work permits (RWPs) used to access high radiation areas (HRAs) and identify what work control instructions or control barriers had been specified. The inspectors verified that allowable stay times or permissible dose for radiologically significant work under each RWP was clearly identified. The inspectors verified that electronic personal dosimeter alarm set points were in conformance with survey indications and plant policy.

The inspectors reviewed the licensees 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 indicated the presence of licensed radioactive material.

The inspectors reviewed the licensees procedures and records to verify that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters.

The inspectors selected two sealed sources from the licensees inventory records that present the greatest radiological risk. The inspectors verified that sources are accounted for and had been verified to be intact.

The inspectors verified that any transactions involving nationally tracked sources were reported in accordance with 10 CFR 20.2207.

For high-radiation work areas with significant dose rate gradients (a factor of five or more), the inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel. The inspectors verified that licensee controls were adequate.

The inspectors reviewed RWPs for work within airborne radioactivity areas with the potential for individual worker internal exposures. The inspectors evaluated airborne radioactive controls and monitoring, including potentials for significant airborne contamination. For these selected airborne radioactive material areas, the inspectors verified barrier integrity and temporary high-efficiency particulate air ventilation system operation.

The inspectors conducted selective inspection of posting and physical controls for HRAs and VHRAs, to the extent necessary to verify conformance with the Occupational PI.

The inspectors discussed with the Radiation Protection Manager the controls and procedures for high-risk HRAs and VHRAs. The inspectors verified that any changes to licensee procedures did not substantially reduce the effectiveness and level of worker protection.

The inspectors discussed with first-line health physics supervisors the controls in place for special areas that have the potential to become VHRAs during certain plant operations. The inspectors verified that licensee controls for all VHRAs, and areas with the potential to become a VHRA, ensured that an individual is not able to gain unauthorized access to the VHRA.

During job performance observations, the inspectors observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors determined that workers were aware of the significant radiological conditions in their workplace and the RWP controls/limits in place and that their performance reflected the level of radiological hazards present.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be human performance errors. The inspectors determined that there was no observable pattern traceable to a similar cause. The inspectors determined that this perspective matched the corrective action approach taken by the licensee to resolve the reported problems.

During job performance observations, the inspectors observed the performance of the radiation protection technician with respect to radiation protection work requirements.

The inspectors determined that technicians were aware of the radiological conditions in their workplace and the RWP controls/limits and that their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be radiation protection technician error. The inspectors determined that there was no observable pattern traceable to a similar cause. The inspectors determined that this perspective matched the corrective action approach taken by the licensee to resolve the reported problems.

The inspectors verified that problems associated with radiation monitoring and exposure control were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensee CAP. In addition to the above, the inspectors verified the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involve radiation monitoring and exposure controls. The inspectors determined that the licensee was assessing the applicability of operating experience to their plants.

b. Findings

No findings were identified.

2RS2 Occupational As Low As is Reasonably Achievable (ALARA) Planning and Controls

a. Inspection Scope

The inspectors used the requirements in 10 CFR Part 20, RG 8.8, Information Relevant to Ensuring that Occupational Radiation Exposures at Nuclear Power Plants will be ALARA, RG 8.10, Operating Philosophy for Maintaining Occupational Radiation Exposure ALARA, the TSs, and the licensees procedures required by TSs as criteria for determining compliance.

The inspectors observed work activities being performed during the Unit 2 RFO (P2R19). For this outage, the licensee had established an outage goal of 222 person-rem, with an outage estimate of 263 person-rem.

The inspectors obtained from the licensee a list of work activities ranked by actual or estimated exposure that were in progress or that have been completed during the last outage, and select work activities of the highest exposure significance.

The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements. The inspectors determined that the licensee had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances.

The inspectors verified that for the selected work activities that the licensee had established measures to track, trend, and if necessary to reduce, occupational doses for ongoing work activities. The inspectors verified that trigger points or criteria were established to prompt additional reviews and/or additional ALARA planning and controls.

The inspectors evaluated the licensees method of adjusting exposure estimates, or re-planning work, when unexpected changes in scope or emergent work were encountered.

The inspectors determined that adjustments to exposure estimates were based on sound radiation protection and ALARA principles or that they were adjusted to account for failures to control the work. The inspectors determined whether the frequency of these adjustments call into question the adequacy of the original ALARA planning process.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

The inspectors used the requirements in 10 CFR Part 20, the guidance in RG 8.15, Acceptable Programs for Respiratory Protection, RG 8.25, Air Sampling in the Workplace, NUREG-0041, Manual of Respiratory Protection Against Airborne Radioactive Material, the TSs, and the licensees procedures required by TSs as criteria for determining compliance.

The inspectors reviewed the plant final safety analysis report (FSAR) to identify areas of the plant designed as potential airborne radiation areas and any associated ventilation systems or airborne monitoring instrumentation. The inspectors reviewed the FSAR for an overview of the respiratory protection program and a description of the types of devices used. The inspectors reviewed the FSAR, TSs, and emergency planning documents to identify the location and quantity of respiratory protection devices stored for emergency use.

The inspectors verified that the licensee used ventilation systems as part of its engineering controls, in lieu of respiratory protection devices, to control airborne radioactivity. The inspectors reviewed procedural guidance for use of installed plant systems, and verified that the systems were used, to the extent practicable, during high-risk activities. The inspectors selected installed ventilation systems used to mitigate the potential for airborne radioactivity, and verified that ventilation airflow capacity, flow path, and filter/charcoal unit efficiencies were consistent with maintaining concentrations of airborne radioactivity in work areas below the concentrations of an airborne area to the extent practicable.

The inspectors selected temporary high-efficiency particulate air filtration systems used to support work in contaminated areas. The inspectors verified that the use of these systems were consistent with licensee procedural guidance and ALARA.

The inspectors verified that the licensee provided respiratory protective devices such that occupational doses are ALARA. As available, the inspectors selected work activities where respiratory protection devices were used to limit the intake of radioactive materials, and verified that the licensee performed an evaluation concluding that further engineering controls were not practical and that the use of respirators was ALARA. The inspectors verified that the licensee had established means to verify that the level of protection provided by the respiratory protection devices during use was at least as good as that assumed in the licensees work controls and dose assessment.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Safety System Functional Failures (2 samples)

a. Inspection Scope

The inspectors sampled PBAPS's submittals for the Safety System Functional Failures (SSFFs) PI for both Unit 2 and Unit 3 for the period of October 1, 2011, through June 30, 2012. To determine the accuracy of the PI data reported during those periods, inspectors used definitions and guidance contained in the Nuclear Energy Institute (NEI)

Document 99-02, Regulatory Assessment PI Guideline, Revision 6, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 10 CFR 50.73." The inspectors reviewed PBAPS's operator narrative logs, operability assessments, MR records, maintenance WOs, CRs, event reports and NRC integrated inspection reports to validate the accuracy of the submittals.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure (IP) 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that PBAPS entered issues into the CAP at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the CAP and periodically attended CR screening meetings.

b. Findings and Observations

No findings were identified.

.2 Annual Sample: Review of Leakage in Gaskets, Seals, and Pressure Boundary

Components ===

a. Inspection Scope

This inspection verified that for a selected sample of component leaks, the leaks were appropriately identified, evaluated, and mitigated in accordance with requirements and plant procedures. The inspection scope included ASME Class 1, 2 and 3 systems, buried piping, FAC susceptible systems, and service water (GL-89-13) systems. The inspectors reviewed IR and action request (AR) reports of leakage in gaskets, seals and pressure boundary components. The leak locations reviewed, that were accessible during plant operation, were observed by the inspectors. The corrective and preventive actions taken to address the leaks were discussed with the Exelon engineering staff and managers. The inspectors verified that the Exelon process and procedures for addressing component leaks was appropriately applied for the sample of components reviewed.

b. Findings and Observations

No findings were identified.

The inspectors noted that for the components evaluated, the leaks were mitigated in accordance to the ASME Code requirements, plant procedures, industry standards, and NRC guidance.

Potential for Draining the Reactor Vessel (OPDRV) (1 sample)

a. Inspection Scope

The inspectors performed an in-depth review of PBAPS actions and response to NRC Enforcement Guidance Memorandum (EGM) 11-003, Dispositioning Boiling Water Reactor (BWR) Licensee Noncompliance with TS Containment Requirements during Operations with a Potential for Draining the Reactor Vessel (OPDRV). The purpose of the EGM was to improve regulatory clarity on the meaning of OPDRV as related to compliance with TSs, and to allow implementation of specific interim actions as an alternative to full compliance with plant Technical Specifications while NRC Standard Technical Specification (STS) improvements are developed. The EGM provided licensees with the option to implement the plain language definition of OPDRV for TS compliance, as clarified in the EGM; or meet specific compensatory measure requirements listed in the EGM during the performance of OPDRVs. The inspectors review included activities during the PBAPS Unit 2 RFO.

b. Findings and Observations

No findings were identified.

In response to EGM 11-003, PBAPS initiated CR 1273127, and changed the definition of OPDRV in the Technical Requirements Manual (TRM) to be consistent with the plain language definition of OPDRV. PBAPS elected to implement the plain language definition of OPDRV to comply with TS compliance during P2R19, and therefore, did not require the use of compensatory measures. Additionally, PBAPS intends to evaluate the final NRC STS change for applicability to the station, as stated in IR 1273127-04.

The inspectors verified that the revised TRM OPDRV definition was consistent with the plain language definition as clarified in EGM 11-003. The inspectors determined that PBAPS appropriately complied with TSs during the performance of OPDRV activities during P2R19.

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

Response to Unit 2 RB Contamination Event during Reactor Vessel Head Vent Disassembly On September 11, 2012, the inspectors responded to a contamination event on the Unit 2 refuel floor. PBAPS personnel were disconnecting the Unit 2 reactor head vent piping during reactor vessel disassembly during RFO P2R19. When the head vent flange was disconnected, MCR operators responded to an apparent lowering reactor level indication and raised reactor water level. The steam dryer assembly inside of the reactor vessel had not been fully cooled prior to the head vent flange disconnection, thereby causing some of the additional water inventory to flash to steam and exit the head vent as water level was raised. Continuous air monitors alarmed on the refuel floor and personnel took action in accordance with station procedures to evacuate the refuel floor. None of the refuel floor radiation monitors went into alarm. As a result of the event, several elevations in the RB became contaminated, and 47 individuals required follow-up radiation monitoring, which subsequently determined that the total effective dose equivalent for the maximally exposed individual was less than one percent of the annual occupational exposure limit. (See section 2RS1 of this report for the radiation protection inspector response and follow-up summary.)

The inspectors determined that PBAPS monitoring and evacuation of the refuel floor was in accordance with procedural controls. The radiation exposure to the personnel on the refuel floor was minimal, and all contamination was contained within the secondary containment boundary. MCR operators followed procedural controls for reactor head vent disassembly, and were using redundant means of level instrumentation during the reactor head vent disassembly. The inspectors determined that there was no uncontrolled loss of inventory during this event. The indicated drop in reactor level was attributed to unexpected conditions associated with the level instrumentation. The inspectors determined that the PBAPS response to this event was appropriate and thorough. PBAPS entered this issue into the CAP as IR 1411220 for root cause investigation and corrective action.

The inspectors used the SDP to evaluate the significance of the radiological aspects of this event, as well as the impact to reactor vessel inventory during shutdown conditions.

The inspectors reviewed IMC 0612, Appendix B, Issue Screening, and Appendix E, Examples of Minor Issues. The inspectors concluded that the consequences of this event were of minor safety significance. Although the inspectors determined that the consequences of this event were not more than minor, the inspectors also referenced IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, 1 - Phase 1, to ensure that PBAPS was maintaining adequate mitigation capability.

4OA6 Meetings, Including Exit

Quarterly Resident

Exit Meeting Summary

On October 22, 2012, the resident inspectors presented the inspection results to Mr. Garey Stathes, Peach Bottom Site Vice President, and other PBAPS staff, who acknowledged the findings. Mr. P. Krohn, Chief, USNRC, Region 1, Division of Reactor Projects, Branch 4, attended this quarterly inspection exit meeting. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

4OA7 Licensee-Identified Violation

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

10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality, such as defective material and equipment, are promptly identified and corrected. Contrary to the above, PBAPS did not promptly correct defective welds in the E-3 EDG lube oil piping that were identified in 1998. Specifically, PBAPS identified partial penetration welds in Fairbanks Morse EDG lube oil pump outlet piping in response to a 1997 Part 21 notification. PBAPS corrected the defective welds on the E-2 and E-4 piping in 1998, but did not correct the defective welds on the E-3 or E-1 based on vendor testing and data provided in the Final Part 21 Notification.

On September 3, 2012, PBAPS identified a leak on the E-3 lube oil pump outlet piping during surveillance testing. PBAPS subsequently declared E-3 inoperable and unavailable from September 3 to September 5, while corrective actions were performed to cut out the defective piping welds and re-weld the piping with full penetration welds. PBAPS determined the leak was a result of fatigue failure of the partial penetration weld. In 1998, PBAPS accepted the Final Part 21 Notification with no corrective action required on E-3 or E-1 based on the vendor testing and data, which did not include a vibration or fatigue analysis despite industry OE that specifically discussed vibration-induced fatigue failures of the EDG lube oil pump outlet piping at other stations with Fairbanks Morse EDGs. The inspectors reviewed PBAPSs planned corrective actions to address the E-1 partial penetration weld, and considered the scheduled repairs appropriate to the circumstances.

The inspectors determined that this violation screened to Green using the Table 4a screening criteria in Appendix A of IMC 0609, "SDP for Findings at Power, because there was no loss of the EDG system safety function. Because this finding is of very low safety significance, and has been entered into Exelon's CAP under IR 1408390, this violation is being treated as a Green NCV consistent with the NRCs Enforcement Policy.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Exelon Generation Company Personnel

G. Stathes, Site Vice President

P. Navin, Plant Manager

J. Armstrong, Regulatory Assurance Manager

T. Moore, Site Engineering Director

M. Herr, Operations Director

J. Kovalchick, Security Manager

P. Rau, Work Management Director

R. Reiner, Chemistry Manager

R. Holmes, Radiation Protection Manager

J. Bowers, Training Director

B. Henningan, Operations Training Manager

NRC Personnel

P. Krohn, Branch Chief

S. Hansell, Senior Resident Inspector

A. Ziedonis, Resident Inspector

J. Furia, Senior Health Physicist

H. Gray, Senior Reactor Inspector

A. Rosebrook, Senior Project Engineer

S. Ibarrola, Project Engineer

LIST OF ITEMS

OPENED, CLOSED, DISCUSSED

Opened

None

Opened/Closed

05000277/2012004-01 NCV Inadequate Preplanning and Performance of Maintenance/

Modifications Resulted in Unavailability of RHR B Loop (Section 1R13)

Closed

None Discussed/Closed None