IR 05000277/2012002

IR 05000277-12-002 & 05000278-12-002, on 01-01-12 - 03-31-12, Peach Bottom Atomic Power Station - NRC Integrated Inspection Report

ML12129A016
Person / Time
Site:	Peach Bottom
Issue date:	05/07/2012
From:	Paul Krohn Reactor Projects Region 1 Branch 4
To:	Pacilio M Exelon Nuclear, Exelon Generation Co
KROHN, PG
References
EA-11-224 IR-12-002
Download: ML12129A016 (49)

Text

UNITED STATES May 7, 2012

SUBJECT:

PEACH BOTTOM ATOMIC POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000277/2012002 AND 05000278/2012002

Dear Mr. Pacilio:

On March 31, 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 April 20, 2012, with Mr. Thomas Dougherty, 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 NRC-identified finding and two self-revealing findings of very low safety significance (Green). 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 the very low safety significance, and because they are 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 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, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the 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 the PBAPS. In accordance with Title 10 of the Code of Federal Regulations (CFR) 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 NRC's document 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 05000277/2012002 and 05000278/2012002 w/Attachment: Supplementary Information (Attachment 1)

Inspection Manual Chapter 0609, Appendix M, Table 4.1 (Attachment 2)

REGION I==

Docket Nos.: 50-277, 50-278 License Nos.: DPR-44, DPR-56 Report No.: 05000277/2012002 and 05000278/2012002 Licensee: Exelon Generation Company, LLC Facility: Peach Bottom Atomic Power Station, Units 2 and 3 Location: Delta, Pennsylvania Dates: January 1, 2012 through March 31, 2012 Inspectors: S. Hansell, Senior Resident Inspector A. Ziedonis, Resident Inspector J. Furia, Senior Health Physicist A. Rosebrook, Senior Project Engineer Approved by: Paul G. Krohn, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000277/2012002, 05000278/2012002; 01/01/2012 - 03/31/2012; Peach Bottom Atomic

Power Station (PBAPS), Units 2 and 3; Post Maintenance Testing and Identification and Resolution of Problems.

The report covered a three-month period of inspection by resident inspectors and an announced inspection by a senior health physicist. This report documents one NRC-identified and two self-revealing non-cited violations (NCVs). 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 findings were 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.

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

Green.

The inspectors determined that PBAPS did not establish measures to promptly identify and correct a condition adverse to the quality related to the emergency diesel generator (EDG) control power circuit. The performance deficiency (PD) constituted a Green, self-revealing NCV of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action." Specifically, measures established to identify and correct chronic control power light socket assembly internal faults were inadequate. Consequently, on February 18, 2012, the E-1 EDG local control power station experienced a short circuit event during control power indicating light bulb replacement. PBAPS entered into this issue into the corrective action program (CAP) via issue report (IR) 1328736.

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 and prevent undesirable consequences. Using IMC 0609,

Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined that this finding was of very low safety significance (Green) because it did not represent an actual loss of safety function for a single EDG train for a duration greater than its Technical Specification (TS) allowed outage time, and did not screen as potentially risk significant due to an external initiating event.

The inspectors determined that this finding had a cross-cutting aspect in the area of problem identification & resolution (PI&R), CAP, because PBAPS did not take appropriate corrective actions to address the adverse trend associated with chronic EDG control power circuit faults in a timely manner, commensurate with its safety significance P.1(d). (Section 1R19)

Green.

The inspectors determined that PBAPS did not promptly identify and correct residual heat removal (RHR) heat exchanger (HX) graphoil gasket leaks. The PD constituted a Green, self-revealing NCV of 10 CFR Part 50, Appendix B, Criterion XVI,

"Corrective Action. Specifically, measures established to identify and correct previous graphoil gasket leaks were inadequate to correct the condition adverse to quality.

Consequently, on February 16, 2012, the Unit 2 'C' RHRHX shell cover lower flange graphoil gasket failed during testing, rendering the 'C' RHR subsystem inoperable. PBAPS entered this issue into CAP via IR 1327477.

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 and prevent undesirable consequences. Using IMC 0609,

Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined that this finding was of very low safety significance (Green) because it did not represent an actual loss of safety function for a single RHR train for greater than its TS allowed outage time, and did not screen as potentially risk significant due to an external initiating event.

The inspectors determined that this finding had a cross-cutting aspect in the area of PI&R,

CAP, because PBAPS did not thoroughly evaluate previous graphoil gasket failures used in RHR HX applications to ensure the resolution addressed the cause and extent of condition P.1(c). (Section 1R19)

Green.

The inspectors identified a PD that was determined to be a finding of very low safety significance (Green) involving a NCV of 10 CFR Part 50, Appendix B, Criterion XVI,

Corrective Action, for the failure by PBAPS to take timely corrective action to correct a condition adverse to quality and the inability to comply with Design Technical Specification (TS) 4.3.1.1.b which requires, in part, that spent fuel pool (SFP) storage racks are designed and maintained with keff less than or equal to 0.95. Specifically, although PBAPS was aware of degradation of neutron absorbing material (Boraflex) within the SFP storage racks since at least 1996, PBAPS did not take effective measures to adequately monitor or manage the degradation to assure sufficient margin to criticality was maintained. Rather, in 2010,

PBAPS deferred corrective actions in the SFPs until 2014 based on an operability determination (OD) that concluded sufficient margin would exist until that time. However, the NRC concluded that the OD did not accurately project the rate of boron degradation, and used several non-conservative assumptions. In June 2011, after addressing the errors in the OD, PBAPS declared 117 spent fuel bundle rack storage cells inoperable since the estimated Boraflex degradation indicated that PBAPS had exceeded design TS 4.3.1.1.b.

The PD was more than minor because it was similar to IMC 0612, Appendix E, Examples of Minor Issues, Example 3.j, which considers that an issue is more than minor if an engineering calculation error results in a condition where there is now a reasonable doubt on the operability of a system or component, or if significant programmatic deficiencies were identified with the issue that could lead to more significant errors if uncorrected.

Using IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the inspectors attempted to evaluate the risk significance of this issue. Applying the guidance in Table 3b, the inspectors made the assumption that the risk associated with this PD most appropriately impacted the Initiating Events cornerstone. A Region I Senior Reactor Analyst (SRA) determined that there were no probabilistic risk assessment tools currently available to adequately assess the risk of a SFP criticality event. Consequently, the inspectors followed the guidance in the Phase 1 SDP screening worksheet, Table 3b,

Step 6, which states, in part, that where the SDP guidance is not adequate to provide reasonable estimates of a findings significance, use IMC 0609, Appendix M, SDP Using Qualitative Criteria.

Using Appendix M, the inspectors identified criteria and associated considerations that supported the overall qualitative risk assessment. On April 3, 2012, a Significance and Enforcement Review Panel (SERP) was conducted involving staff from Region I, the Office of Nuclear Reactor Regulation, and the Office of Enforcement to discuss the significance of this event. The SERP determined the PD and subsequent consequences resulted in a condition of very low safety significance (Green), based on an assessment using Appendix M attributes. This finding was also determined to have a cross-cutting aspect in the area of Problem Identification and Resolution - Evaluation P.1(c). Specifically, Exelon did not properly evaluate a condition adverse to quality for operability in that the 2010 OD did not accurately predict the rate of Boraflex degradation and whether the issue challenged current SFP operability P.1(c). (Section 4OA2)

Other Findings

One violation of very low safety significance that 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 number is listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 2 began the inspection period at 100 percent power. On January 14, 2012, operators reduced power to approximately 55 percent power to perform planned testing on control rods, main turbine valves, and main steam isolation valves; and to perform planned reactor feed pump (RFP) maintenance. The unit was returned to 100 percent power on January 15, where it remained until the end of the inspection period, except for brief periods to support control rod insertion and recovery associated with planned maintenance.

Unit 3 began the inspection period at 100 percent power. On January 28, 2012, operators reduced power to approximately 55 percent power to perform planned testing on control rods, main turbine valves, and main steam isolation valves; and to perform planned RFP maintenance. The unit was returned to 100 percent power on January 29, where it remained until the end of the inspection period, except for brief periods to support control rod insertion and recovery associated with planned maintenance.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors performed a review of PBAPSs response to high wind speeds in excess of 40 miles per hour on March 26, 2012. The review focused on the operability of emergency core cooling systems (ECCS), reactor building (RB) ventilation system, north and south electrical switchyard equipment, and site activities that could be impacted by the high winds. The inspectors reviewed operating procedure OP-AA-108-111-1001, Revision 6, Severe Weather and Natural Disaster Guidelines, control room alarm response card ARC-317 30C212R K-5, RB Hi-Lo Differential Pressure, TSs, control room logs, emergency action level (EAL) entry conditions, and the CAP to determine how the high winds impacted these systems, and to ensure PBAPS personnel had adequately prepared and responded to the challenges. The inspectors performed walkdowns of the selected systems to ensure station personnel identified issues that could challenge the operability and availability of the systems during the high wind conditions. Documents reviewed for each section of this inspection report are listed in the Attachment.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Partial System Walkdowns (71111.04Q - 5 samples)

a. Inspection Scope

The inspectors performed partial walkdowns of the following five systems:

• Unit 3 B loop core spray (CS) system during A loop unavailability for planned maintenance on January 3, 2012

• Unit 3 B loop RHR system during A loop unavailability for planned maintenance on January 9, 2012

• Unit 2 reactor core isolation cooling (RCIC) system during high pressure coolant injection (HPCI) system unavailability for planned maintenance on January 19, 2012

• Unit 3 HPCI system with RCIC system unavailable for planned maintenance on January 24, 2012

• Unit 3 A loop RHR system during B loop unavailability during planned maintenance on January 31, 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 updated final safety analysis report (UFSAR), TSs, work orders (WOs), condition reports (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 CAP for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Resident Inspector Quarterly Walkdowns

a. Inspection Scope

The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that PBAPS controlled combustible materials and ignition sources were controlled 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 3 RB, B and D CS rooms, elevation 91-6 inches on January 4, 2012 (fire zones 13A and 13B)

• Unit 3 RB, B and D RHR pump and HX rooms, elevations 91-6 inches and 116 on January 5, 2012 (fire zones 9 and 10)

• Unit 2 RB, RCIC room, elevation 88 on January 19, 2012 (fire zone 60)

• Unit 3 RB, A RHR pump and HX rooms, elevation 91-6 inches and 116 on January 30, 2012 (fire zone 12A)

• E-1 and E-3 EDG rooms on February 9, 2012 (fire zone 132)

b. Findings

No findings were identified.

.2 Fire Brigade Drill

a. Inspection Scope

The inspectors observed a fire brigade drill scenario on February 23, 2012. The drill involved a simulated fire in the Unit 3 turbine building, elevation 165, 4G4 electrical load center 13kV switchgear (fire zone 79A). The inspectors evaluated the fire brigades initial response time, proper retrieval of required gear and equipment, and implementation of fire-fighting strategies. The inspectors verified that PBAPS personnel identified deficiencies, openly discussed them in a self-critical manner at the debrief, and took appropriate corrective actions to improve performance. The inspectors evaluated the following attributes:

• Proper use of turnout gear and self-contained breathing apparatus

• Employment of appropriate fire-fighting techniques

• Sufficient fire-fighting equipment brought to the scene

• Effectiveness of command and control

• Search for victims and propagation of the fire into other plant areas

• Smoke removal operations

• Utilization of pre-planned strategies

• Adherence to the pre-planned drill scenario

• Drill objectives met

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Internal Flooding Review

a. Inspection Scope

The inspectors reviewed the UFSAR, the site flooding analysis, and plant procedures to assess susceptibilities involving internal flooding. The inspectors also reviewed the CAP to determine if PBAPS identified and corrected flooding problems and whether operator actions for coping with flooding were adequate. The inspectors focused on the Unit 2 and Unit 3 RB closed loop cooling room areas to verify the adequacy of equipment seals located below the flood line, floor and water penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, control circuits, and temporary or removable flood barriers.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the Unit 2 B CS room cooler and the Unit 3 A RHR HX maintenance on January 11, 2012, to determine the readiness and availability of both components to perform their safety functions. The inspectors reviewed the design basis for the components and verified PBAPSs commitments to NRC Generic Letter (GL)89-13. The inspectors reviewed the results of previous inspections of the 2 B CS room cooler and similar room coolers. The inspectors discussed the results of the most recent inspections of both components with site engineering staff and reviewed pictures of the as-found and as-left conditions. The inspectors verified that the CS room cooler and RHR HX performance was within the limits of the acceptance criteria.

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 testing on February 14, 2012, which included a main steam leak, primary containment isolation, and an anticipated transient without scram scenario. The inspectors evaluated operator performance during the simulated event and verified completion of risk significant operator actions, including the use of abnormal and emergency operating procedures. The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. The inspectors verified the accuracy and timeliness of the emergency classification made by the shift manager and the TS action statements entered by the shift technical advisor. Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

The inspectors observed the following activities in the main control room:

• Unit 2 power reduction from 100 percent to approximately 60 percent for planned maintenance and testing, removal of the C RFP from service for planned maintenance, and scram time testing on nightshift from January 13, 2012 to January 14, 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 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 structures, systems, and components (SSCs) 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 3 safety/relief valve (SRV) maintenance in response to SRV 71B thread seal leakage on February 1, 2, and 3, 2012

• E-2 EDG planned maintenance outage from February 7 to February 10, 2012

• Unit 2 main steam leak detection channel B failure on March 19, 20, and 21, 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 50.64(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.

• Planned maintenance on Unit 3 A loop of CS on January 4, 2012

• Planned maintenance on Unit 3 A loop of RHR and elevated plant risk on January 9, 2012

• Planned maintenance on Unit 3 HPCI system and elevated plant risk on January 18, 2012

• Planned maintenance on Unit 3 RCIC and elevated plant risk on January 25, 2012

• Planned maintenance on Unit 3 B RHR and elevated plant risk on January 30 and 31, 2012

• Unplanned Unit 3 half-scram condition and elevated plant risk on February 3, 2012

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed six ODs for the following degraded or non-conforming conditions:

• Unit 3 SRV 71C leakage on January 6, 2012

• Unit 3 A RHR HX leakage on January 10, 11, and 13, 2012

• Unit 3 main turbine No. 2 control valve pressure switch failure that provides a signal to the reactor protection system (RPS) on January 30, 2012

• E-2 EDG loss of control power indication at the local room panel on February 8, 2012

• Unit 2 and Unit 3 control rod operability during a postulated seismic event on February 8, 9, and 10, 2012

• Unit 2 and Unit 3 safety-related 4 kilovolt buses in response to operating experience regarding a postulated loss of a single voltage phase on February 14 and 15, 2012 The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determinations to assess whether TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and UFSAR to PBAPSs evaluations to determine whether the components or systems were operable. When compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were controlled properly by PBAPS. The inspectors determined, when appropriate, compliance with bounding limitations associated with the evaluations.

b. Findings

No findings were identified.

1R18 Plant Modifications

Temporary Modifications

a. Inspection Scope

The inspectors evaluated the temporary modifications below to determine whether the modification affected the safety functions of systems that are important to safety. The inspectors reviewed modification documents associated with the upgrade and design change, discussed the modification with engineers, and observed portions of the installation to verify that the temporary modification did not degrade the current design bases, licensing bases, and performance capability of the affected systems.

• ECR 09-00301, Limerick low level radiation waste storage at PBAPS on February 15, 2012

• ECR 12-00063, Unit 3 drywell equipment drain sump design change on February 28 and 29, 2012

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 3 A RHR HX flow verification after leak repair on January 10, 2012

• Unit 2 HPCI booster pump seal repairs on January 20, 2012

• Unit 3 RCIC motor-operated valve maintenance on January 26, 2012

• Unit 3 scram discharge volume level switch replacement on February 16, 2012

• EDG E-1 control power repairs on February 21, 2012

• Unit 2 C RHR HX leak repair on February 29, 2012

• Unit 2 main steam leak detection system on March 19, 2012

b. Findings

===.1

Introduction.

The inspectors determined that PBAPS did not establish measures to===

promptly identify and correct a condition adverse to the quality related to the EDG control power circuit. The PD constituted a Green, self-revealing NCV of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action." Specifically, measures established to identify and correct chronic control power light socket assembly internal faults were inadequate. Consequently, on February 18, 2012, the E-1 EDG local control power station experienced a short circuit event during control power indicating light bulb replacement.

Description.

On February 18, 2012, during replacement of the local control power station indicating light bulb at the E-1 EDG, the replacement bulb failed a few seconds after installation. The inside of the panel was inspected, and it was identified that the light socket short circuited, which caused significant damage to the socket, melted the wiring on the neutral side of the socket, and also caused collateral damage to nearby wiring inside the control panel. The inspectors noted that this event did occur in an emergency preparedness vital area, but there was no fire associated with the event.

Additionally, the local control power station contained wiring circuitry associated with EDG automatic start features. PBAPS operators determined that alternate indications for EDG control power demonstrated that there was no actual loss of control power.

However, operators declared the E-1 EDG inoperable and unavailable for damage inspection, troubleshooting, and wiring repairs. PBAPS conducted inspections of all local wiring, and confirmed through electrical continuity testing that all features associated with EDG automatic start circuitry remained functional. Therefore, there was no actual loss of EDG safety function as a result of this event. The inspectors noted that PBAPS did replace several pieces of wiring due to insulation damage, and the light socket assembly was also replaced.

The inspectors noted chronic issues with EDG loss of local control power indication over several years. PBAPS performed an apparent cause investigation for the EDG control power indicating light bulb short circuit event, which included a summary of the historical issues with EDG local control power indication:

• 1993 - E-3 EDG local control power panel socket shorted out during light bulb replacement, causing wiring damage, which blew the control power fuse and made E-3 inoperable and unavailable. The light socket assembly was replaced.

• 2009 - E-4 EDG local control power panel socket shorted out during light bulb replacement, causing a small fire (which was extinguished in under 15 minutes) and wiring damage. The short circuit event occurred during an E-4 maintenance outage, thereby extending the period of inoperability for additional corrective maintenance activities. The cause of the event was attributed to aging of the control power socket assembly, as the assembly was original to the E-4 EDG. The control power light assembly was replaced on the E-4, as well as all the EDGs as an extent of condition action. This constituted a missed opportunity to identify the 1993 event on E-3 and include it with the E-4 failure evaluation.

• 2010 - E-2 and E-3 control power light bulbs found extinguished in June. E-2 was found extinushed again in August. All bulbs were successfully replaced.

• 2011 - E-2 control power light bulb found extinguished in January (successfully replaced), February (no clear documentation of replacement), and April. Following identification in April, a CAP engineering investigation concluded that a poor connection was likely introduced during the 2010 socket replacement, and recommended replacing the fixture during E-2 planned maintenance in early 2012. This constituted another missed opportunity to identify the cause of the chronic adverse condition common to all the EDGs and correct the condition.

Subsequently, the E-2 control power light bulb was again found extinguished in July, and successfully replaced. In November, the E-1 control power light bulb was found extinguished, and was successfully replaced.

• 2012 - E-1 control power light bulb found extinguished in January (no clear documentation of replacement), and again in early February. On February 18, E-1 control power light bulb was replaced and subsequently short circuited. The light socket assembly and bulb were replaced and an apparent cause investigation was conducted.

PBAPS's apparent cause investigation determined that the cause of the light socket failure was attributed to a sustained high energy electrical fault between the internal terminals of the incandescent light socket. The electrical fault was caused by long-term tracking and micro-arcing that occurred between the two internal incandescent lamp terminals, with carbon build up developing on the material surface of the terminals, thus developing a fault path along the two internal lamp terminals. PBAPS also concluded that moisture and contaminants from outside air in the EDG room would accelerate the development of the internal fault path. PBAPS concluded that a contributing cause of the February 18, 2012, E-1 short circuit event was attributed to the failure to take corrective measures to address chronic light socket assembly problems in a timely manner. Planned corrective actions to address this condition adverse to quality include modifying the current incandescent socket assemblies on all four EDGs to a light emitting diode (LED)-style socket assembly, which has lower current draw and voltage drop, thereby causing less micro-arcing and carbon collection. Additionally, PBAPS determined that the use of LED's will reduce the probability of a short circuit event due to an improved expected operating life compared to the incandescent-style indicating lights, as well as the lack of cold filament in-rush currents. The inspectors determined that PBAPS's planned corrective actions were appropriate to the circumstances.

Analysis.

The inspectors determined that PBAPS not establishing measures to promptly identify and correct a condition adverse to quality related to the EDG control power circuit constituted a PD. Consequently, on February 18, 2012, the E-1 EDG local control power station experienced a short circuit event during control power indicating light bulb replacement. 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 response to initiating events to prevent undesirable consequences.

Specifically, the E-1 EDG was declared inoperable and unavailable, and local control power panel inspections revealed significant damage to the light socket, melted wire on the neutral side of the socket, and local wiring insulation damage. Using IMC 0609, 4, Phase 1 - Initial Screening and Characterization of Findings, 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 EDG train for greater than its TS allowed outage time, and did not screen as potentially risk significant due to an external initiating event.

The inspectors determined that this finding had a cross-cutting aspect in the area of PI&R, CAP, because PBAPS did not take appropriate corrective action to address an adverse trend in a timely manner, commensurate with its safety significance P.1(d).

Specifically, PBAPS did not take appropriate corrective actions to address the adverse trend associated with EDG chronic control power circuit internal faults.

Enforcement.

10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," states, in part, that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, prior to February 2012, PBAPS did not establish measures to promptly identify and correct a condition adverse to the quality of the EDG control power circuit. Specifically, measures established to identify and correct chronic control power light socket assembly internal faults were inadequate. Consequently, on February 18, 2012, the E-1 EDG local control power station experienced a short circuit event during control power indicating light bulb replacement. Because this finding was of very low safety significance and it was entered into the CAP via IR 1328736, this violation is being treated as an NCV consistent with the Enforcement Policy. (NCV 05000277/2012002-01 and

===05000278/2012002-01, Inadequate Corrective Action to Address Emergency Diesel Generator Control Power Circuit Chronic Internal Faults)

===.2

Introduction.

The inspectors determined that PBAPS did not promptly identify and===

correct RHR HX graphoil gasket leaks. The PD constituted a Green, self-revealing NCV of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action. Specifically, measures established to identify and correct previous graphoil gasket leaks were inadequate to correct the condition adverse to quality. Consequently, on February 16, 2012, the Unit 2 'C' RHR HX shell cover lower flange graphoil gasket failed during testing, rendering the 'C' RHR subsystem inoperable.

Description.

On February 16, 2012, during surveillance testing of the Unit 2 'C' RHR subsystem, the 'C' RHR HX shell lower flange gasket extruded, resulting in a continuous spray of water from the lower shell flange area. The leak rate was not quantified, and rendered the 'C' RHR subsystem inoperable thereby placing Unit 2 in a limited condition of operation (LCO) of 7-days per TSs. The surveillance testing was part of post-maintenance testing (PMT) to return the 'A loop of RHR to operation following planned maintenance. The 'A' subsystem had successfully completed its surveillance prior to the

'C' RHR HX leakage. The planned maintenance outage on the 'A' RHR loop had just entered day 4 of 7 of the LCO, and with the 'C' RHR pump inoperable due to the 'C' subsystem leakage, Unit 2 was in day 4 of the 7-day LCO with one RHR pump inoperable. No HX maintenance had been performed during the 'A' RHR loop maintenance outage.

PBAPS maintenance personnel removed the 'C' HX lower shell cover and discovered a graphoil style gasket, which is composed of thin layers of stainless steel embedded in graphite. The gasket had extruded in the northeast quadrant of the flange, and the HX flange face was discovered to have some areas of protruding metal on the edge of the gasket in the area of the failure. The remaining areas of the HX flange were in good condition, as well as the lower shell head flange.

The graphoil gasket was installed on the lower shell flange, as well as on the floating seating surface in 2009, during maintenance to replace the floating head due to internal tube-to-shell leakage. The RHR HXs are floating head type shell-and-tube HXs, which are designed to account for thermal expansion and contraction of the tube sheet over a wide range of fluid temperatures. The graphoil gasket was installed on the floating head in 2009 to accommodate the pitting and degradation of the floating head seating surface.

Graphoil gaskets are more accommodating to surface imperfections than the original style soft iron gaskets that had been used previously on both the floating head as well as the lower shell cover flange.

In 2010, the 'C' RHR HX developed another internal leak on the floating head. An apparent cause evaluation determined that the graphoil gaskets are susceptible to accelerated erosion of the gasket seating surface due to the graphite and stainless steel foil construction of the gasket. The apparent cause evaluation (ACE) also determined that the lower torque requirements of the graphoil gasket were another contributor to the gasket failure. In 2010, the 'C' RHR HX floating head seating surface was machined to remove the pitting imperfections, and the original style soft iron gasket was installed on the floating head. The 2010 ACE assigned an action to only use soft iron gaskets on the floating heads, and remove all other style floating head gaskets from stock. However, the graphoil style gasket was installed on the RHR HX lower shell cover flange.

Additionally, the action to remove the graphoil gaskets from stock was never performed, and had been assigned a lower level administrative code that does not require completion within the Exelon corrective action process.

The inspectors noted that PBAPS has a history of challenges in the area of RHR HX leakage:

• 2007 - Unit 3 'D' (3D) floating head leak repair, soft iron gasket used

• 2008 - 3 D lower shell cover flange leak repair, soft iron gasket used

• 2008 - 2 D floating head leak repair, graphoil gasket used

• 2009 - 2 C floating head leak repair, graphoil gasket used on floating head and lower shell cover

• 2010 - 2 C floating head leak. Floating head seating surface machined and soft iron floating head installed. Graphoil gasket installed on lower head shell flange.

• 2011 - 3 A floating head leak. Seating surface machined, soft iron gasket installed.

Graphoil lower head shell flange gasket installed.

• 2012 - 3 A and 2 C lower shell cover leaks. Small leak on 3 A bottom head, head retorqued, leak stopped. Gasket extruded on 2 C lower shell cover, replaced with soft iron gasket, leakage stopped.

Corrective action to address the February 16, 2012, 2 C RHR HX leakage was completed prior to exceeding the 7-day LCO action statement. Following the 2012 graphoil gasket failure on the 2 C RHR HX, PBAPS conducted another apparent cause investigation. PBAPS identified similar apparent and contributing causes from the 2010 evaluation related to graphoil erosion susceptibility and lower torque requirements of the graphoil gasket, and also identified additional causes related to torquing. Specifically, PBAPS determined that graphoil gaskets require additional torque passes following initial installation, especially given bolt relaxation and loss of preload following RHR HX fluid seasonal temperature changes and pressure changes during removal of the stayfill system for planned maintenance. Additionally, PBAPS determined that once a small leak develops across the graphoil gasket, the gasket is more susceptible to complete failure unless additional torquing is performed.

PBAPS noted that the 2012 leak from the 2 C RHR HX followed the removal and subsequent return of the stayfill system from service. Prior to graphoil gasket failure, a small leak developed on the 2 C RHR HX during ST of the 'A' RHR subsystem.

Subsequently, when the 2 C RHR pump was started for the 'C' subsystem surveillance, the 'C' graphoil gasket failed completely. PBAPS also noted that for the 3 A RHR HX lower shell leak, the leakage was small and was corrected with additional torque passes.

No additional torque passes were performed on the 2 C HX following the identification of small leakage prior to 2 C RHR pump start and complete gasket failure.

PBAPS concluded, via the 2012 ACE, that although the graphoil gaskets were rated for RHR HX system pressure and temperature, they were not the preferred gasket style for RHR HX applications. PBAPS has created corrective action assignments to remove the graphoil gaskets from stock, and also to replace the graphoil gaskets on the remaining RHR heat exchanges (3 A, 2 D and 2 C) with the original style soft iron gaskets at the next appropriate maintenance opportunity. The inspectors noted that PBAPS has evaluated interim operation of the graphoil gaskets on the remaining RHR HXs, and determined that it is acceptable. The inspectors determined that PBAPS's corrective actions are appropriate to the circumstances.

Analysis.

The inspectors determined that PBAPS's failure to establish measures to promptly identify and correct repetitive RHR HX graphoil gasket leaks constituted a PD.

Consequently, on February 16, 2012, the Unit 2 'C' RHR HX shell cover lower flange graphoil gasket failed during testing, rendering the 'C' RHR subsystem inoperable. 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. Using IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined that this finding was of very low safety significance (Green) because it did not represent an actual loss of safety function for a single RHR train for greater than its TS allowed outage time, and did not screen as potentially risk significant due to an external initiating event.

The inspectors determined that this finding had a cross-cutting aspect in the area of PI&R, CAP, because PBAPS did not thoroughly evaluate a problem such that resolution addressed the cause and extent of condition, as necessary P.1(c). Specifically, PBAPS did not thoroughly evaluate previous graphoil gasket failures used in RHR HX applications, which resulted in the Unit 2 'C' RHR HX shell cover lower flange graphoil gasket failure on February 16, 2012.

Enforcement.

10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," states, in part, that measure shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, PBAPS did not establish measures to promptly identify and correct repetitive RHR HX graphoil gasket leaks.

Specifically, measures established to identify and correct previous graphoil gasket leaks were inadequate to correct the condition adverse to quality. Consequently, on February 16, 2012, the Unit 2 'C' RHR HX shell cover lower flange graphoil gasket failed during testing, rendering the 'C' RHR subsystem inoperable. Because this finding was of very low safety significance and it was entered into the CAP via IR 1327477, this violation is being treated as an NCV consistent with the Enforcement Policy. (NCV 05000277/2012002-02, Inadequate Corrective Action to Address Residual Heat Removal Heat Exchanger Graphite Gasket Leaks)

1R22 Surveillance Testing

a. Inspection Scope

(5 routine surveillances and 2 in-service test samples)

The inspectors observed performance of 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:

• Unit 2 RCIC logic system functional test on January 4, 2012 (in-service test)

• Unit 2 control rod scram time testing on January 14, 2012

• E-4 EDG fast start testing on January 23, 2012 (in-service test)

• Main stack radiation monitor function check on February 16, 2012

• Diesel-driven fire pump operability test on March 13, 2012

• A Emergency service water pump, valve, unit cooler, and emergency cooling tower functional inservice test on March 14, 2012

• Flow testing of new diesel-driven high capacity portable pump on March 24, 2012

b. Findings

No findings were identified.

1EP6 EP Drill Evaluation

a. Inspection Scope

The inspectors evaluated the conduct of a PBAPS emergency exercise on March 27, 2012, to identify any weaknesses and deficiencies in the classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator and technical support center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the simulator critique to compare inspector observations with those identified by PBAPS staff in order to evaluate PBAPSs critique and to verify whether the PBAPS staff was properly identifying weaknesses and entering them into the corrective action program.

b. Findings

No findings were identified.

2RS0 1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

The inspectors conducted walk downs of the facility, including radioactive waste processing, storage, and handling areas to evaluate material conditions and potential radiological conditions.

The inspectors selected containers holding nonexempt licensed radioactive materials that may cause unplanned or inadvertent exposure of workers, and verified that they were labeled and controlled.

The inspectors observed several locations where the licensee monitors potentially contaminated material leaving the radiologically controlled area, and inspected the methods used for control, survey, and release from these areas. The inspectors verified that the radiation monitoring instrumentation had appropriate sensitivity for the types of radiation present.

During tours of the facility and review of ongoing work, the inspectors evaluated ambient radiological conditions. The inspectors verified that existing conditions were consistent with posted surveys, radiation work permits, and worker briefings, as applicable.

b. Findings

No findings were identified.

2RS0 2 Occupational As Low As is Reasonably Achievable Planning and Controls

a. Inspection Scope

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 determined the plants three-year rolling average collective exposure.

The inspectors determined the site-specific trends in collective exposures and source term measurements.

The inspectors reviewed site-specific procedures associated with maintaining occupational exposures As Low As is Reasonably Achievable (ALARA) which included a review of processes used to estimate and track exposures from specific work activities.

b. Findings

No findings were identified.

2RS0 5 Radiation Monitoring Instrumentation

a. Inspection Scope

The inspectors selected portable survey instruments in use or available for issuance.

The inspectors checked calibration and source check stickers for currency, and assessed instrument material condition and operability.

The inspectors walked down area radiation monitors and continuous air monitors to determine whether they were appropriately positioned relative to the radiation sources or areas they were intended to monitor.

The inspectors selected personnel contamination monitors and small article monitors to verify that the periodic source checks were performed in accordance with the manufacturers recommendations and licensee procedures.

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 71152, PI&R, 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

No findings were identified.

.2 Closed Unresolved Item (URI) 05000277&278/2010-004-01, Non-conservative TS and

Potential Non-compliance Associated with Degraded Spent Fuel Pool Boraflex Panels

=

Inspection Scope NRC Inspection Report 05000277 and 05000278/2010-004 opened an URI associated with a concern about the operability of the SFP due to degraded Boraflex panels. The inspectors closed this URI by reviewing Exelon and NRC documents including: Peach Bottoms 2007 License Amendment Request (LAR) to change TS 4.3.1.1.a; Peach Bottoms withdrawl letter for this LAR (ML101690377); Peach Bottoms operability evaluation 10-007, corrective actions needed for SFP Boraflex degradation (IR1127773); NRC TIA 11-004, SFP criticality with 45% B-10 loss (Technical Evaluation, Revision 3 -IR 864431-15), and LER 05000277/11-002. The inspectors assessed the technical adequacy of the operability evaluations, the use and control of compensatory measures, and compliance with the licensing and design bases. The inspectors also reviewed the compensatory actions taken by Peach Bottom after SFP cells were declared inoperable in June 2011.

On April 3, 2012, a Significance and Enforcement Review Panel (SERP) was conducted with personnel from Region I, the Office of Nuclear Reactor Regulation, and the Office of Enforcement to discuss the significance of this event.

The NRC identified a NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the failure by the PBAPS to take timely corrective action to correct a condition adverse to quality (CAQ) and failure to meet TS 4.3.1.1.b. This NCV is documented below. No additional findings were identified. URI 05000277 &

05000278/2010004-01 is closed.

a. Findings and Observations

Untimely Corrective Actions Resulted in SFP Boraflex Degradation Exceeding Design Limits

Introduction.

The inspectors identified a PD that was determined to be a finding of very low safety significance (Green) involving a NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the failure by PBAPS to take timely corrective action to correct a condition adverse to quality (CAQ) and failure to meet TS 4.3.1.1.b which requires, in part, that SFP storage racks are designed and maintained with keff less than or equal to 0.95. Specifically, although PBAPS was aware of degradation of neutron absorbing material (Boraflex) within the SFP storage racks since at least 1996, the licensee did not take effective measures to adequately monitor or manage the degradation to assure sufficient margin to criticality was maintained. Rather, in 2010, PBAPS deferred corrective actions in the SFPs until 2014 based on an OD that concluded sufficient margin would exist until that time. However, the NRC concluded that the OD did not accurately project the rate of boron degradation, and used several non-conservative assumptions. In June 2011, after addressing the errors in the OD, PBAPS declared 117 cells inoperable since the estimated Boraflex degradation indicated that PBAPS had exceeded design TS 4.3.1.1.b.

Description.

This issue was previously discussed in the 3rd quarter 2010 Integrated Inspection Report (50-277&278/2010004) as unresolved item (URI) 05000277, 278/2010004-01. Since the 1970s, the industry has been aware that Boraflex in an SFP environment degrades. In 1996, the NRC issued GL 1996-04, Boraflex Degradation in SFP Storage Racks, to alert the industry to these concerns, and requested each licensee crediting Boraflex to provide the NRC with its plan to manage the degradation.

PBAPSs plan involved using the analytical code, RACKLIFE, every six months to predict future degradation of Boraflex in its SFPs. In addition, to determine actual degradation levels, PBAPS implemented in-situ testing of 100 percent of its racks every four years using the B-10 Areal Density Gauge for Evaluating Racks (BADGER) tool.

PBAPS used the BADGER results to benchmark the RACKLIFE predictions. It should be noted that the NRC has not, to date, approved the use of BADGER or RACKLIFE.

In 2000, PBAPS obtained a vendor analysis to determine the amount of Boraflex degradation that could occur while still meeting the regulatory sub-criticality design criterion of keff (i.e., the effective neutron multiplication factor) 0.95, as specified in TS 4.3.1.1.b. The analysis concluded that keff could be met in the SFPs with uniform degradation of up to 10 percent, when averaged across all panels in the spent fuel racks (equating to an average areal density of 0.0189 g/cm2).

In June 2008, using the guidance in NRC Administrative Letter 98-10, PBAPS requested a license amendment to reduce the TS kinf value (the neutron multiplication factor for an infinite array of fuel configured in the standard, uncontrolled, reactor geometry at cold conditions), based on BADGER/ RACKLIFE analyses which indicated that average Boraflex degradation in the PB2 SFP racks would exceed 10 percent in the fall of 2008.

At that point, PB concluded the kinf TS limit of < 1.362 would be non-conservative, meaning that compliance with that value would no longer assure that the in-rack keff limit of 0.95 would not be exceeded. On June 18, 2010, PBAPS withdrew the license amendment request, after several rounds of NRC requests for additional information (RAIs) to better understand how PB obtained and verified its analyses. A number of the RAIs were issued to address NRC questions related to the use of BADGER and RACKLIFE, which was being proposed for use as the new code of record.

In 2009, Region I issued a Severity Level IV (SL IV) NCV to PBAPS because the licensee was using analytic tools that were different than described in their UFSAR.

Also, since August 2009 PBAPS has corrected the issue and has implemented an administrative control (documented in PBAPSs SFP and core fuel move process procedure) to ensure the most reactive fuel bundles (once burned fuel having spent two years in the reactor core) are not placed in a SFP rack cell that has > 20 percent boron carbide degradation. The NRC resident inspectors at PBAPS have verified that this administrative control has been followed and noted that since 2009, once burnt fuel assemblies were only present in the PB2 or PB3 SFPs for a maximum of 4.5 days during the refueling outages.

Subsequently, to address the now non-conservative TS kinf limit and to evaluate the acceptability of the Boraflex degradation, PB conducted an OD of the SFPs. In the OD, PB concluded that, with administrative limits on the reactivity of the fuel added to the SFPs, Keff would conservatively remain below 0.95 until the maximum Boraflex degradation reached approximately 45% in 2014. Specifically, PB determined that SFP storage cells loaded with fuel assemblies having a peak kinf of 1.26 and with an areal density 0.01155 g/cm2 (45% degradation) would continue to meet the TS requirement for the SFP keff to be 0.95. It is noted that the most degraded rack cells are located in the PB2 SFP, and were measured using BADGER. The January 2010 data showed SFP rack storage cells degraded to an areal density of 0.0169 g/cm2 (19.5%) and projected (by RACKLIFE) to have further degraded to 0.0146 g/cm2 (30.5%) as of November 1, 2010.

During the 3rd quarter of 2010, the NRC resident inspectors at PBAPS reviewed PBAPSs OD, and concluded that assistance from NRC headquarters experts was needed to determine its technical adequacy and correctness. An URI was documented in the 3rd quarter integrated Inspection Report (05000277 & 05000278/2010004), and on January 25, 2011, Region I sent Task Interface Agreement (TIA)11-004, requesting that NRC headquarters evaluate the OD and independently estimate when the PB SFPs operability would be challenged.

Ultimately, the NRC determined that PBs OD and supporting documents did not provide reasonable assurance of SFP operability beyond 2014 without additional compensatory measures. Specific concerns included:

• PBAPS indicated that the degradation limit of 45 percent was determined using the minimum areal density reference value of 0.0210 g/cm2, however, Nuclear Reactor Regulation (NRR) determined that the 45 percent limit actually appeared to have been arrived at using the average areal density reference value (0.0235 g/cm2),indicating that PBAPSs 45 percent limit may be incorrect and non-conservative;

• It did not appear that PBAPS recalibrated the RACKLIFE predictions based on the BADGER results obtained in 2006, which could affect the results for subsequent predictions, including the prediction that operability would not be challenged until 2014;

• It did not appear that PBAPS performed a RACKLIFE analysis in 2011, and the degradation rate PBAPS used for this period inexplicably indicated that the degradation rate was decreasing;

• Between mid-2009 and early 2010, the degradation rate appeared to have significantly increased, and this trend was not carried forward in PBAPSs predicted future degradation rates; and

• PBAPS did not appear to have updated its OD with the RACKLIFE projection from November 2010, and the inclusion of this data could result in the degradation limit being reached earlier than PBAPS had predicted.

The NRC concluded that the Boraflex degradation limit in the PB2 SFP would not exceed PBAPSs OD degradation limit (0.01155 g/cm2) until mid-2011. However, the NRC also determined that an areal density of 0.01504 g/cm2 (36% of 0.0235 g/cm2)would be a more appropriate minimum acceptable value, based on the NRCs analysis.

As of November 2010, PBAPS determined that several Boraflex panels had already exceeded the above value.

On June 8, 2011, PBAPS determined that it no longer had reasonable assurance that all storage locations in the PB2 SFP remained capable of maintaining compliance with the TS limit of Keff

.095 under worst case design conditions. After performing a new

analysis, PBAPS determined that as of November 2010, 117 cells in the PB2 SFP were inoperable, in that, if they were loaded with fuel higher than kinf of 1.0473, the 0.95 keff limit would have been exceeded. PBAPS further determined that 27 additional cells would be inoperable by the end of 2011 (a total of 144 cells out of 3819). This analysis also determined that the PB2 SFP racks first exceeded the TS limits in approximately the fourth quarter of 2008.

As of June 12, 2011, PBAPS had relocated the spent fuel assemblies from the 144 affected PB2 SFP cells and from 57 additional cells with reduced margin, and declared those cells inoperable. Additionally, PBAPS relocated 84 spent fuel assemblies within the PB3 SFP (although no PB3 SFP cells were determined to be inoperable). PBAPS also established additional administrative controls to govern the use of the affected cells so as to not exceed the subcriticality margin requirements. PBAPS is designing a SFP modification as a long-term corrective action. PBAPS issued Licensee Event Report (LER) No.11-002 on July 29, 2011, to document the TS violation.

A follow-up PI&R sample inspection was conducted by the Region I Division of Reactor Safety Operations Branch during November 2011. PBAPS provided an updated analysis to the inspector which challenged one of the TIAs assumptions, claiming, in part, that PBAPS had been charged a redundant reactivity penalty. For design basis conditions, Exelon asserted that the max Keff for the pool was 0.95002, using all the other TIA assumptions and BADGER data for June 2011. Notwithstanding, the inspectors identified the June 2011 BADGER data indicated 9 cells with 50% to 51%

degradation.

In November 2011, during the PI&R sample inspection, DRS inspected PBAPSs compensatory actions taken and administrative controls in place, and determined that these actions were appropriate to ensure continued safe operations, until the issue can be addressed via PBAPSs proposed SFP Insert Modification and LAR (submitted to the NRC on November 3, 2011, and supplemented on December 22, 2011), which is currently under NRC review. This LAR also introduced a new code of record replacing the original Westinghouse criticality code of 1986 used in the current approved NRC SFP Safety

Analysis.

Using the updated computer code, PB would be able to demonstrate there is additional margin to the TS Keff limit.

In February 2012, an NRC subject matter expert reviewed Exelons assertion of a redundant reactivity penalty, and determined that Exelons position was not valid and that the reactivity penalties imposed by the TIA were not redundant. In summary, neither the NRC TIA, the NRC evaluation of the PBAPS post-TIA Technical Evaluation, the 2010 PBAPS OD, nor the 2011 PBAPS Technical Evaluation supported compliance with TS 4.3.1.1.b for design case conditions.

Analysis.

The failure of PBAPS to take timely corrective action to correct a CAQ is considered a PD that was reasonably within Exelons ability to foresee and prevent.

Specifically, PBAPS has been aware of degradation of neutron absorbing material (Boraflex) within the SFP storage racks since at least 1996 and did not take effective measures to adequately monitor or manage the degradation to assure sufficient margin to criticality was maintained. Rather, in 2010, PBAPS deferred corrective actions in the SFPs until 2014 based on an OD that concluded sufficient margin would exist until that time. However, the NRC concluded that the OD did not accurately project the rate of boron degradation, and used several non- conservative assumptions. In June 2011, measured degradation indicated PBAPS had exceeded design TS 4.3.1.1.b.

The PD was more than minor because it was similar to IMC 0612 Appendix E, Examples of Minor Issues, Example 3.j, which indicates that an issue is more than minor if an engineering calculation error results in a condition where there is now a reasonable doubt on the operability of a system or component, or if significant programmatic deficiencies were identified with the issue that could lead to worse errors if uncorrected.

Using IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the inspectors attempted to evaluate the risk significance of this issue.

Applying the guidance in Table 3b, the inspectors made the assumption that the risk associated with this PD most appropriately impacted the Initiating Events cornerstone. A Region I SRA determined that there are no probabilistic risk assessment tools currently available to adequately assess the risk of a SFP criticality event. Consequently, the inspectors followed the guidance in the Phase 1 SDP screening worksheet Table 3b, Step 6, which states, in part, that where the SDP guidance is not adequate to provide reasonable estimates of a findings significance, use IMC 0609, Appendix M, SDP Using Qualitative Criteria.

Using Appendix M, the team identified criteria and associated considerations that supported an overall qualitative risk assessment. These criteria and considerations are provided in Attachment 2 to this report. The fact that multiple criteria were met in the Appendix M worksheet did not reflect on significance, and reflected only that they were items to be considered to assist management in reaching a significance determination.

On April 3, 2012, a Significance and Enforcement Review Panel (SERP) was conducted with personnel from Region I, the Office of Nuclear Reactor Regulation, and the Office of Enforcement to discuss the significance of this event. The SERP determined the PD and subsequent consequences resulted in a condition of very low safety significance (Green), based on assessment of Appendix M attributes and the factors (including actual conditions and design information) discussed below. The primary difficulty in this case was that the condition that was exceeded is a design TS which assumes worst case conditions, maximum fuel loading considerations, and a credible error (such as a dropped fuel assembly and mispositioning event). Furthermore, there is no TS action statement for the design TS to use as a guide for assessing risk. Since the degradation is bounded by the fourth quarter of 2008 (when the most degraded cells first exceeded the NRC TIA value of 36 percent degradation), the NRC determined that it is appropriate to consider the likelihood of actual SFP conditions reaching design conditions following that specific time period as well as the consequences of a potential criticality event to assess the risk.

PBAPS has been monitoring its entire SFPs since the mid 1990s with the most commonly used analytic software programs available to the industry (BADGER and RACKLIFE). Since August 2009, PBAPS has implemented an administrative control (documented in the PBAPS SFP and core fuel move process procedure) to ensure the most reactive fuel bundles (once burned fuel having spent two years in the reactor core)are not placed in SFP rack cell that has > 20 percent boron carbide degradation. The NRC resident inspectors at PBAPS have verified that this administrative control has been followed.

The NRC considered that the implementation of these controls in August 2009, prior to the identification of this issue and PBAPSs licensee event report (LER), has ensured that the actual conditions in the SFPs never exceeded the Keff 0.95 limit. Further, since exceeding the Keff 0.95 design limit would require a critical configuration of 5-6 adjacent high energy cells, the NRC concluded that the probability that multiple mispositioning events could have occurred is minimal. In addition, PBAPS identified the refueling loading issue (i.e., concentration of high reactivity assemblies in the portion of the SFP closest to the reactor cavity) as the root cause of the highest degradation cells in the 2008 LAR. Further, PBAPS was aware of the issue and was taking steps to evaluate and address it, as evidenced by the administrative controls, the 2008 LAR, and the long term solution to install SFP rack boron inserts.

In addition, the NRC considered that based on the reactivity of the fuel that was actually used at PBAPS during this time period (fourth quarter 2008 to June 2011), the probability of meeting the design worst case assumptions and causing the TS Keff limit to actually be exceeded was minimal. In the OD, PBAPS calculated that the TS Keff, limit had been exceeded; assuming the SFP cells each contained the most reactive bundle that has ever been present at PBAPS. The licensee determined that this was GE11 9x9 fuel with an in-core Kinf of 1.2344. However, this type of fuel was last loaded in PB2 in 1994, and was removed from the core in 2000. The licensee determined that, during the time period in question, the highest Kinf value of any fuel used in either unit was no greater than in-core Kinf of 1.2165. Further, of the 201 PB2 SFP cells where fuel assemblies were removed, the 74 most reactive assemblies had peak reactivity (as calculated by PBAPS staff) of 1.0473. The NRC concluded that the likelihood of the Keff limit being exceeded based on the reactivity values of the fuel assemblies actually present on site during this period of vulnerability was extremely low.

Given the above considerations, the NRC determined that this case was of very low safety significance (Green). This finding was also determined to have a cross-cutting aspect in the area of Problem Identification and Resolution - Evaluation (P.1(c)).

Specifically, Exelon failed to properly evaluate a condition adverse to quality for operability, in that, the 2010 OD did not accurately predict the rate of Boraflex degradation and whether the issue challenged current operability.

Enforcement.

10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that conditions adverse to quality such as equipment deficiencies and malfunctions shall be promptly identified and corrected. Design TS 4.3.1.1.b states, in part, that, SFP storage racks are designed and shall be maintained with keff less than or equal to 0.95 if fully flooded with unborated water which includes an allowance for uncertainties as described in Section 10.3 of the UFSAR.

Contrary to the above, from the 4th quarter 2008 until June 2011, PBAPS failed to adequately identify or correct a condition adverse to quality involving Boraflex degradation in the SFP storage racks (10 CFR Part 50, Appendix B component, as stated in Section 10.3 of the UFSAR). Specifically, PBAPS deferred corrective actions in the SFPs until 2014 based on an OD that concluded sufficient margin would exist until that time. However, the NRC concluded that the OD did not accurately project the rate of boron degradation and used several non-conservative assumptions. In June 2011, after addressing the errors in the OD, PBAPS declared 117 cells in the Unit 2 SFP inoperable as of the fourth quarter 2008, which resulted in Unit 2 being in violation of TS 4.3.1.1.b. Because this finding is of very low safety significance and has been entered into the CAP via IRs 1127773 and 1225840, this violation is being treated as a Green NCV consistent with the Enforcement Policy, (NCV 05000277, 278/2012-03, Untimely Corrective Actions Resulted in Spent Fuel Pool Boraflex Degradation Exceeding Design Limits).

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

in accordance with NRC's Enforcement Policy

.1 (Closed) LER 05000277/2011-005-00: Inoperability of Offsite Power Circuit due to

Design Weakness On November 16, 2011, PBAPS determined, during design reviews, that a condition prohibited by TSs occurred as a result of two time periods within the last three years where the alignment of the two qualified circuits between the offsite transmission network and the onsite Class 1E AC electrical power distribution system did not comply with 10 CFR Part 50, Appendix A, General Design Criterion (GDC) XVII, "Electric Power Systems." It was determined that a lack of physical separation occurred, contrary to GDC 17, due to the auxiliary power supply for two TS offsite power source transformers, 00X011 and 00X005, being provided from a common power source. The cause of the event was attributed to an inadequate design of the auxiliary power to the 00X011 transformer, which was installed in the mid-1990s to provide the station with a third offsite power source that could be made available to feed a TS qualified circuit. PBAPS TS require only two operable offsite circuits to supply the Class 1E AC electrical power distribution system normal power operation. PBAPS entered this issue into the CAP.

The inspectors verified that PBAPS has established interim controls to ensure that the 00X011 and 00X005 transformers are not simultaneously credited as part of the two TS operable qualified circuits. The enforcement aspects of this LER are discussed in Section 4OA7. This LER is closed.

4OA6 Meetings, Including Exit

Quarterly Resident

Exit Meeting Summary

On April 20, 2012, the resident inspectors presented the inspection results to Mr.

Thomas Dougherty, 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 meets the criteria of the NRC Enforcement Policy for being dispositioned as an NCV(s).

• TS LCO 3.8.1, Condition A, requires that one inoperable offsite circuit be restored to an OPERABLE status within seven days during operational modes 1, 2 and 3.

Condition G requires action, if the completion time for Condition A cannot be met, to place the unit in operational mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Contrary to the above, the offsite power circuit associated with transformer 00X011 was inoperable between March 18 and March 26, and May 10 and 28, 2010. Specifically, PBAPS determined that offsite power source transformers 00X011 and 00X005 were not designed with adequate physical separation to minimize, to the extent practical, a simultaneous failure per the requirements of 10 CFR Part 50, Appendix A, Criterion XVII, "Electric Power Systems."

The inspectors determined that this finding was very low safety significance (Green),for both Peach Bottom Units 2 and 3, in accordance with IMC 0609, Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power Situations" (IMC 0609A) using SDP Phases 1, 2 and 3. Phase 1 screened this finding to Phase 2 because it represented a loss of the 00X011 function, between May 10 and 28, 2010 (approximately 18 days), for longer than the TS LCO of 7 days.

A Region 1 SRA conducted a Phase 3 analysis because the Phase 2 analysis, conducted by the inspectors using the Peach Bottom Pre-solved Risk-Informed Inspection Notebook, did not model the loss of a single offsite circuit.

The SRA used the Peach Bottom Standardized Plant Risk (SPAR) model, Version 8.18 dated September 10, 2009 and 8.17 dated July 8, 2009 for Units 2 and 3 respectively and SAPHIRE 8 to conduct the Phase 3 analysis.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Exelon Generation Company Personnel

T. Dougherty, Site Vice President

G. Stathes, Plant Manager

J. Armstrong, Regulatory Assurance Manager

T. Moore, Site Engineering Director

M. Herr, Operations Director

J. Kovalchick, Security Manager

P. Rau, Acting 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

LIST OF ITEMS

OPENED, CLOSED, DISCUSSED

Opened

None

Opened/Closed

05000277;278/2012002-01 NCV Inadequate Corrective Action to Address Emergency Diesel Generator Control Power Circuit Chronic Internal Faults (Section 1R19.1)

05000277/2012002-02 NCV Inadequate Corrective Action to Address Residual Heat Removal Heat Exchanger Graphite Gasket Leaks (Section 1R19.2)

05000277;278/2012-03 NCV Untimely Corrective Actions Resulted in Spent Fuel Pool Boraflex Degradation Exceeding Design Limits (Section 4OA2.1)

Closed

05000277&278/2010-004-01 URI Non-conservative TS and Potential Non-

Compliance Associated with Degraded Spent Fuel Pool Boraflex Panels (Section 4OA2.2)

05000277/2011-005-00 LER Inoperability of Offsite Power Circuit due to Design Weakness (Section 4OA3.2)