IR 05000277/2007002

TS. Corrective actions included issuing a cease and desistorder to licensed operators to stop crediting time in the

WECS [[position as activetime for maintaining licenses. The finding is more than minor because it impacted the human performanceattribute of the Mitigating Systems cornerstone. In addition, the finding is morethan minor because if left uncorrected, it would become a more safety significantsafety concern. Specifically, although the]]

WECS performs activities important tosafety, the active time credited is not in a position defined by

TS [[that involveddirecting the licensed activities of licensed operators. This finding is related tooperator license conditions and was determined to be of very low safetysignificance (Green) because more than 20 percent of the records reviewed haddeficiencies. (Section 1R11.1)*Green. A self-revealing]]

NCV of 10

CFR Part 50, Appendix B, Criterion V,"Instructions, Procedures, and Drawings," was identified for inadequatesurveillance procedure development that changed the use of a common highpressure coolant injection (HPCI)/reactor core isolation cooling (RCIC) line to thetorus from its original design purpose as a partial-flow flush line, to a full-flow test

Enclosureivline. The cracked piping to the torus was replaced and this issue was placed intothe corrective action program (CAP) for resolution.This finding is more than minor because it is associated with the design controlattribute of the Barrier Integrity Cornerstone and it affected the objective toprovide reasonable assurance that physical design barriers (primarycontainment) protect the public from radionuclide releases caused by accidentsor events. The Significance Determination Process (SDP) Phase 1 screeningidentified that a Phase 2 analysis was needed because the finding affected twocornerstones, specifically the Mitigating Systems and Barrier Integritycornerstones. However, the senior reactor analysts (SRAs) conducted aPhase 3 evaluation because the issue was too complex to evaluate using thePlant Specific Phase 2 Notebook. For events (large or medium break loss-of-coolant accidents) with the greatest potential consequence, the

SRA [[sdetermined that the probability of a large early release remained very lowbecause existing emergency operating procedures direct reactor operators tomaintain torus level and prevent an increase in core damage frequency byinjecting high pressure service water (]]

HPSW ) through the residual heat removal(RHR) system. The Phase

3 SDP evaluation concluded that this finding was ofvery low safety significance (Green). (Section 4

OA 3.2)Cornerstone: Public Radiation Safety*Green. The inspectors identified a

NCV of

TS [[5.4.1.C because procedures foreffluent monitoring were inadequately established and maintained. Specifically,the Quality Assurance required procedures for effluent monitoring wereinadequate to detect non-representative sampling of the 'B' train of the mainstack particulate effluents sampling system. This issue was placed in the]]

CAP [[for resolution. This finding is more than minor because it affected the Public Radiation SafetyCornerstone objective to ensure adequate protection of public health and safety. This finding was determined to be of very low safety significance because: 1) itwas not a radioactive material control issue; 2) it did involve the effluent releaseprogram; 3) there was an impaired ability to assess dose; and 4) public radiationdoses did not exceed 10]]

CFR Part 50, Appendix I values. This finding has across-cutting aspect in the human performance area, resources componentbecause the procedures and training of personnel were inadequate to detect thesample bypass. (Section

2PS 1)B.Licensee-Identified Violation A violation of very low safety significance, that was identified by the licensee, has beenreviewed by the inspectors. Corrective actions taken or planned by the licensee havebeen entered into the licensee's

CAP. The violation and corrective actions are listed inSection 4OA7 of this report.

EnclosureREPORT

DETAIL [[]]

SS [[ummary of Plant StatusUnit 2 began the inspection period at 100 percent full rated thermal power (RTP). OnFebruary 16, 2007, power was reduced to approximately 58 percent for maintenance on the 2'B' reactor feed pump, control rod timing, water box cleaning, and other planned maintenanceand testing. The unit was returned to full power on February 17, 2007, where it remainedexcept for brief periods to support planned testing and rod pattern adjustments. OnFebruary 28, 2007, an unplanned power reduction to approximately 76 percent was performedto maintain main condenser vacuum when the 2 'C' circulating water pump tripped. Later onFebruary 28, 2007, the unit returned to full power where it remained until the end of theinspection period.Unit 3 began the period at 100 percent]]

RTP. [[On January 12, 2007, power was reduced toapproximately 58 percent for maintenance on the 3 'C' reactor feed pump, control rod timing,and other planned maintenance and testing. The unit returned to full power on January 13,2007, where it remained except for brief periods to support planned testing and rod patternadjustments. On February 27, 2007, an unusual event (]]

UE [[) was declared in response to a firein non-safety-related switchgear located in the turbine building. Consequently, an unplannedpower reduction to approximately 55 percent was performed due to the fire-induced loss ofisophase bus duct cooling. Subsequently, power was further reduced to 50 percent followingan unplanned trip of the 3 'B' reactor feed pump. On February 28, 2007, power was increasedto 90 percent following the return of isophase bus duct cooling. On March 2, 2007, the unit wasreturned to full power where it remained until the end of the inspection period.1.REACTOR]]

SAFETY Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R01Adverse Weather Protection (71111.01 - 1 Sample) a.Inspection ScopeThe inspectors reviewed one sample of

PBAPS 's preparation for frazzle ice conditions. The inspectors reviewed abnormal operations procedure (AO)-29.2, "Discharge Canal toIntake Pond Cross-Tie Gate Operation and Frazzle Ice Mitigation," Revision 12, toensure

PBAPS appropriately prepared for environmental conditions conducive to theformation of frazzle ice. The inspectors discussed

PBAPS's actions with maintenanceand engineering personnel. Documents reviewed during this inspection are listed in theAttachment. b.FindingsNo findings of significance were identified.

2Enclosure1R02Evaluations of Changes, Tests, or Experiments (71111.02 - 20 Samples: 4 Safety Evaluations; 16 Screening Evaluations) a.Inspection ScopeThe inspectors reviewed four safety evaluations (SEs) completed during the past twoyears. The

SE s reviewed were in the Initiating Events and Mitigating Systemscornerstones. The selected

SE s were reviewed to verify that changes to the facility orprocedures as described in the Updated Final Safety Analysis Reports (UFSAR) werereviewed and documented in accordance with

10 CFR Part 50.59, and that the safetyissues pertinent to the changes were properly resolved or adequately addressed. Thereviews included the verification that

PBAPS had appropriately concluded that thechanges could be accomplished without obtaining license amendments. The inspectors also reviewed 16 screening evaluations for changes, tests andexperiments for which

PBAPS determined that

SE s were not required. This review wasperformed to verify that the threshold for performing

SE s was consistent with 10

CFR [[Part 50.59. The documents reviewed are listed in the Attachment. b.FindingsNo findings of significance were identified.1R04Equipment Alignment (71111.04Q - 4 Partial Walkdown Samples)Partial Walkdown a.Inspection ScopeThe inspectors performed a partial walkdown of four systems to verify the operability ofredundant or diverse trains and components when safety-related equipment wasinoperable. The inspectors performed walkdowns to identify any discrepancies thatcould impact the function of the system and potentially increase risk. The inspectorsreviewed applicable operating procedures, walked down system components, andverified that selected breakers, valves, and support equipment were in the correctposition to support system operation. The inspectors also verified that]]

PBAPS hadproperly identified and resolved equipment alignment problems that could causeinitiating events or impact the capability of mitigating systems or barriers and enteredthem into the

CAP. [[The four systems reviewed were:*Unit 3 'B' Core Spray Pump with the 3 'A' Core Spray Pump Out-of-Service;*'B' Emergency Service Water (ESW) Pump with the 'A']]

ESW PumpOut-of-Service for Breaker Maintenance;*Unit 2 'A'

RHR Loop With the Unit 2 'B' RHR Loop Out-of-Service; and*Standby Gas Treatment System with secondary containment breached for Unit 2 and Unit 3.

3Enclosure b.FindingsNo findings of significance were identified.1R05Fire Protection (71111.05Q - 9 Samples).1Fire Protection - Tours a.Inspection ScopeThe inspectors reviewed

PBAPS 's Fire Protection Plan, Technical Requirements Manual(

TRM "), and the respective pre-fire action plan procedures to determine the required fireprotection design features, fire area boundaries, and combustible loading requirementsfor the areas examined during this inspection. The fire risk analysis was reviewed togain risk insights regarding the areas selected for inspection. The inspectors performedwalkdowns of nine areas to assess the material condition of active and passive fireprotection systems and features. The inspection was also performed to verify theadequacy of the control of transient combustible material and ignition sources, thecondition of manual firefighting equipment, fire barriers, and the status of any relatedcompensatory measures. The following nine fire areas were reviewed for impaired fireprotection features:*Unit 3 Service Water Screen Wash Pump (Fire Zone 144);*Radwaste Building, Elevations 150' & 165' (Fire Zone 72J);*Unit 2 [[system" contains a listed "[" character as part of the property label and has therefore been classified as invalid. Motor Generator Set Room (Fire Zone 4C);*Emergency Cooling Tower (Fire Zone 136);*Unit]]

2 HPCI Pump Room (Fire Zone 59);*Unit 2 'A' & 'C'

RHR Pump and heat exchanger (HX) Room (Fire Zone

PF -1);*Unit 2 'A' & 'C' Core Spray Rooms (Fire Zone

PF -5A);*Unit 3 'A' & 'C'

RHR Pump and

HX Rooms (PF-11); and*Unit 3 Reactor Building Closed Cooling Water Room (Fire Zone

PF -12B). b.FindingsNo findings of significance were identified..2Fire Protection - Drill Observation (71111.05A - 1 Sample) a.Inspection ScopeThe inspectors observed a Unit 3

HPCI pump room fire drill on January 10, 2007. Thedrill simulated a Class B fire (lubricating oil) at the bearings of the Unit

3 HP [[]]

CI pump dueto a bearing failure. The inspectors evaluated the fire brigade performance during thedrill to assess the readiness of station personnel to fight fires. Specifically, theinspectors verified that:

4Enclosure*The fire brigade (FB) leader responded to the fire area to begin assessing thesimulated fire and establishing a command post;*Security radiation protection personnel and a licensed senior reactoroperator (SRO) (floor supervisor) responded and were available to support theFB leader;*The four

FB members donned the applicable turnout gear and responded to thefire area;*Self-contained breathing apparatuses were available and properly worn by thefour

FB members;*FB leader maintained command and control of the fire brigade and had a copy ofthe pre-fire plan; *The fire hoses were capable of reaching the fire hazard and were laidappropriately;*The

FB used the "two person rule" for personnel safety;*The

FB brought sufficient fire fighting equipment to the scene;*Drill personnel followed the scenario and all drill objectives were met; and*The

FB [[and the evaluators performed a post-drill critique and validated that thedrill objectives were met. b.FindingsNo findings of significance were identified.1R06Flood Protection Measures (71111.06 - 2 Internal Samples)Internal Flooding a. Inspection ScopeThe inspectors reviewed]]

PBAPS 's internal flooding analysis contained in the IndividualPlant Examination (IPE) for the Unit 2 and Unit 3 'A' and 'C'

RHR pump rooms. Theinspectors also reviewed Design Basis Document (

DBD ) P-T-09, Revision 8, "InternalHazards." The inspectors walked down Unit 2 and Unit

3 RHR pump rooms to verifyinternal flooding design features were as described in the

IPE. The inspectors alsoinspected floor plugs to verify that they were installed in the Unit 2 and Unit 3 'A' and 'C'RHR pump room drains to prevent multiple RHR pumps from being affected by a flood. b.FindingsNo findings of significance were identified.1R07 Heat Sink Performance (71111.07 - 1 Sample) a. Inspection ScopeBased on a plant specific risk assessment and past inspection results, the inspectorsselected the following heat exchanger for review:

5Enclosure*RT-O-010-660-2,

RHR [[]]

HX Performance Test, Revision 7, completed March 10,2007.The inspectors reviewed one sample of safety-related

HX testing to identify anydegraded performance or potential for common cause problems that could increaseplant risk. The inspectors reviewed the results of testing performed in accordance with

PBAPS 's procedures. The inspectors reviewed test results and compared them withacceptance criteria contained within the procedure to verify that all acceptance criteriahad been satisfied. The inspectors also reviewed the

UFSAR to ensure that

HX [[inspection results were consistent with the design basis. b. FindingsNo findings of significance were identified.1R11Licensed Operator Requalification Program (71111.11B - 1 Sample) .1Biennial Review of Licensed Operator Requalification Program a.Inspection ScopeThe inspectors reviewed documentation of operating history since the last requalificationprogram inspection. The inspectors also discussed facility operating events with theresident staff. Documents reviewed included]]

NRC inspection reports, plantperformance insights, licensee event reports (

LER [[s), and licensee issue reports (IRs)that involved human performance issues for licensed operators to ensure thatoperational events were not indicative of possible training deficiencies.The inspectors reviewed three examination sets (weeks 1, 2, and 3) for both thecomprehensive]]

RO and

SRO [[biennial written examinations administered in 2006, aswell as scenarios and job performance measures (JPMs) administered during thiscurrent examination cycle to ensure the quality of these examinations met or exceededthe criteria established in the Examination Standards and]]

10 CFR Part 55.59. Duringthe onsite weeks of this inspection, the inspectors observed the administration ofoperating examinations to operating crews (

PS -1 and 2). The operating examinationsconsisted of two or three simulator scenarios for each crew and one set of five

JPM sadministered to each individual. For the site specific simulator, the inspectors observed simulator performance during theconduct of the examinations, and discrepancy reports to verify compliance with therequirements of 10

CFR Part 55.46. The inspectors reviewed simulator maintenance,testing, and control procedures. Simulator maintenance, testing, configuration control,and machine operation were discussed with members of the simulator maintenancestaff. A sample of simulator tests including transients, normal, steady state, andmalfunction tests as well as plant event data comparison tests, were reviewed.

6EnclosureConformance with operator license conditions was verified by reviewing the followingrecords:*Remediation training records for two individual operating examination failures;*Simulator and classroom training attendance records for two training cycles;*Six licensed operator medical records;*Proficiency watch-standing and reactivation records; and *A sample of licensed operator reactivation records.The inspectors interviewed Instructors, training/operations management personnel, andtwo operators for feedback regarding the implementation of the licensed operatorrequalification program to ensure the requalification program was meeting their needsand responsive to their noted deficiencies/recommended changes.The inspectors reviewed a potential examination compromise issue that Exelon self-identified based on a review of recent licensed operator requalification programoperating experience. This item was entered into

CAP (IR 545351). On April 13, 2007, the inspectors conducted an in-office review of

PBAPS 'srequalification examination results. These results included the annual operating testsadministered in 2007. The inspection assessed whether pass rates were consistent withthe guidance of

NRC [[]]

IMC [[0609, Appendix I. The inspectors verified that: *Crew failure rate on the dynamic simulator was less than 20 percent. (Failure rate was 0.0 percent);*Individual failure rate on the dynamic simulator test was less than or equal to 20 percent. (Failure rate was 0.0 percent);*Individual failure rate on the walkthrough test (]]

JPMs) was less than or equal to 20 percent. (Failure rate was 0.0 percent);*Individual failure rate on the comprehensive biennial written examination wasless than or equal to 20 percent. (N/A - biennial written examinations were notadministered this examination cycle); and*More than 75 percent of the individuals passed all portions of the examination(100.0 percent of the individuals passed all portions of the examination).The inspectors used the following references as acceptance criteria for the inspection:

NUREG-1021, "Operator Licensing Examination Standards for Power Reactors,"Revision 9;*Inspection Procedure Attachment 71111.11, "Licensed Operator RequalificationProgram;"*NRC Inspection Manual Chapter (IMC) 0609, Appendix I, "OperatorRequalification Human Performance

SDP ;" and *10

CFR Part 55.46, "Simulation Facilities."

7Enclosure b.Findings and ObservationsIntroduction: The inspectors identified a non-cited violation (NCV) of Title 10 of theCode of Federal Regulations (CFR) Part 55.53(e), "Conditions of Licenses," becausePeach Bottom Atomic Power Station (PBAPS) incorrectly credited individuals withactively performing the functions of a senior operator (SO) while those individualsstaffed a position that was not specified in

PBAPS 's Technical Specifications (

TS ). Specifically,

PBAPS incorrectly credited individuals with performing the functions of a

SO while those individuals staffed the work execution control supervisor (WECS)position. Description: During discussions with licensed senior reactor operators (SROs), theinspectors discovered that the

SRO s were taking credit for maintaining their licenseactive while standing the

WECS position. The inspectors determined that ExelonProcedure

OP -

AA -105-102, "NRC Active License Maintenance," Revision 8, Section4.1.1.1, states that, "The

WECS position may also be used to satisfy active licenserequirements, provided at least one shift each quarter is performed in the unit supervisorposition." A review of

OP -AA-105-102, "NRC Active License Maintenance," Attachment1, "Active License Tracking Log," found numerous

SRO s that were incorrectly takingcredit for standing the

WECS position; a position that is not required to be licensed perPBAPS's

TS. The inspectors reviewed

TS and determined from section 5.3.2that

PBAPS has only committed to have the minimum on-site staffing required by

10CFR Part 50.54(m). For a two unit facility with one control room, 10

CFR Part 50.54(m) requires a minimumof two

SRO s. 10

CFR Part 50.54(m)(ii) requires that one of the

SRO s be assignedresponsibility for overall plant operation. At

PBAPS , that position is held by the shiftmanager.

10 CFR Part 50.54(m)(iii) requires that a person holding a

SO license be inthe control room at all times. At

PBAPS , that position is held by the unit supervisor(previously the control room supervisor position). Therefore, per 10

CFR Part 50.54(m),PBAPS is only required to have a unit supervisor and a shift manager.10

CFR Part 55.53(e) states, in part, that to maintain active status, the licensee shallactively perform the functions of an operator or

SO. [[]]

10 CFR Part 55.4 defines "activelyperforming the functions of an operator or

SO " as an individual that has a position onthe shift crew that requires the individual to be licensed as defined in the facility's

TS ,and that individual carries out and is responsible for duties covered by that position. At

PBAPS , the only two positions that are required to be licensed per

TS are theunit supervisor and the shift manager. Therefore, the only two positions that should becredited with active license time are the unit supervisor and the shift manager.The performance deficiency is that

PBAPS incorrectly credited individuals withperforming the functions of a

SO while those individuals staffed the work executioncontrol supervisor (WECS) position. Analysis: The finding is more than minor because it impacted the human performanceattribute of the Mitigating Systems cornerstone. In addition, the finding is more than

8Enclosureminor because if left uncorrected, it would become a more safety significant safetyconcern. Specifically, although the

WECS performs activities important to safety, theactive time credited was not in a position defined by

TS that involved directing thelicensed activities of licensed operators. Traditional enforcement does not applybecause there were no actual safety consequences, impacts on the

NRC 's ability toperform its regulatory function, or will aspects to the violation. The finding wasevaluated using the

NRC [[]]

IMC 0609, Appendix I. The

SDP , Appendix I, Block 24 appliessince the issue is related to the licensee's program for maintaining active operatorlicenses and ensuring the medical fitness of its licensed operators. Since the

WECS position is not required to be licensed by the facility's

TS , giving

SRO credit for activelyperforming the functions of the

WECS would impact the licensee's program formaintaining active operator licenses. Since more than 20 percent of the recordsreviewed indicated deficiencies (Block 27), this finding is of very low safety significance(Green).Enforcement:

10 CFR Part 55.53(e), "Conditions of Licenses," requires, in part, that tomaintain an operator license active, the licensee shall actively perform the functions ofan operator or

SO on a minimum of seven 8-hour or five 12-hour shifts per calendarquarter.

10 CFR Part 55.4, "Definitions," states, in part, that actively performing thefunctions of an operator or

SO means that an individual has a position on the shift crewthat requires the individual to be licensed as defined in the facility's

TS and that theindividual is responsible for the duties covered by that position. Contrary to the above,the inspectors identified that prior to January 27, 2007,

PBAPS personnel wereimproperly maintaining operator licenses active by incorrectly crediting individuals withactively performing the functions of a

SO while manning a position that was not definedin the facility's

TS. Specifically, active time was credited for the

WECS position and thisposition is not required to be licensed as defined in

TS. Corrective actionsincluded

PBAPS issuing a cease and desist order to licensed operators to stop creditingtime in the

WECS position as active time for maintaining their licenses. Because thisfinding was of very low safety significance and was entered into

IR 00592412), this violation is being treated as an

CAP (

NCV , consistent with section

VI.A. 1of the

NRC Enforcement Policy:

NCV 05000277/2007002-01; 05000278/2007002-01,Non-Technical Specifications Position Incorrectly Credited for Active LicenseMaintenance..2Resident Inspector Quarterly Review (71111.11Q - 1 Sample) a.Inspection ScopeOn March 6, 2007, the inspectors observed operators in the plant's simulator duringlicensed operator requalification training to verify that operators' performance wasadequate and that evaluators were identifying and documenting crew performanceissues. The inspectors verified that performance issues were discussed in the crew'spost-scenario critiques. The inspectors also observed the operators' implementation ofoperating procedures. The inspectors discussed the training, simulator scenarios, and

9Enclosurecritiques with the operators, shift supervision, and the training instructors. Theevaluated scenarios observed for this one sample are listed below: *PSEG0731R, Low Torus Level Condition Requires Emergency Blowdown; and*PSEG0715R, Hydraulic Anticipated Transient Without Scram. b.FindingsNo findings of significance were identified.1R12Maintenance Effectiveness (71111.12Q - 2 Samples)Routine Maintenance Effectiveness Issues a. Inspection ScopeThe inspectors reviewed two samples of

PBAPS 's evaluation of degraded conditionsinvolving safety-related structures, systems, and/or components for maintenanceeffectiveness during this inspection period. The inspectors reviewed

PBAPS 'simplementation of the Maintenance Rule (MR), and verified that the conditionsassociated with the referenced

CR s were evaluated against applicable

MR functionalfailure criteria as found in licensee scoping documents and procedures. The inspectorsalso discussed these issues with system engineers and

MR coordinators to verify thatthey were tracked against each systems' performance criteria and that the systemswere classified in accordance with

MR implementation guidance. Documents reviewedduring the inspection are listed in the Attachment. The following conditions werereviewed:*

IR 579872, E-1 Emergency Diesel Generator (

EDG ) Fuel Oil Leaks; and*IR 554132, Replace 3 'D'

RHR [[]]

HX Floating Head Assembly. b.FindingsNo findings of significance were identified.1R13Maintenance Risk Assessments and Emergent Work Control (71111.13 - 7 Samples) a.Inspection ScopeThe inspectors reviewed

PBAPS 's planning and risk management actions for plannedand emergent work activities to assess their management of overall plant risk. Theactivities selected were based on plant maintenance schedules and systems thatcontributed to risk. The inspectors reviewed

PBAPS 's probabilistic safety assessmentrisk evaluation results forms. The inspectors compared the risk assessment results andthe risk management actions to the requirements of

10 CFR Part 50.65(a)(4),Regulatory Guide (

RG ) 1.182, "Assessing and Managing Risk Before MaintenanceActivities at Nuclear Power Plants," and procedure

WC -

AA-101, "On-line Work Control

10EnclosureProcess." The inspectors also reviewed selected control room operating logs, walkeddown protected equipment and maintenance locations, and interviewed personnel. These reviews were performed to determine whether

PBAPS properly assessed andmanaged plant risk and performed activities in accordance with applicable

TS [[and workcontrol requirements. The following seven planned and emergent work order (WO) andaction request (AR) activities were reviewed:*WO C0219775, Remove Foreign Material (Garlock Gasket Tool) from the Unit 2Generator Brush Rigging;*WO C0219963, Repair Hydrogen Leak on Unit 2 'D' Main Generator HydrogenCooler;*WO C0219318-26 & -29, Remove and Reinstall Hatch Above 3 'D']]

RHR atReactor Building, 135' Elevation;*

WO C0219318-35 & -36, Remove and Reinstall 3 'D'

RHR [[]]

HX Floating Head;*WO C0220444, 4T4 Bus, Inspect, Rework as Required; *WO C0220652, E-3

EDG Inspections Following Overload Event; and*

AR A1607626, Unit

2 HPCI Inoperable Due to

AO [[-2-23-042 Failing Closed. b.FindingsNo findings of significance were identified.1R15Operability Evaluations (71111.15 - 6 Samples) a.Inspection ScopeThe inspectors reviewed six issues to assess the technical adequacy of the evaluations,the use and control of compensatory measures, and compliance with the licensing anddesign bases. Associated adverse condition monitoring plans, engineering technicalevaluations, and operational and technical decision making documents were alsoreviewed. The inspectors verified these processes were performed in accordance withthe applicable procedures. The inspectors used]]

TS ,

TRM , the

UFSAR , and associated

DBD s as references during these reviews. The issues reviewed included:*3 'D'

RHR [[]]

HX Leak (IR 514302);*Emergency cooling Tower (ECT) Freezing Issue (AR A1044572);*Lost Part - 2 'C'

RHR [[]]

HX Plug Insertion Tooling Failed, (AR A1546765);*2 'C'

RHR [[]]

HX Leakage to

HPSW Greater than Acceptance Criteria,(

AR A1604675);*Unit

2 HPCI Inoperable Due to

AO -2-23-042 Failing Closed (AR A1607626); and*2 'D'

RHR Room Cooler 2

DE058 Heat Transfer Test Unsat (IR 608000). b.FindingsNo findings of significance were identified.

11Enclosure1R17Permanent Plant Modifications (71111.17B - 8 Samples) a.Inspection Scope The inspectors reviewed eight design changes that were completed within the past twoyears. The review was performed to verify that the design bases, licensing bases, andperformance capability of risk significant structures, systems, and components (SSCs)had not been degraded as a result of the modifications.The inspectors walked down systems to detect possible abnormal installation conditions. The inspectors reviewed the design inputs, assumptions, and design calculations todetermine the design adequacy. For the replacement components, the inspectorsverified material compatibility and seismic qualification. In addition, the inspectorsreviewed the post-modification testing to determine readiness for operations. The10

CFR Part 50.59 screenings and evaluations for the modifications were reviewed toverify that the plant changes were reviewed and documented in accordance with10

CFR Part 50.59. Finally, the inspectors reviewed the procedures, drawings,

DBD s,and

UFSAR sections to verify that the documents were appropriately updated. Themodifications reviewed are listed in Attachment 1. The inspectors reviewed

IR s associated with 10

CFR Part 50.59 issues and plantmodification issues to ensure that

PBA [[]]

PS was identifying, evaluating, and correctingproblems associated with these areas, and that the planned or completed correctiveactions for the issues were appropriate. b.Findings No findings of significance were identified.

1R19Post-Maintenance Testing (71111.19 - 7 Samples) a.Inspection ScopeThe inspectors observed selected portions of post-maintenance testing (PMT) activitiesand reviewed completed test records. The inspectors observed whether the tests wereperformed in accordance with the approved procedures and assessed the adequacy ofthe test methodology based on the scope of maintenance work performed. In addition,the inspectors assessed the test acceptance criteria to verify whether the testdemonstrated that the tested components satisfied the applicable design and licensingbases and the

TS requirements. The inspectors reviewed the recorded test data toevaluate whether the acceptance criteria were satisfied. The inspectors reviewed seven

PMT s performed in conjunction with the following maintenance activities:*WO C0220132, 2-5A-K003A Replace Relay and Perform

PMT ;*

WO R0810095, E124-P-A (6244) Perform

MCU Inspection;*

WO R1011869,

CHK -O-33-515A; Disassemble Inspect/Rework;*

WO C0219318-19 & -23, Perform 3 'D'

RHR [[]]

HX Leak Repairs;

2Enclosure*WO C0219643,

2AP 040 Clean/Inspect/Repack Cylinders (2 'A'

SLC Pump);*WO C0220652,

0CG 012-

DR Inspections on the E-3 Diesel Generator Due toIncomplete Procedure Performance During Testing Results in E-3 GeneratorTrip; and*WO C0220288, Recal/Rework/Replace

LS -2-23-090 As Required (U2

HPCI [[Steam Supply Drain Pot Level). b.FindingsNo findings of significance were identified.1R22Surveillance Testing (71111.22 - 7 Samples) a.Inspection ScopeThe inspectors reviewed and observed portions of selected surveillance tests (STs), andcompared test data with established acceptance criteria to verify the systemsdemonstrated the capability of performing the intended safety functions. The inspectorsalso verified that the systems and components maintained operational readiness, metapplicable]]

TS requirements, and were capable of performing the design basis functions. The seven

ST [[s reviewed and observed included:*ST-O-020-560-2, Reactor Coolant Leakage Test [Reactor Coolant System (RCS) Leakage Sample];*ST-O-010-301-3, 'A']]

RHR Loop Pump, Valve, Flow and Unit Cooler Functionaland Inservice Test (

IST [[) [IST Sample];*ST-O-052-701-2, E-1 Diesel Generator 24-hour Endurance Test;*SI3F-13-83-XXCQ, Calibration Check of]]

RCIC Steam Line High Flow Instrument

DPIS 3-13-83;*ST-O-033-300-2,

ESW , Valve, Unit Cooler, and

ST -O-052-212-2, E-2 Diesel Generator Slow Start Full Load and

IST ;*

IST Test; and*

SI 3F-23-82-XXC2, Calibration Check of

HPCI Flow Instruments

FT 3-23-082,FI/FC 3-23-108, E/S 3-23-143,

XS 3-23-144 and

FS 3-23-078. b.FindingsNo findings of significance were identified.1R23Temporary Plant Modifications (71111.23 - 2 Samples) a.Inspection ScopeThe inspectors reviewed two temporary modifications to verify that implementation ofthe modifications did not place the plant in an unsafe condition. The review was alsoconducted to verify that the design bases, licensing bases, and performance capabilityof risk significant SSCs had not been degraded as a result of these modifications. The inspectors verified the modified equipment alignment through control room

13Enclosureinstrumentation observations:

UFSAR , drawings, procedures, and

WO "reviews; andplant walkdowns of accessible equipment. The following temporary modifications werereviewed:*TCCP 07-00080, Temporary Power for 30Y023; and*TCCP 07-00081, Temporary Power for 4-T-4-T-C. b.FindingsNo findings of significance were identified.Cornerstone: Emergency Preparedness1EP6Drill Evaluation (71114.06 - 1 Sample)Simulated Training Exercise a.Inspection ScopeOn January 10, 2007, the inspectors observed one emergency plan training exercisethat simulated control of the Emergency Response Organization by the emergencydirector in the [[Emergency Facility" contains a listed "[" character as part of the property label and has therefore been classified as invalid. prior to the emergency operations centeraccepting control. The inspection was conducted to assess personnel performance. The training exercise was performed to provide drill and exercise performance (DEP)opportunities for the]]

DEP performance indicator (

PI ). The review was conducted toidentify any weaknesses and deficiencies in protective action recommendation (PAR)development and simulated notification activities. The inspectors verified that

PAR development was performed in accordance with

EP -AA-111, "Emergency Classificationand Protective Action Recommendations," and

EP -

AA -111-F-08, "Limerick/PeachBottom Plant Based

PAR. " Event classification and notifications were done inaccordance with

EP -AA-1007, "Exelon Nuclear Radiological Emergency Plan Annex forPeach Bottom Atomic Power Station." The inspectors verified that training exerciseevaluators captured the results for calculation of the

DEP [[]]

PI. The inspectors alsoverified that weaknesses or deficiencies were captured for the critique of the trainingexercise. The following simulated events were classified during this one trainingexercise:*FG1 - General Emergency, Fission Product Barrier Status; and*MG1 - General Emergency, Loss of Alternating Current Power. b.FindingsNo findings of significance were identified.

14Enclosure2.RADIATION

SAFETY [[Cornerstone: Occupational Radiation Safety []]

OS "]2OS1Access Control to Radiologically-Significant Areas ([[Inspection procedure" contains a listed "[" character as part of the property label and has therefore been classified as invalid. - 1 Sample) a.Inspection ScopeThe inspectors reviewed selected activities and associated documentation in the areaslisted below. The criteria used for the evaluation of]]

PBAPS 's performance in theseareas was 10

CFR Part 20,

TS [[, and Exelon procedures. The selected areas were:*Plant Walkdowns; *Radiation Work Permit Reviews; and *Jobs in Progress Reviews.The inspectors walked down selected radiological controlled areas and reviewedhousekeeping, material conditions, posting, barricading, and access controls toradiological areas. The inspectors observed and reviewed ongoing work activitiesassociated with packaging of irradiated hardware for disposal. b.FindingsNo findings of significance were identified. Cornerstone: Public Radiation Safety []]

PS "]2PS1Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems([[Inspection procedure" contains a listed "[" character as part of the property label and has therefore been classified as invalid. - 10 Samples) a.Inspection ScopeInspection Planning and In-office InspectionThe inspectors reviewed the 2004 and 2005 Radiological Effluent Release Reports andRadiological Dose Assessment Reports to verify that the program was implemented asdescribed in the Radiological Effluents]]

TS (

RETS ) and the Offsite Dose CalculationManual (ODCM). The inspectors also reviewed estimated radiological effluentsreleased and projected dose results for 2006. The inspectors reviewed the reports forsignificant changes to the

ODCM and to radioactive waste system design and operation. The inspectors determined whether changes to the

ODCM were technically justified anddocumented. Technical justifications were reviewed during the onsite inspection.The inspectors evaluated

PBA [[]]

PS's analysis for any additional discharge pathways as aresult of a spill, leak, routine, normal, abnormal, or unexpected liquid discharge orgaseous discharges, which may have developed since the previous inspection. The

15Enclosureinspectors verified that

PBAPS had records on sampling locations, type of monitoring,and frequency of sampling to meet 10

CFR Part 20.1501 requirements.The inspectors determined whether modifications made to radioactive waste systemdesign and operation changed the dose consequence to the public. The inspectorsverified that technical reviews and

10 CFR Part 50.59 reviews were performed. Theinspectors determined whether radioactive liquid and gaseous effluent radiation monitorsetpoint calculation methodology changed since completion of the modifications, andthat

PBAPS had set and adjusted its radioactive effluent alarm setpoints in accordancewith the methodology and parameters specified within the current

ODCM. The inspectors also reviewed

PBAPS 's actions to resolve any out-of-specificationinter-laboratory cross-check analysis data for the effluent monitoring program and todetermine if remedial action had been taken for the out-of-specification data.The inspectors reviewed the

ODCM to identify the effluent radiation monitoringsystems and applicable flow measurement devices. The inspectors reviewed anyeffluent radiological occurrence performance indicator incidents for onsite follow-up andreviewed

PBAPS self-assessments, audits, and event reports that involvedunanticipated offsite releases of radioactive material. The inspectors reviewed the

UFSAR description of all radioactive effluent monitoring and radioactive gaseous andliquid processing systems. The inspectors reviewed the

ODCM to identify the programs for identifyingpotential contaminated spills and leakage, and

PBAPS [['s process for control andassessment. The inspectors determined if any licensee procedures and surveillanceactivities address the ability to identify onsite spills and leaks of contaminated fluids.Problem Identification and ResolutionThe inspectors reviewed]]

PBAPS 's self-assessments, audits, licensee event reports, andspecial reports related to the radioactive effluent treatment and monitoring programsince the last inspection to determine if identified problems were entered into the

CAP [[for resolution. The inspectors interviewed staff and reviewed documents to determine iffollow-up activities were being conducted in an effective and timely mannercommensurate with their importance to safety and risk. The inspectors also reviewedself-assessments, audits, and]]

LER [[s that may have involved unanticipated offsitereleases of radioactive material. For repetitive deficiencies or significant individualdeficiencies in problem identification and resolution, the inspectors determined ifPBAPS's self-assessment activities were identifying and addressing these deficiencies.The inspectors reviewed a selection of corrective action documents since the previousinspection:*NOS Audit]]

NOSA -

PEA -03-08, Radiological Environmental Monitoring Program(REMP),

OD [[]]

CM, Non-radiological Effluent Monitoring, October 2003;

16Enclosure*NOS Audit

NOSA -

PEA -06-04, Chemistry, Radiological Effluent andEnvironmental Monitoring, May 2006; *NOS Audit

PEA -05-08,

ODCM ,

REMP , Effluent and Environmental Monitoring;and*

IR s: 196314, 253869, 279624, 1499640, 293360, 319434, 339837, 346400,352961, 353353, 35483356601, 386618, 394522, 363933, 394580, 394604,398636, 454242, 467543, 489045, and 569284. The criteria used in this review is contained in

10 CFR Part 20,

TS [[, and stationprocedures.Onsite InspectionThe inspectors walked down components of the gaseous and liquid release systems(e.g., radiation and flow monitors, filters, tanks, and vessels) to observe current systemconfiguration with respect to the description in the]]

UFSAR. The inspectors observedequipment material condition. The inspectors verified that system components were asdescribed in the

ODCM and were used for reduction of activity levels in accordance withthe

ODCM. [[The inspectors observed routine sample collections from the Unit 2 and Unit 3 plantvents and observed analysis of these samples, and samples of particulate and charcoalcartridges from the main stack. The inspectors reviewed use of radioactive gaseouseffluent treatment equipment in accordance with]]

ODCM requirements, andreviewed use of systems per

ODCM guidance. The inspectors reviewed severalradioactive liquid waste release permits, including projected doses to members of thepublic.The inspectors reviewed records of releases made with out-of-service effluent radiationmonitors, and

PBAPS [['s actions for these releases, to ensure an adequatedefense-in-depth was maintained against an unmonitored, unanticipated release ofradioactive material to the environment. The inspectors determined compensatorysampling and radiological analyses were conducted at the]]

ODCM requiredfrequency when effluent monitors were declared out-of-service. For unmonitoredreleases, the inspectors determined if

PBAPS performed an evaluation of the type andamount of radioactive material that was released, and the associated projected doses tomembers of the public. The inspectors also determined if

PBAPS placed information onleaks or spills into its

10 CFR Part 50.75(g) decommissioning file. The inspectors assessed

PBAPS 's understanding of the location and construction ofunderground pipes and tanks, and storage pools (spent fuel pool) that containradioactive contaminated liquids. The inspectors evaluated if

PBAPS may havepotential unmonitored leakage of contaminated fluids to the groundwater as a result ofdegrading material conditions or aging of facilities. The inspectors evaluated

PBAPS 's capabilities (such as monitoring wells) of detecting spills or leaks and of identifyinggroundwater radiological contamination both onsite and beyond the owner controlledarea. The inspectors reviewed

PBA [[]]

PS's technical bases for its onsite groundwater

17Enclosuremonitoring program. The inspectors discussed with

PBAPS its understanding ofgroundwater flow patterns for the site, and in the event of a spill or leak of radioactivematerial, if

PBAPS 's staff can estimate the pathway of a plume of contaminated fluidboth onsite and beyond the owner controlled area. The inspectors reviewed the PeachBottom Station Hydro-geologic Investigation Report dated September 1,

2006.T he inspectors reviewed changes to the

ODCM as well as to the liquid or gaseousradioactive waste system design, procedures, or operation since the last inspection. Foreach system modification and each

ODCM revision that impacted effluent monitoring orrelease controls, the inspectors reviewed

PBAPS 's technical justification to determinewhether the changes affected

PBAPS 's ability to maintain effluents as low as reasonablyachievable (

ALARA [[) and whether changes made to monitoring instrumentation resultedin a non-representative monitoring of effluents. For significant changes to dose values reported in the Radiological Effluent ReleaseReport from the previous report (2004 versus 2005), the inspectors evaluated thefactors which may have resulted in the change. The inspectors evaluated if the changewas influenced by an operational issue (e.g., fuel integrity, extended outage, or majordecontamination efforts).The inspectors reviewed a selection of 2004, 2005, and 2006 monthly, quarterly, andannual dose calculations to ensure that]]

PBAPS properly calculated the offsite dose(both cumulative and projected) from radiological effluent releases and to determine ifany annual

TS /ODCM (i.e., Appendix I to

10 CFR Part 50 values) were exceeded and, ifappropriate, issued a

PI report if any quarterly values were exceeded. The inspectorsevaluated the source term used by

PBAPS to ensure all applicable radionuclidesdischarged, within delectability standards, were included.The inspectors reviewed air cleaning system

ST results (standby gas treatment system,control room) to ensure that system operations were within applicable acceptancecriteria specified in the

TS. The inspectors reviewed

ST results or the methodologyPBAPS used to determine the stack and vent flow rates. The inspectors verified that theflow rates are consistent with

PBAPS 's quality control evaluation of the inter-laboratorycomparison test and associated corrective actions for any deficiencies identified. Theinspectors also reviewed

ODCM or

FSAR [[values. The inspectors reviewed records of instrument calibrations performed since the lastinspection for each point of discharge effluent radiation monitor and flow measurementdevice; reviewed completed system modifications; and reviewed the current effluentradiation monitor alarm setpoint value for agreement with]]

RETS [[/ODCM requirements.The inspectors reviewed calibration records of radiation measurement (i.e., countingroom) instrumentation associated with effluent monitoring and release activities. Theinspectors reviewed quality control records for the radiation measurement instruments,and looked for indications of degraded instrument performance and the correctiveactions taken.The inspectors reviewed the results of the inter-laboratory comparison program to verifythe quality of radioactive effluent sample analyses performed by]]

PBA [[]]

PS. The

18Enclosureinspectors reviewed

PBAPS 's assessment of any identified bias in the sampleanalysis results and the overall effect on calculated projected doses to members of thepublic.The inspectors reviewed the results from Exelon's

QA audits to determine whether

PBAPS met the requirements of the

ODCM. b.FindingsIntroduction: An

NRC -identified Green non-cited violation of

TS 5.4.1, "Procedures,"was identified associated with inadequately establishing, implementing and maintainingwritten procedures for

QA of effluent monitoring. Specifically, procedures for

QA ofeffluent monitoring were inadequate to detect non-representative sampling of the 'B'train of the main stack particulate effluents sampling system. Description:

TS , Section 5.4.1.C requires that written procedures for

QA of effluentmonitoring be established, implemented, and maintained.

PBAPS collects weeklyparticulate samples of its main stack for use in public dose assessment in accordancewith its

ODCM. On March 7, 2007, the

NRC inspectors identified thatnon-representative samples of main stack 'B' train particulate effluents were collectedfor the week of February 28, 2007. Regulatory Guide (

RG ) 4.15, "QA for Radiological Monitoring Programs (NormalOperations) - Effluent Streams and Environmental Monitoring," Revision 1, provides theNRC regulatory position on an acceptable

QA Program.

RG 4.15 identifies the need forQA procedures for continuous sampling systems, including the need for representativesampling. Exelon committed to implement

RG 4.15, in accordance with its Station

QAP rogram, Revision

71.T he

NRC identified non-representative sampling of the 'B' train particulate sampler forthe week of February 28, 2007. Subsequently,

PBAPS [[reviewed its main stacksampling results and determined that the main stack 'B' particulate effluent sampler trainalso likely exhibited non-representative sampling during the weeks of November 22,2006; December 6, 2006; December 20, 2006; and February 21, 2007. EffectiveAugust 1, 2006,]]

PBAPS had selected the 'B' train effluent measurements sample datafor use in determination of dose to the public. Prior to August 1, 2006,

PBAPS [[relied ona combination of data from both the 'A' and 'B' train effluents sampling systems in thatmaximum values of releases were used. The 'A' channel did not exhibit bypass. The 'A'and 'B' trains each sample the main stack effluent releases and conservative resultswere used.]]

PBAPS conducted preliminary re-evaluation of projected radiation doses tomembers of the public for 2006 and concluded that no doses in excess of

10 CFR 50,Appendix I, had occurred.

PBAPS also re-evaluated the year-to-date projected doses tomembers of the public for calendar year 2007. This re-evaluation also did not identifyany projected doses in excess of

10 CFR 50, Appendix I. In addition, to evaluateextent-of-condition,

PBAPS evaluated potential sample bypass, and non-representative

19Enclosuresampling, for both the Unit 2 and Unit 3 plant vent stack 'B' train sampling systems. These vents use the same sampling arrangement as the main stack.

PBAPS did notidentify sample bypass for these systems or any apparent dose projection issues sincesamples were also collected from both the 'A' and 'B' trains of these systems for reviewand dose assessment. Since August 1, 2006,

PBAPS 's procedures specified using the'B' train effluent sample analysis results in the assessment of dose to members of thepublic. Failure to implement adequate

QA procedures, as specified in

TS for effluentmonitoring, is a performance deficiency in that non-representative sampling of effluentsoccurred for the 'B' train radioactive effluents which was reasonably within

PBAPS 'sability to foresee and correct, and which should have been prevented. Analysis: The finding is not subject to traditional enforcement in that the finding did nothave any actual safety consequence, did not have the potential for impacting the

NRC 'sability to perform its regulatory function, and there were no willful aspects. The finding was greater than minor because failure to implement adequate

QA foreffluent monitoring affected the Public Radiation Safety Cornerstone objective to ensureadequate protection of public health and safety. Specifically, the

NRC identified, onMarch 7, 2007, that non-representative sampling of main stack particulate effluents hadoccurred for the week beginning February 28, 2007. Using

NRC [[]]

IMC [[0609, Appendix D,this finding was determined to be of very low safety significance (Green), in that: 1) itwas not a radioactive material control issue, 2) it did involve the effluent releaseprogram, 3) there was an impaired ability to assess dose, and 4) public radiation dosesdid not exceed]]

10 CFR 50, Appendix I values. The inspectors determined that the cause of this finding was related to the resourcesaspect of the human performance cross-cutting area.The above example of failure to establish and implement adequate procedures for

QA of effluent monitoring reflects a finding in the cross-cutting area of human performance. Specifically, procedures and training of personnel were not adequate to detect thissample bypass. Exelon placed this issue into its

CAP (

IR 600686).Enforcement:

TS 5.4.1.C requires that procedures for

QA of effluent monitoring beestablished, implemented, and maintained. Contrary to this requirement, prior toMarch 7, 2007, the written procedures for

QA [[of effluent monitoring were inadequate todetect non-representative sampling of the 'B' train of the main stack particulate effluentssampling system. Since August 1, 2006, the 'B' train effluent measurements data wereused for public dose assessment. Because this finding was of very low safetysignificance (Green), and]]

PBAPS entered this finding into its

CAP (

AR 600686), thisviolation is being treated as a

NCV consistent with Section

VI.A of the

NRCE nforcement Policy,

NUREG -1600:

NCV 05000277/2007002-02;05000278/2007002-02, Exelon Did Not Establish and Implement Adequateprocedures for

QA of Effluent Monitoring as Required by TS 5.4.1.

20Enclosure2PS2Radioactive Material Processing and Transportation (71122.02) a.Inspection ScopeThe inspectors observed the packaging and preparation of a Type B shipping cask forshipment (PW-07-003). The inspectors visually inspected the loaded cask inpreparation for shipment. The inspectors selectively reviewed conformance with theapplicable

NRC licensed cask Certificate of Compliance (Certificate No. 5805, Revision23). b.FindingsNo findings of significance were identified.4.

OTHER [[]]

ACTIVI [[]]

TIESC ornerstones: Initiating Events, Mitigating Systems, and Barrier integrity4OA1Performance Indicator (PI) Verification (71151 - 6 Samples) a.Inspection ScopeThe inspectors reviewed a sample of

PBAPS 's submittals for the

PI s listed below toverify the accuracy of the data reported. The

PI definitions and the guidance containedin Nuclear Energy Institute (

NEI ) 99-02, "Regulatory Assessment Indicator Guideline,"Revision 4, and licensee procedure

LS -

AA -2001, "Collecting and Reporting of

NRCP erformance Indicator Data," were used to verify procedure and reporting requirementswere met. The inspectors reviewed raw

PI data collected since October 2006 andcompared graphical representations from the most recent

PI report to the raw data toverify the data was included in the report. The inspectors also examined a selectedsample of operators' logs,

LER s,

CAP records and procedures to verify the

PI data wasappropriately captured for inclusion into the

PI report and the individual

PI s werecorrectly calculated. The inspectors verified that

PBAPS initiated an

IR (IR 588926) tocorrect a reporting error regarding the unplanned transients

PI. The

PIs reviewed were:*Unplanned Scrams per 7,000 Critical Hours (Unit 2 and 3);* Scrams with Loss of Normal Heat Removal (Unit 2 and 3); and* Unplanned Power Changes per 7,000 Critical Hours (Unit 2 and 3). b.FindingsNo findings of significance were identified.

21Enclosure4OA2Identification and Resolution of Problems (71152).1Routine Review of Items Entered Into the

CAP a.Inspection Scope As required by

IP 71152, "Identification and Resolution of Problems," and in order tohelp identify repetitive equipment failures, human performance issues or program issuesfor follow-up, the inspectors performed routine screening of issues entered intoPBAPS's

CAP. This review was accomplished by selectively reviewing copies of

IR s,attending daily screening meetings, and accessing

PBAPS 's computerized database. b.FindingsNo findings of significance were identified.4

OA 3Event Followup (71153 - 5 Samples) .1(CLOSED)

LER [[05000277/2006003-00, Elbow Leak on Piping Attached to SuppressionPool Results in Loss of Containment IntegrityOn October 7, 2006, an Unusual Event was declared for Unit 2 due to a loss of primarycontainment. The loss of primary containment was a result of the discovery of a leak ina 4 inch diameter pipe in a location external to the pipe's penetration of the primarycontainment suppression pool (i.e., torus). The leaking elbow was replaced and thesimilar pipe on Unit 3 was examined. Walkdowns and ultrasonic testing were performedon similar Unit 2 and 3 torus attached piping. These examinations did not identifysimilar concerns. The corrective actions to resolve the underlying causes of this eventwere entered into the]]

CAP (IR 541265). Additional details regarding this event werepreviously documented in

NRC Inspection Report 05000277,278/2006-005. Theenforcement aspects of this finding are discussed in Section 4

OA 3.2 of this report. ThisLER is closed..2(CLOSED) Unresolved Item (URI) 05000277/20060005-02, Loss of PrimaryContainment IntegrityURI 05000277/20060005-02 was opened in

NRC Inspection Report 050000277;05000278/2006005, pending the

NRC staffs' characterization of this issue following thereview of

PBAPS 's technical analyses and other documents. The characterization ofthis issue as a finding and its risk significance are discussed below. This

URI is closed. b.FindingsIntroduction: A self-revealing, Green

NCV of 10

CFR Part 50, Appendix B, Criterion V,"Instructions, Procedures, and Drawings," was identified for inadequate surveillanceprocedure development that changed the use of a common

PBAPS personneldiscovered a leak in piping attached to the Unit 2 suppression pool that resulted in aloss of primary containment integrity. The leaking piping was the

RCIC line to the torusfrom its original design purpose as a partial-flow flush line, to a full-flow test line.

2EnclosureDescription: As previously discussed, on October 7, 2006,

HPCI [[/RCIC torus flushline. The leak occurred on the intrados of a 45 degree elbow in the 4 inch nominalpiping and was located approximately one foot above the torus penetration (i.e., the leakwas outside of primary containment). The cracks in the elbow resulted from excessivelyhigh flow rates, cavitation, and turbulence. The inspectors reviewed]]

LER 05000277/2006003-00 and

PBAPS [['s root causeinvestigation report (IR 541265-29) to understand the underlying causes for this event. The inspectors noted that the licensee-identified root cause for this self-revealing eventwas inadequate surveillance procedure development and approval that changed the useof this common]]

RCIC line to the torus from its original design purpose as apartial-flow flush line, to a full-flow test line. Operation of this piping at flow velocitieshigher than intended was not identified when the

ST frequency was increased. The inspectors noted that the vendor instructions for

HPCI system operation andmaintenance were provided to

PBAPS in

GEK -9682, "Operations and MaintenanceInstructions, High Pressure Coolant Injection System for Peach Bottom Atomic PowerStation, Units 2 and 3," dated February 1971.

GEK -9682, Section

IV , MaintenanceInstructions, Subsection 4-4, "Flow Test," provides a procedure for full flow testing of theHPCI system. The procedure provides direction to operate the

HPCI [[turbine at reducedspeed (1000-1500 rpm) to limit flow while flushing water to the suppression pool throughboth the minimum flow bypass line and the torus flush line. Subsequently, theprocedure directs isolation of the torus flush line to the suppression pool and opening ofthe test bypass return line to the condensate storage tank before turbine speed isincreased to achieve the full pump flow rate of 5000 gpm.]]

ST -O-023-301-2, "HPCI Pump, Valve, Flow and Unit CoolerFunctional and In-Service Test," steps 6.5.23 to 6.5.26, provided instructions for aligningthe

ST procedure,

HPCI [[pump to discharge to the suppression pool at reduced speed and flow throughboth the minimum flow bypass line and the flush line. However, subsequent steps6.5.27 to 6.5.31 did not direct isolation of the torus flush line to the suppression poolbefore turbine speed was increased to achieve full rated pump flow of 5000 gpm. The]]

ST did not limit the flow rate through the flush line to the torus as intended byGEK-9682. The inspectors reviewed a technical evaluation (IR 541265-61) that identified initiatingevents where the existing through-wall cracks in the common

RCIC [[line would failand provide a flow path from inside the torus to outside the torus. The evaluationassumed that flow through the drywell to torus downcomers or through the safety reliefvalve (SRV) tailpipes would cause sufficient hydrodynamic load to result in the failure ofthis pipe. The inspectors also reviewed a technical evaluation (IR 541265-62) thatdetermined the amount of time required to lower suppression pool level and uncover thecommon]]

RCIC line, assuming no inventory make-up.

23EnclosureThe performance deficiency was inadequate surveillance procedure development andapproval that changed the use of a common

IMC 0609, Appendix A,"Significance Determination of Reactor Inspection Findings for At-Power Situations." The

RCIC [[line to the torus from itsoriginal design purpose as a partial-flow flush line, to a full-flow test line. Analysis: The finding is not subject to traditional enforcement in that the finding did nothave any actual safety consequence, did not have the potential for impacting the]]

NRC [['sability to perform its regulatory function, and there were no willful aspects. The finding ismore than minor because it is associated with the design control attribute of the BarrierIntegrity Cornerstone and affected the objective to provide reasonable assurance thatphysical design barriers (primary containment) protect the public from radio nuclidereleases caused by accidents or events.The inspectors evaluated the finding in accordance with]]

SDP Phase 1 screening identified that a Phase 2 analysis was needed because thefinding affected two Cornerstones, specifically the Mitigating Systems cornerstone andthe Barrier Integrity cornerstone. However, the

SRA conducted a Phase 3 evaluationbecause the issue was too complex to evaluate using the Plant Specific Phase 2Notebook.Using the site-specific Peach Bottom Standardized Plant Analysis Risk Model, Revision3.21, the

SRA made the following assumptions to evaluate this finding:*The exposure time of one-year was used in conducting the evaluation;*A hydrodynamic load (greater than 6 psig) in the torus would occur from a largeor medium break loss-of-coolant accident (

LOCA ) or a

SRV actuation. This loadwould be sufficient to cause torus water level to decrease, uncovering thedowncomer from the drywell and

HPCI /RCIC pipe;*Operator action, directed in the emergency operating procedures (EOPs), wouldrecover torus level. If low torus level is indicated in the main control room, then

RO s would be directed by the

EOP s to maintain torus level using the

HPSW system through the

RHR system and/or to cease injecting to the

RCS from thetorus to prevent damaging the injection pumps due to the low level. The failureof operators to perform these actions would cause an increase in

CDF andincrease the probability of post vessel breach release from containment (LERF);*For non-LOCA initiating events - if power conversion systems fail or wereassumed to fail due to the initiating event, an

SRV would lift. The containmentwould pressurize if suppression pool cooling failed. This would increase theprobability of a containment release (delta

LERF ) through the pipe break ifcontainment venting was successful (I.e., containment did not fail, prior to coredamage) and torus water level was lower than the pipe at the time of reactorvessel breach. This event does not cause an increase in delta

CDF because themitigating systems rely on the condensate storage tank as the primary source ofwater for

RCS injection.The

SRA developed a

HPSW/torus fill fault tree to model the torus pipe failure. Thefault tree included a basic event that would question the tree if only the torus pipe was

24Enclosureassumed to fail and modeled human action and motor operated valves with their electricdependency. The

SRA determined that this finding was of very low safety significance (Green),represented a very low change in delta

CDF (low to mid 1X10E-8), and a very lowchange of high 1X10E-8 in

LERF (delta

LERF ). The most dominant Phase 3 coredamage sequences involved the initiating events of large and medium

LOCA s, and thefailure of the operators to recover torus level. For large and medium

LOCA scenarios,the

HPSW /torus fill fault tree indicated that success in torus makeup would prevent lossof torus level; however, failing to refill the torus would cause an increase in delta

CDF and would result in an increase in delta

LERF. For other

LERF sequences that did notincrease

CDF , the core damage sequences that included

SPC failures, successfulcontainment venting (CV), and failure of late injection were identified. These sequenceswere then transferred to the torus fill event tree which included the

HPSW /torus fill faulttree and resulted in core damage occurring if the torus pipe retained its integrity (basecase). However, if the pipe was assumed to fail, the event tree would calculate theprobability of a release using the delta

CDF and assuming that the release factor of 1.0(for Mark I containment). Accident sequences with suppression pool cooling failure andCV failure were not included in the analysis because the containment was assumed tofail if

CV failed, thereby, no benefit would result by refilling the torus. A release wouldoccur if the

RCS was breached post-core damage.Enforcement:

10 CFR [[Part 50, Appendix B, Criterion V, "Instructions, Procedures, andDrawings," states, that activities affecting quality shall be prescribed by documentedprocedures and shall be accomplished in accordance with these procedures. Theprocedures shall include appropriate acceptance criteria for determining that importantactivities have been satisfactorily accomplished. Vendor document,]]

GEK -9682,provides a procedure for full-flow testing of the

HPCI system. However, this procedureprovides direction to operate the

HPCI [[turbine at reduced speed (1000-1500 rpm) tolimit flow while flushing water to the suppression pool through both the minimum flowbypass line and the torus flush line. Subsequently, the procedure directs isolation of thetorus flush line to the suppression pool and opening of the test bypass return line to thecondensate storage tank before turbine speed is increased to achieve the full pump flowrate of 5000 gpm. Contrary to the above, Exelon procedure]]

ST -O-023-301-2 provided instructions foraligning the

HPCI pump to discharge through the torus flush line to the suppression poolat full rated pump flow of 5000 gpm. Specifically, not limiting the flow rate through thetorus flush line to the torus as directed by

GEK -9682 resulted in excessively high flowrates and cavitation that led to piping erosion and the resultant through-wall leak in thepartial flow flush line to the torus. Because this finding is of very low safety significanceand has been entered into the

CAP (IR 5584677), this violation is being treated as aNCV consistent with Section

VI.A of the

NRC Enforcement Policy:

NCV 05000277/2007002-03, Failure to Develop and Implement

HPCI SurveillanceTesting in a Manner Consistent with Vendor Specified Test Instructions.

25Enclosure.3Unit 2 - Fire in 480 Volt Non-Vital Load Center - February 27, 2007 a.Inspection ScopeAt approximately 9:16 a.m. on February 27, 2007, a fire was suspected to have startedbased on the receipt of numerous secondary plant alarms in the main control room(MCR) and the report of smoke near the '4T4' 480 Volt load center. The inspectorsresponded to the

MCR [[following a site announcement for the fire brigade to respond toa suspected fire in the Unit 3 turbine building. The inspectors monitored the operators'response to the event and the status of plant equipment. The observations wereprimarily focused on the nuclear safety aspects of the plant's and operators' responses. The inspectors also monitored the response of]]

PBAPS 's emergency responseorganization to the declaration of an

UE. Subsequent to the fire, the inspectors discussed the fire with operations, engineeringand

PBAPS [[management personnel to gain an understanding of the event and toassess their followup actions. The inspectors reviewed operator logs and operators'actions taken in accordance with licensee procedures. Based on the operators'narrative logs, the fire brigade was dispatched to the Unit 3 turbine building atapproximately 9:20 a.m. Fire personnel investigated and notified the]]

MCR that anactual fire existed at 9:38 a.m. An Unusual Event for a fire not extinguished within15 minutes (emergency action level (

EAL )

HU 6) was declared at 9:41 a.m. All state andlocal government notifications were completed by 9:59 a.m. and the

NRC [[HeadquartersOperations Officer was notified of the event at 10:36 a.m. The fire was considered to beextinguished at approximately 10:32 a.m. At 11:37 a.m., the Unusual Event wasterminated. Prior to the report of the potential fire, Unit 3 was operating at full power. As a result offire and the associated response actions, numerous non-safety-related loads poweredby the '4T4' 480 Volt load center were de-energized. Equipment that was de-energizedincluded: the 'B' isophase bus cooler fan, the 'B' drywell chiller, the 'B' recirculationpump speed controller, the leading edge flow meters and the 'B' reactor feed pump. Plant operators took the required]]

TS [[actions and responded to the equipment losses byperforming controlled reactor power reductions and stabilized the plant at approximately50 percent of rated power.The inspectors verified that the required reports were made during the event and that nofurther reports are planned. The inspectors also verified that this issue (]]

IR 569889) wasplaced into the

CAP. Preliminarily,

PBAPS has determined that the fire resulted from anapparent mismatch between the ratings of one breaker and its cubicle in the '4T4' 480volt load center. A root cause investigation was ongoing at the end of the inspectionperiod and will be reviewed by the inspectors during a future inspection period.

26Enclosure b.FindingsAt the close of this inspection period, the inspectors were reviewing the event andawaiting the results of the root cause evaluation to understand the potentialperformance deficiencies. This issue is unresolved pending review of

PBAPS 's causalevaluation and corrective actions by the inspectors to characterize the issue.

URI 05000277/2007002-04, Incorrect Size Breaker Resulted in a Fire in the '4T4'480 Volt Load Center..4Personnel Performance - Missed Procedure Step Resulted in Unplanned Overloading ofthe E-3

EDG [[a.Inspection ScopeThe inspectors reviewed selected applicable plant records, correction action documentsand approved procedures while evaluating the performance of operations personnel inresponse to non-routine evolutions. The inspectors assessed personnel performance todetermine what occurred and how the operators responded, and to determine if plantpersonnel's response was in accordance with plant procedures and training. Thefollowing non-routine evolution was reviewed:*During the conduct of surveillance testing of the E-3]]

EDG [[on March 15, 2007, alicensed operator missed the performance of a required step in a supportingsystem operating procedure. The omission of the procedure step placed the E-3EDG in the isochronous mode while synchronized with offsite power through a4 kilovolt (kV) vital bus. This condition resulted in unexpectedly loading the E-3EDG beyond its 30-minute load rating. The]]

ST and supporting proceduresdirected the synchronization of the E-3

EDG to a selected 4 kV bus to pick upthe bus loads. The procedure subsequently directed opening the offsite powerfeeder breaker to the 4 kV vital bus (the missed step) before placing the

EDG inthe isochronous mode.

PBAPS placed this issue in the

CAP by initiating

IR [[604364. Prompt corrective actions included the selected implementation ofadditional peer checking of procedure performance place-keeping. The E-3EDG was inspected for potential damage and tested before being returned to anoperable condition in accordance with]]

TS [[on March 17, 2007. The causalevaluation of this event was ongoing at the end of the inspection period. b.FindingsAt the close of this inspection period, the inspectors were reviewing the event andawaiting the results of the causal evaluation to understand the potential performancedeficiencies. This issue is unresolved pending review of]]

PBAPS's causal evaluation andcorrective actions by the inspectors to characterize the issue. URI 05000277/2007002-05, Missed Procedure Step Resulted in Unplanned

Overloading of the E-3

EDG. 27Enclosure.5(CLOSED)

LER 05000277/2006001-00, Main Steam Isolation Valves Exceeded TheirAllowable Leakage LimitsOn September 22, 2006, engineering personnel determined that there were multipleleak rate test failures involving the main steam isolation valves (

MSIV s). Thisdetermination was based on local leak rate testing performed during the P2R16Refueling Outage. Four of the eight

MSIV s were found to be leaking in excess of theirallowable leakage limits, including both the inboard and the outboard

MSIV s for the 'D'main steam line. This condition resulted in a degraded plant safety barrier, a conditionprohibited by

TS s and a condition that resulted in multiple trains being inoperable in asafety system. The

MSIV s were repaired and returned to an operable status. Theas-left leakage rates were restored below the

TS allowable limits. The correctiveactions to resolve the underlying causes of this event are in the

CAP [[(IR 534622) andinclude planned actions to minimize the number of times that the valves are stroked formaintenance and testing in a dry condition to minimize accelerated wear of the internals. This finding is more than minor because it had a credible impact on safety, in that, if the'D' main steam line was required to isolate on a containment isolation signal, thepenetration leakage would be greater than the]]

TS [[allowable limits. Also, for the 'A' and'C' penetrations, if the redundant valve in the penetration did not close on a containmentisolation signal, containment integrity would not be ensured. The finding affects theBarrier Integrity Cornerstone and was considered to have very low safety significance(Green) using Appendix H of the]]

SDP because the likelihood of an accident leading tocore damage was not affected, the probability of early primary containment failure andtherefore a large early release was small. This licensee-identified finding involved aviolation of

TS 3.6.1.3, Primary Containment Isolation Valves. The enforcement aspectsof the violation are discussed in Section 4

OA 7 of this report. This

LER is closed. 4

OA 6Meetings, Including ExitExit Meeting SummaryOn April 20, 2007, the resident inspectors presented the inspection results to Mr.

J. Grimes and other

PBAPS staff, who acknowledged the findings. The inspectorsasked the licensee whether any of the material examined during the inspection shouldbe considered proprietary. No proprietary information was identified.

4OA 7Licensee-Identified ViolationThe following violation of very low safety significance (Green) was identified by thelicensee and is a violation of

NRC requirements which meet the criteria of Section

VI ofthe

NRC Enforcement Policy,

NUREG -1600, for being dispositioned a

NCV. *TS 3.6.1.3 requires that penetration flow paths with one or more

MSIV s notwithin

MSIV leakage rate limits be isolated within eight hours. Contrary to this,for an indeterminate period during the two-year operating cycle beforeSeptember 18, 2006, four

MSIV s were not within

MSIV leakage rate limits and

28Enclosurethe penetrations were not isolated within eight hours. This was identified in thelicensee's

CAP as

IR 534622. This finding is of very low safety significancebecause it does not represent an open pathway in the physical integrity of thereactor containment greater than that assumed in the

UFSAR , Chapter 14,"Plant Safety Analysis," for radiological consequences.

ATTACH MENT:

SUPPLE [[]]

MENTAL [[]]

INFORM [[]]

ATION A-1AttachmentSUPPLEMENTAL

INFORM [[]]

ATIONK EY

POINTS [[]]

OF [[]]

CONTAC [[]]

TE [[xelon Generation Company personnelJ. Grimes, Site Vice PresidentM. Massaro, Plant ManagerN. Alexakos, Manager, Engineering-ProgramsJ. Armstrong, Regulatory Assurance ManagerC. Behrend, Engineering DirectorC. Jordan, Chemistry ManagerD. Lewis, Operations DirectorG. Stathes, Maintenance DirectorS. Taylor, Manager, Radiation ProtectionA. Wasong, Training DirectorT. VanWyen, Operations Training ManagerB. Artus, Principal Requal Training InstructorR. Tyler, Simulator SupervisorW. Pilkey, Physician AssistantJ. Verbillis, Examination DeveloperJ. Chizever, Mechanical Design EngineeringD. Foss, Sr. Regulatory EngineerA. Franchitti, Electrical Design EngineeringNRC personnelMel Gray,]]

DRP , Branch 4, Branch ChiefJ. Caruso, Senior Operations EngineerJ. D'Antonio, Senior Operations EngineerM. Brown, Resident InspectorF. Bower, Senior Resident Inspector

LIST [[]]

OF [[]]

ITEMS [[]]

OPENED ,

CLOSED ,

AND [[]]

DISCUS SEDOpened05000277/2007002-04URIIncorrect Size Breaker Resulted in a Fire inthe '4T4' 480 Volt Load Center (Section

4OA 3.3)05000277/2007002-05

URIM issed Procedure Step Resulted inUnplanned Overloading of the E-3

EDG (Section 4

OA3.4)

A-2AttachmentOpened and Closed05000277, 278/2007002-01NCVNon-Technical Specifications PositionIncorrectly Credited for Active LicenseMaintenance (Section 1R11.1)05000277, 278/2007002-02NCVExelon Did Not Establish and ImplementAdequate Procedures for

QA of EffluentMonitoring as Required by

TS 5.4.1 (Section

2PS 1) 05000277/2007002-03

NCVF ailure to Develop and Implement

HPCIS urveillance Testing in a Manner Consistentwith Vendor Specified Test Instructions(Section 4

OA 3.2)Closed05000277/2006001-00LERMain Steam Isolation Valves ExceededTheir Allowable Leakage Limits (Section

4OA 3.5)05000277/2006003-00

LERE lbow Leak on Piping Attached toSuppression Pool Results in Loss ofContainment Integrity (Section

4OA 3.1)05000277/2006005-02

URIL oss of Primary Containment Integrity(Section

4OA 3.2)DiscussedNone.

LIST [[]]

OF [[]]

DOCUME NTS

REVIEW [[]]

EDSection 1R01: Adverse WeatherIR 568034, Evaluate Cross Tie Gate RemovalIR 584869, Station Critique for Discharge Canal Cross-Tie Gate RemovalAR A1596763, Evaluate Cross Tie Gate RemovalRT-O-28B-800-2, River Temperature and Flow MonitoringM-028-001, Discharge Canal to Intake Pond Gate OperationST-C-095-805-2, Liquid Radwaste Discharge

A-3AttachmentSection 1R02: Evaluation of Changes, Tests, or Experiments10

CFR 50.59 Safety Evaluations

PB -2004-002-E, Installation and Use of the Reactor Cavity Work Platform (RCWP) DuringOutage, Revision

1PB -2005-01-E, Use of

GNF 2 Lead Use Fuel Assemblies in

PB Unit 3 Cycle 16, Revision 0

PB -2005-003-E, Adopt

SQUG Methodology for Seismic Qualification of Equipment, Revision 0

PB -2006-01-E, Application of

TRACG 04 for Stability Analysis, Revision 010

CFR 50.59 ScreensPB-2004-022-S,

ECR [[]]

PB -00119 (U3

MPT and

UAT [[]]

SPR Logic Upgrade), Revision 0

PB -2005-007-S,

HPCI Turbine Vibration, Revision 0

PB -2005-009-S, Core Spray Line Break Detection Setpoint Change, Revision

0PB -2005-027-S, Provide

OPRM Clarifications in Tech Spec Bases Section 3.3, Revision

0PB -2005-031-S, Restoration of

SBO Test Circuit Due to Duct Bank Damage During

BRE #3Rock Anchor Drilling, Revision 0

PB -2005-033-S, Revise

HPSW System Design Press by

RO -2(3)-801 or 2(3) 789, Revision

0PB -2005-042-S, Install Temperature Monitoring in

SRV Pilot Valves, Revision

0PB -2005-046-S, Support Replacement of

ESW Valve

HV -3-33-518, Revision 0

PB -2005-065-S,

PBAPS [[]]

EDG Keep Warm Modifications, Revision

3PB -2005-067-S,

RWM Operability Check, Revision

0PB -2005-078-S, Installation of Restricting Orifices in the

HPCI Lube Oil System, Revision

0PB -2006-001-S,

SE -10 Procedure Revision, Revision

0PB -2006-006-S, Procedure Creation

AO 6F-2-2(3), Revision

0PB -2006-018-S,

RCWP Jib Crane, Revision

0PB -2006-029-S, Closing Torque Switch Bypass

MO -2-02-053A, Revision

0PB -2006-055-S, E-1 Diesel Aux Pump Abandonment, Revision 0Calculations86-5049524, Summary Report for Peach Bottom

BWR [[]]

RCWP Framing Design, Revision 2Corrective Action Reports340404490304492097513278598300*599323*600094*490319*

NRC Identified During Inspection

Drawings6280-M-37, Diesel Generator Auxiliary Systems (Lube Oil System), Sheet 3, Revision 40

A-4AttachmentSurveillance ProceduresST-O-62A-210-2,

RWM Operability Check, Revision 13Miscellaneous

GE Letter, Analysis of Postulated Collision between

NF 400 Mast 762E974G002 and Low ProfileJib Hoist 124D1815G001, dated 3/4/06

GE Letter, Lead Test Assembly Licensing, dated 8/24/81GE-NE-0000-003909767-00, Technical Evaluation to Support Introduction of

GNF 2 Lead UseAssemblies (

LUA ) in Peach Bottom Atomic Power Station Unit 3, Revision

0GE -

NE -0000-0052-5690-R0,

TRACG 04

DIVOM [[]]

10 CFR 50.59 Evaluation Basis, 4/06

NEDC -33144P,

GNF 2 Lead Use Assembly (

LUA ) for

PBAPS Unit 3, Revision 1

NEDE [[-24011-P-A-15, General Electric Standard Application for Reactor Fuel, 9/05NEDO-32465-A, Reactor Stability Detect and Suppress Solutions Licensing Basis Methodologyfor Reload Applications, 8/96PM L-200-VC-4, Limitorque Valve Operator Engineering Reference Manual, Revision]]

0PM -1076, Impact of

RCWP Jib Crane Failure on Fuel Handling Accident Analysis, Revision 0Supporting Information for 50-59 Evaluation No.

PB -2005-01-

EU pdated Final Safety Analysis Report, Peach Bottom Atomic Power Station, Revision 20Section 1R04: Equipment AlignmentSO 14.1.A-3, Revision 3, Core Spray System Alignment for Automatic or Manual OperationCOL 14.1.A-3B, Revision 9, Core Spray System Loop

BCOL 9A.1.A, Revision 9, Standby Gas Treatment System Automatic OperationP&

ID M-362, Sheet 2, Revision 60, Core Spray Cooling SystemProtected Equipment Tracking Sheet,

PBAPS Unit 2 & Common, dated January 22, 2007Protected Equipment Tracking Sheet,

PBAPS Unit 2 & Common, dated January 31,

2007IR 584836,

NOS [[]]

ID Protected Equipment List DiscrepanciesSection 1R05: Fire Protection

OP -AA-201-003, Revision 8, Fire Drill PerformanceRT-F-101-922-2, Revision 3, Fire Drill, completed 1/10/07PF-4C, Revision 5, Prefire Strategy Plan Unit 2 Rx Recirc Pump

MG Set Room, Radwaste Building, 135' Elevation

PF -72J, Revision 1, Prefire Strategy Plan Radwaste Building, 150' & 165' ElevationPF-136, Prefire Strategy Plan, Emergency Cooling Tower, Fire Zone

136PF -59, Revision 4, Prefire Strategy Plan Unit 2 Reactor Building

HPCI Room, 88' ElevationPrefire Strategy Plan U/3

RBCCW Room Radwaste Bldg. 116' Elevation, Fire Zone 12B,Revision 3Prefire Strategy Plan 2 'A' & 2 'C' Core Spray Room,

RX Building 91' 6" Elevation, Fire Zones5A & 5B, Revision 1Prefire Strategy Plan 2 'A' & 2 'C'

RHR Pump and

HX Rooms RB2 - 91' 6" Elevation, Revision 2

A-5AttachmentPrefire Strategy Plan 3 'A' & 3 'C'

RHR Pump and

HX Rooms

RB 2 - 91' 6" Elevation, Revision 2Section 1R06: Flood Protection Measures

DBD P-T-09, Revision 8, Internal HazardsIPE Section 3.3.8.2.3, "Reactor Building"Section 1R07: Heat Sink PerformanceRT-O-010-660-2,

RHR Heat Exchanger Performance Test, Revision 7, completed 3/10/07

NRC Generic Letter 89-13, Service Water System Problems affecting safety-related equipmentSection 1R11: Licensed Operator Requalification ProgramPSEG0731R, Low Torus Level Condition Requires Emergency BlowdownPSEG0715R, Hydraulic

ATWSR equalification Program Procedures

HR -AA-07-101, Revision 4, "Licensed Operator Medical Examination"OP-AA-105-101, Revision 10, "Administrative Process for

NRC License and Medical Requirements"

TQ-AA-106, Revision 8, "Licensed Operator Requal Training Program"TQ-AA-106-304, Revision 7, "Licensed Operator Requal Training Examination Development Job Aid"TQ-AA-106-305, Revision 3, "Licensed Operator Requal Training Examination Administration Job Aid"OP-AA-105-102, Revision 8, "NRC Active License Maintenance"Simulator Baseline Review of Documentation for Transient TestsSTRB 05-3 Exelon Nuclear Simulator Testing Review, 6/9/2005STRB 05-6 Exelon Nuclear Simulator Testing Review, undated

A-6AttachmentSimulator Transient TestsB.1.2.8 Maximum Recirculation Suction Break with Loss of Offsite Power

STPT -

RRS 20

&MAP 02, Revision 3, 10/25/2006.B.1.2.6 Turbine Trip Within Bypass Valve Capacity

STPT -MTA04, Revision 2, 10/20/2006B.1.2.5

STPT - Single Recirc Pump Trip, Revision 3, 10/4/2006B.1.2.1

STPT - Manual Scram, Revision 1, 10/04/2006B.1.2.10

SMPT [[]]

IPM 02

MSIV Closure with Failed Open

SRV and No High Pressure

ECCS ,Revision 1, 10/24/2006Simulator Normal Evolution Tests

SNOT [[]]

NOROP 1 Cold S/D to 100% Power, 12/15/2004

SNOT [[]]

NOROP 4 Scram and Restart to 100% Power, 12/15/2005

SNOT [[]]

NOROP 2 Plant S/D and Cooldown, 12/22/03

SNOT [[]]

NOROP 3 no title (includes reactor startup plus

ST surveillance procedures for

HPCI ,

RCIC ,

RHR ,

CS), 2/7/2007Simulator Steady State TestsSSPT-Heat Bal Simulator Heat Balance Test, Revision 1, 9/11/2006

Simulator Malfunction TestsSMPT

RHR 04

RHR Pump Discharge Line Break, Revision 6, 11/28/2006SMPT

VAC 01 480

VAC Bus Fault, Revision 5, 11/21/2006SMPT

VAC 03 480

VAC [[]]

MCC Fault, Revision 5, 10/10/2006

SMPT [[]]

RPS 05 Automatic Scram Circuit Failure, Revision 3, 11/21/2006

SMPT [[]]

RRS 07A Recirc Pump Shaft Seizure, Revision 6, 2/07/07 Plant Event Data Comparison with Simulator

PDRP 04007 Low Pressure Group 1 Unit 2, 2/24/2005PDRP 04009 Condensate Pump Trip, 12/28/2004Open

SWR s

SWR #

5654 PMS Digital Displays Do Not Work, 12/15/2003

SWR #

6550 MS /

OG [[Numac Rad Monitors Screen Broke on a Total of 3, 7/26/2004SWR# 8014 Core Model IssuesClosed Simulator Work Requests (SWRs)SWR# 9272 Rod position indication is blank after a scramSWR#]]

9632 AO -8098 and 8099 A & C stroke too fast

SWR #

9695 ST -R-002-910-2 step 6.1.8 was unsat

SWR # 9381 Problems with E324-O-A,

VAC 03

WSWR #

7412 RC [[]]

IC operates erratically

A-7AttachmentSWR# 7259 Problems noted with loss of Y-34SWR# 6194 Condenser not working correctlySWR# 7736 'A' Condensate string flow drops after

FW heater leakSection 1R12: Maintenance Effectiveness

IR 00579872, E-1

EDG Fuel Oil LeaksRed/Yellow Maintenance Rule (a)(1) Systems - System 52 -

EDG Improvement PlanAR A1424883, General Purpose

AR for Misc Evals for System 52 Issues

IR 00207837,

PBAPS [[]]

EDG Action PlanIR 00495141, Exhaust System Bolting Disassembly Results in a Large Percentage of the BoltsBreakingAR A1592701, Examine Lower Support Bolting for

RHR [[]]

HX 3 'D'AR A1591784, Replace 3 'D'

RHR Heat Exchanger Floating Head Assembly

AR A1558090, Disassemble, Bubble Test, Repair 3 'D'

RHR Heat Exchanger

AR A1578288, Increased Leak Rate for 3 'D'

RHR Heat Exchanger

IR 579005,

RIS -9081 Causing

HPSW High Rad AlarmIR 578998,

RIS -9082 Causing

HPSW High Rad AlarmIR 583564, Unit 2 'B' Loop

HPSW High Rad Alarm

IR 606881, 3 'D' Train of

RHR Has Exceeded

MR [[(A)(1) Performance CriteriaSection 1R13: Maintenance Risk Assessments and Emergent Work ControlC0219963, 2 'D' E001 Heat Exchanger Leak RepairHU-AA-1211, Pre-job Briefing Checklist for Unit 2 Generator Hydrogen Cooler RepairSA-AA-116-2124, Attachments 2 and 3, Job Hazard Analysis Form for Tightening of Hydrogen FlangeOn-Line Maintenance Approval Form, 3 'D']]

RHR Secondary Containment Breach, datedJanuary 23, 2007 Barrier Breach Permit 07-6, Hatch 24, dated January 25, 2007

IR 199380-37 & 38,

PORC 07-02 Action Items

GP -16, Breaching and Establishing Secondary Containment, Revision 28Pre-Job Briefing ChecklistHLA/IPA Briefing WorksheetEvaluation of Voluntary Entry into Tech Spec Action Statements for Secondary Containment toSupport

RHR Heat Exchanger Corrective Maintenance Work, Revision 0, dated 1/19/07

IR 579658, Floating Head Removal from 3 'D'

RHR Room

IR 579005,

RIS -9081 Causing

HPSW Hi Rad AlarmAR A1599678,

RIS -9081 Causing

HPSW Hi Rad AlarmAR A1599677,

RIS -9082 Causing

HPSW Hi Rad AlarmC0220444 - '4T4' Bus; Inspect, Rework as RequiredA1605389 - '4T4' Bus Fault, Inspect, Rework as RequiredA1605391 - 3 'B'

RFPT TrippedA1605414 - Loss of 30Y022-18A1605422 - 3 'A' Isophase Bus Cooling Fan Breaker TrippedA1605436 -

MO 3149B temporary powerA1605437 - 3 'B' D/W Chiller Trip

A-8AttachmentA1605471 - 3 'B' Isophase Bus

FME Inspection

AR A1607626 -

AO -2-23-042 Would Not Reopen During the Performance of

STST -O-023-301-2 -

HPCI Pump, Valve, Flow and Unit Cooler Functional and In-service Test,Revision 47, completed 3/14/07Peach Bottom Operator Narrative Logs 3/14/07

IR 604364, Human Error Results in E-3

EDG Overload & E-33 Breaker Trip

AR A1607776, Incomplete Procedure Performance During E-3

EDG TestingSection 1R15: Operability Evaluations

IR 453260,

RHR to

HPSW Leak -

HPSW Sample Shows Radiological Contamination in 3 'B'Loop

IR 583564, Unit 2 'B' Loop

HPSW High Radiation Alarm

IR 584041,

RHR 3 'D' Heat Exchanger Lower Support Gap and Missing Bolt

IR 584070, Near Miss Opportunity for Potential 3.0.3 Inoperability

AR A1551497-01, Assess Leak Rate Identified Via Bottom Head Sampling

AR A1578288, Increased Leak Rate for 3 'D'

RHR Heat Exchanger

AR A1592631, 3 'D'

RHR Exchanger/3 'B'

RHR Loop Discharge Pipe FlushTRT 06-47, 3 'D'

RHR Exchanger/3 'B'

RHR Loop Discharge Pipe FlushECR

PB 96-03159-000, Emergency Cooling Tower Freezing Issue

ECR [[]]

PB 96-03159-000, Attachment 1, Evaluation of Icing Conditions in the EmergencyCooling Tower Reservoir

IR 593397, 2 'C'

RHR Heat Exchanger Plug Insertion Tooling Failed

AR A1546765-20, Evaluate Leaving Pop-A-Plug Tooling Inside Plugged Tube Peach Bottom Lost Parts DatabaseER-AA-2006, Lost Parts EvaluationsMA-AA-716-008, Attachment 9, Loss of Integrity Actions, Recovery from a Loss of

FMEI ntegrity

MA -AA-716-008, Attachment 10, Loss of Integrity Notification and Recovery PlanIR 594481,

RHR to

HPSW Leakage Greater Than Acceptance CriteriaIR 148870,

RHR Heat Exchanger Leak: Evaluate per

CFR s and

ODCMIR 372040, Suspected 2B

RHR /HPSW Heat Exchanger

HPSW In-Leakage

AR A1607626 -

AO -2-23-042, Would not Reopen During the Performance of

STST -O-023-301-2,

HPCI Pump, Valve, Flow and Unit Cooler Functional and In-service Test,Revision 47, completed 3/14/07Peach Bottom Operator Narrative Logs 3/14/07

IR 00608000, Heat Transfer Test Unsat. Update

PTRM Entry

IR 513038,

3DE 058 Requires Cleaning (Micro-fouling)

IR 516995,

2DE 058 Heat Transfer Test Unsat. Revise

PTRM EntryA1577785,

3DE 058 Requires Cleaning (Micro-fouling)

RT -O-033-600-2, Revision 14, Flow Test of

ESW to

ECCS Coolers and Diesel GeneratorCoolersTRM 3.11 and Bases

A-9AttachmentSection 1R17: Permanent Plant ModificationsModificationsPB 02-00758, Add

SQUG Method for Seismic Qualification into

UFSAR , Etc., Revision

0PB 03-00119, U3 Main and Unit Aux

SPR Mod - Installation and Testing

ECR , Revision 2

PB -05-00068, E324 480V

LV Bkrs - Replace

OD Trip Devices with Solid State, Revision

0PB 05-00140, Replace Bearing Lube Oil Supply Ball Valves with Orifices, Revision 3

PB 05-00155, Core Spray Line Break Detection Vulnerability, Revision

0PB -05-00159, Install Line Stop Hdwr to Replace

ESW 518 Valve, Revision

5PB 05-00195, P00507 U2 Power Range Neutron Monitoring Mod - Reactor Stability, Revision 0

PB 05-00236, Revise

HPSW Design Pressure in M-30, Issue calc

PM -1071, Revision 0CalculationsPM-1071, Calculation of Pressure Drop through

HPSW System, Revision 0

PM -1075,

HPCI Lube Oil System Orifice Sizing, Revision 023-15

SP , Pipe Stress Analysis and Support Evaluation for

HPCI Lube Oil Line From Lube OilCooler 20E105, Revision 0Corrective Action Reports221323279193294570309624485619487311558911599882*600116*600132**

NRC Identified During InspectionDrawingsE-911, Electrical Secondary and Control Conn

MOV , Sheet 1, Revision 52E-359, Recirculation Pump Suction and Discharge Valve, Sheet 1, Revision 29E-1617, Single Line Meter and Relay diagram, Sheet 1, Revision 63Miscellaneous

DPIS -2-14-043B Instrument Calibration Sheet, Revision 2Midas Calc Results,

MOV [[]]

MO -2-02-053A, 10/2/06NE-164, Specification for Environmental Service Conditions Peach Bottom Atomic PowerStation Units 2 and 3, Revision 5P-T-17, Dynamic Qualification Program, Revision

4SQUG Letter, Revision 3A to the Generic Implementation Procedure for Seismic Verification ofNuclear Power Plant Equipment, dated 2/16/04

SQUG Memorandum, Use of

GIP Revision 3A, dated 6/14/0533-55045-

QS, Class 1E Electrical Equipment Environmental Qualification Report, Revision 26280-M1JJ-97, Instruction Manual Motor Operated Gate Valves, Revision 0

A-10Attachment11187-G-14, General Project Requirements for Seismic Design and Analysis of Equipment andEquipment Supports for Peach Bottom Atomic Power Station Units 2 & 3, Revision 0ProceduresAO 10.8-2, Placing Torus Cooling in Service with

LOCA Signal Present or Has Occurred, Revision 8

CC -AA-320-002, Use of

SQUG Methodology for the Seismic Qualification of New andReplacement Items, Revision 0

CC -AA-320-1004, Guidance for the Use of

SQUG Methodology for the Seismic Qualification ofNew and Replacement Items, Revision 1M-055-005, 480 Volt I-T-E Solid State Breaker Trip Device Testing, Revision 1

NE -C-420-04, Setpoint Methodology, Revision

1SE -10, Alternate Shutdown Procedure, Attachments 1-4, 7, Revision 14S0 48.1.B, Emergency Cooling Water System Startup, Revision 11Surveillance Procedures

ST -O-054-753-2, E32

4KV Bus Undervoltage Relays and

LOCA Loop Functional Test, Revision 17Work OrdersA1188670C0216690Section 1R19: Post-Maintenance TestingA1602476,

ESW Pump 0

AP 057 Discharge Check ValveR1049544,

ESW , Valve Unit Clr and

ECT Fans

ISTST -O-033-300-2, Revision 31,

ESW , Valve, Unit Cooler and

IST , performed 2/3/07ST-O-033-300-2, Revision 31,

ESW , Valve, Unit Cooler and

IST ,performed 2/4/07C0220132, 2-5A-K003A: Replace Relay and Perform

PMTIR 00585972, 2-5A-K003A Relay FailedSI2M-60F-RT7-A4M2, Revision 4, Response Time Test of

MSIV Closure Scram Channel

AA 1225120, Intake Struct Vent Exh

3AV 83R0810095, E124-P-A (6244) Perform

MCU InspectionAO 56.1, Revision 4, Removing and Installing a

480 VAC Motor Control Center Bucket

ST -O-010-640-3, 3 'D'

RHR Heat Exchanger Leak Test

ST -O-010-306-3, 'B'

RHR Loop Pump, Valve, Flow and Unit Cooler Functional and InserviceTestA1607776, E-3 Diesel Generator, Incomplete Procedure Performance During Testing Resultsin E-3 Generator TripC0219643, 2

AP 040 Clean/Inspect/Repack Cylinders (2 'A'

SLC Pump)

ST-O-011-301-2, Standby Liquid Control Pump Functional Test for IST, completed 3/27/07

A-11AttachmentIR 0604364, E-3 Diesel Trip During TestingST-O-052-123-2, Diesel Generator

RHR Pump Reject Test

ST -O-052-213-2, E3 Diesel Generator Slow Start Full Load and

IST TestA1603535, U2

HPCI [[]]

ST -003 Modification

PMT Unexpected ResultIR 00590626, U2

HPCI [[]]

ST -003 Modification

PMT Unexpected ResultC0220288, Recal/Rework/Replace

LS -2-23-090 as Required (U2

HPCI Steam Supply Drain Pot Level)

WO C0220652,

0CG 012-

DR InspectionsWO R1011869,

CHK -O-33-515A; Disassemble Inspect/Rework

WO R0810095, E124-P-A (6244) Perform

MCU Inspection 590973, Steam Leak through

HV -2-23C-21173Section 1R22: Surveillance TestingST-O-052-701-2, Rev 16, E-1 Diesel Generator 24-Hour Endurance Test, completed 1/18/07SI3F-13-84-XXCQ, Revision 18, Calibration Check of

RCIC Steam Line High Flow Instrument

DPIS , 3-13-84, completed 1/22/07SI3F-13-83-XXCQ, Revision 21, Calibration Check of

RCIC Steam Line High Flow Instrument

DPIS , 3-13-83, completed 1/22/07ST-O-020-560-2, Reactor Coolant Leakage Test, Performed 1/27/07ST-O-033-300-2, Revision 31,

ESW , Valve, Unit Cooler, and