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August 10, 2009

Mr. Charles Senior Vice President, Exelon Generation Company, LLC President and Chief Nuclear Officer, Exelon Nuclear 4300 Winfield Road Warrenville, IL 60555

SUBJECT: PEACH BOTTOM ATOMIC POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000277/2009003 AND 05000278/2009003

Dear Mr. Pardee:

On June 30, 2009, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Peach Bottom Atomic Power Station (PBAPS), Units 2 and 3. The enclosed integrated inspection report documents the inspection results, which were discussed on July 17, 2009, with Mr. William Maguire and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. Based on the results of this inspection, two self-revealing findings of very low safety significance (Green) were identified. One of these findings was determined to involve a violation of NRC requirements. Additionally, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. However, because of the very low safety significance and because the finding has been entered into your corrective action program (CAP), the NRC is treating the finding as a non-cited violation (NCV), consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest the NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, U. S. NRC, Washington, DC 20555-0001; and the NRC Resident Inspector at the PBAPS. In addition, if you disagree with the characterization of the cross-cutting aspect of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region 1 and the NRC Senior Resident Inspector at PBAPS. The information you provide will be considered in accordance with Inspection Manual Chapter (IMC) 0305.

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

Sincerely,/RA/ Paul G. Krohn, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos.: 50-277, 50-278 License Nos.: DPR-44, DPR-56

Enclosures:

Inspection Report 05000277/2009003 and 05000278/2009003

w/Attachment:

Supplemental Information cc w/encl:

C. Crane, President and Chief Operating Officer, Exelon Corporation M. Pacilio, Chief Operating Officer, Exelon Nuclear W. Maguire, Site Vice President, Peach Bottom J. Grimes, Acting Senior Vice President, Mid-Atlantic R. Hovey, Senior Vice President, Nuclear Oversight G. Stathes, Plant Manager, Peach Bottom J. Armstrong, Regulatory Assurance Manager, Peach Bottom J. Bardurski, Manager, Financial Control & Co-Owner Affairs R. Franssen, Director, Operations P. Cowan, Director, Licensing D. Helker, Licensing K. Jury, Vice President, Licensing and Regulatory Affairs J. Bradley Fewell, Associate General Counsel, Exelon T. Wasong, Director, Training Correspondence Control Desk D. Allard, Director, Bureau of Radiation Protection, PA Department of Environmental Protection S. Gray, Administrator, Maryland Power Plant Research Program S. Pattison, Secretary, SLO, Maryland Department of the Environment M. Griffen, Maryland Department of Environment Public Service Commission of Maryland, Engineering Division Board of Supervisors, Peach Bottom Township B. O'Connor, Council Administrator of Harford County Council Mr. & Mrs. Dennis Hiebert, Peach Bottom Alliance E. Epstein, TMI - Alert J. Johnsrud, National Energy Committee, Sierra Club Mr. & Mrs. Kip Adams R. Fletcher, Dir, MD Environmental Program Manager, Radiological Health Program Director, Nuclear Safety Project, Union of Concerned Scientists R. Ayers, Deputy Mgr, Harford County Div of Emergency Operations E. Crist, Harford County Div of Emergency Operations S. Ayers, Emergency Planner, Harford County Div of Emergency Operations R. Brooks, Cecil County Dept of Emergency Services Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/ Paul G. Krohn, Chief Reactor Projects Branch 4 Division of Reactor Projects Distribution w/encl: (via E-mail) S. Collins, RA M. Dapas, DRA D. Lew, DRP J. Clifford, DRP P. Krohn, DRP R. Fuhrmeister, DRP A. Rosebrook, DRP E. Torres, DRP J. Bream, DRP F. Bower, DRP, SRI M. Brown, DRP, RI S. Schmitt, DRP, OA L. Trocine, RI OEDO H. Chernoff, NRR R. Nelson, NRR J. Hughey, PM NRR P. Bamford, Backup NRR ROPreports@nrc.gov Region I Docket Room (with concurrences) SUNSI Review Complete: ___PGK___ (Reviewer's Initials) ML092220599 DOCUMENT NAME: G:\DRP\BRANCH4\INSPECTION REPORTS\PEACH BOTTOM\PBIR2009-003 REV 4.DOC After declaring this document "An Official Agency Record" it will be released to the Public. To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy OFFICE RI/DRP RI/DRP RI/DRP NAME FBower/ PGK for JBream/ * PKrohn/ PGK DATE 08/10 /09 07/ 24 /09 08/10 /09 OFFICIAL RECORD COPY * Concurred on 7/24/09, JRB 1 Enclosure U.S. NUCLEAR REGULATORY COMMISSION REGION I Docket Nos.: 50-277, 50-278 License Nos.: DPR-44, DPR-56 Report No.: 05000277/2009003 and 05000278/2009003 Licensee: Exelon Generation Company, LLC Facility: Peach Bottom Atomic Power Station, Units 2 and 3 Location: Delta, Pennsylvania Dates: April 1, 2009 through June 30, 2009 Inspectors: F. Bower, Senior Resident Inspector M. Brown, Resident Inspector E. Torres, Project Engineer A. Ziedonis, Reactor Inspector Approved by: Paul G. Krohn, Chief Reactor Projects Branch 4 Division of Reactor Projects

Enclosure 2

SUMMARY OF FINDINGS

......................................................................................................... 3

REPORT DETAILS

REACTOR SAFETY

.............................................................................................................. 5 1R01 Adverse Weather Protection ............................................................................................ 5 1R04 Equipment Alignment ....................................................................................................... 6 1R05 Fire Protection ................................................................................................................. 7 1R11 Licensed Operator Requalification Program .................................................................... 8 1R12 Maintenance Effectiveness ............................................................................................. 9 1R13 Maintenance Risk Assessments and Emergent Work Control ......................................... 9 1R15 Operability Evaluations .................................................................................................. 10 1R18 Plant Modifications ........................................................................................................ 10 1R19 Post-Maintenance Testing ............................................................................................. 11 1R22 Surveillance Testing ...................................................................................................... 11 1EP6 EP Drill Evaluation

OTHER ACTIVITIES

....... 13

4OA1 Performance Indicator Verification

................................................................................ 12

4OA2 Identification and Resolution of Problems (PI&R)

......................................................... 13

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

......................................... 18

4OA5 Other Activities .............................................................................................................. 21 4OA6

Meetings, Including Exit ................................................................................................. 22

4OA7 Licensee-Identified Violations ........................................................................................ 22

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

.................................................................................................. A-1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

....................................................... A-1

LIST OF DOCUMENTS REVIEWED

...................................................................................... A-2

LIST OF ACRONYMS

...... ...................................................................................................... A-9

SUMMAR Y

OF [[]]

FINDIN [[]]

GS IR 05000277/2009003, 05000278/2009003; 04/01/2009 - 06/30/2009; Peach Bottom Atomic

Power Station, Units 2 and 3; Identification and Resolution of Problems; Follow-up of Events and Notices of Enforcement Discretion.

The report covered a three-month period of inspection by resident inspectors and an announced inspection by a regional reactor inspector. Two self-revealing findings were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using

IMC 0609, "Significance Determination Process" (

SDP ). Findings for which the

SDP does not apply may be Green or be assigned a severity level after

NRC management review. Cross-cutting aspects associated with findings are determined using

IMC 0305, "Operating Reactor Assessment Program," dated January 2009. The

NRC 's program for overseeing the safe operation of commercial nuclear power reactors is described in

NUR [[]]

EG-1649, "Reactor

Oversight Process," Revision 4, dated December 2006. Cornerstone: Initiating Events * Green. A self-revealing finding was identified when

PBAPS personnel incorrectly performed a maintenance procedure for tuning the reactor recirculation pump (

RRP) motor generator (MG) set voltage regulator. Specifically, maintenance personnel

adjusted a potentiometer in the wrong direction, which resulted in a trip of the RRP and an unplanned plant transient. This finding is more than minor because the finding is associated with the human performance attribute of the Initiating Events Cornerstone, and adversely affected the

cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions. Specifically, this error resulted in an unplanned plant transient that reduced reactor power from 75 percent to 33 percent. In accordance with IMC 0609, Attachment 4, the inspectors determined this finding to be of very low safety significance (Green) since the finding did not contribute to both the likelihood of a

reactor trip and the likelihood that mitigation equipment or functions would not be available. This finding has a cross-cutting aspect in the area of human performance, Work Practices, because

PBAPS did not define and effectively communicate expectations regarding procedural compliance and personnel did not follow procedures H.4(b). Specifically,

PBAPS personnel did not follow procedure IC-11-02011

instructions for tuning the 3 'A'

RRP [[]]

MG set voltage regulator. (Section

4OA 3.1) Cornerstone: Mitigating Systems and Barrier Integrity * Green. A self-revealing

NCV of

10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," was identified. Specifically, Exelon's Motor Operated Valve (

MOV ) Program procedures lacked specific instructions to prescribe an acceptable frequency for performing valve stem lubrication, which resulted in test failures of safety-related

MOV s and affected the reliability of the

MOVs' safety functions.

On Unit 2, the inspectors determined that the finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability,

and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). In accordance with IMC 0609, Attachment 4, the inspectors determined that the finding was of very low safety significance (Green)

because it was not a design or qualification deficiency, did not represent a loss of system safety function, and was not associated with any external events. On Unit 3, the inspectors determined that the finding was more than minor because it was associated with the configuration control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design

barriers (e.g., containment) protect the public from radionuclide releases caused by accidents or events. In accordance with

IMC [[0609, Attachment 4, the inspectors determined that the finding was of very low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of reactor containment. For both units, this finding has a cross-cutting aspect in the area of Problem Identification and Resolution (]]

PI&R ), Corrective Action Program, because

PBA [[]]

PS did not thoroughly evaluate problems such that the resolutions addressed the causes and extent of

condition P.1(c). Specifically,

PBAPS failed to thoroughly evaluate previous conditions of degraded and hardened grease on safety-related valves, such that the extent of the condition was considered and the cause was resolved. (Section 4

OA 2) Other Findings A violation of very low safety significance, which was identified by the licensee, has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's

CAP. This violation and the licensee's corrective action tracking numbers are listed in Section 4

OA 7 of this report.

REPORT [[]]

DETAIL S Summary of Plant Status Unit 2 began the inspection period at 100 percent rated thermal power (RTP). On April 24, a power reduction to 23 percent

RTP was conducted in response to continued degradation and heating of electrical components in the electro-hydraulic control (

EHC) system. On April 26, the unit was returned to full power. Unit 2 remained at or near full power for the remainder of the

inspection period. Unit 3 began the inspection period at 100 percent

RTP. On May 22, power was reduced to 75 percent

RTP to support planned summer readiness maintenance and adjustments to a

RRP [[]]

MG set voltage regulator. An unplanned power reduction from 75 percent to 32 percent occurred when the 3 'A'

RRP tripped during the adjustments to its

MG set voltage regulator. On May 25, the unit was returned to full power. On June 13, 2009, the unit was reduced to 62 percent for

emergent maintenance to repair degrading condenser in-leakage on the 3 'B' main feed pump turbine exhaust expansion joint. On June 14, 2009, the unit was returned to full power. Unit 3 remained at or near full power for the remainder of the inspection period.

1.

REACTO R

SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01 - 2 Samples)

.1 Grid Reliability a. Inspection Scope The inspectors reviewed plant features and procedures for operation and continued

availability of offsite and backup power systems during adverse weather (summer conditions). The inspectors reviewed communication protocols between the control room personnel and electrical system operations, as well as measures prescribed and taken to maintain the availability and reliability of these alternating current (AC) systems. Documents reviewed during this inspection are listed in the Attachment. b. Findings No findings of significance were identified. .2 Summer Seasonal Readiness Preparations

a. Inspection Scope The inspectors conducted a review of

PBA [[]]

PS 's preparations for the 2009 summer conditions to verify selected features of the plant's design were sufficient to protect mitigating systems from the effects of adverse weather. The inspectors reviewed

PBAPS 's implementation of procedure

WC-AA-107, "Seasonal Readiness," in preparation for summer season readiness. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when

challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensee's procedures used to mitigate or respond to adverse weather conditions. The inspectors reviewed the Updated Final Safety Analysis

Report (UFSAR) and performance requirements for systems selected for inspection. The inspectors reviewed

CAP records to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their

CAP. In addition, the inspectors reviewed the "Certification of 2009 Summer Readiness" memorandum dated May 15, 2009. Documents reviewed during this inspection are

listed in the Attachment. The inspectors walked down the following systems and equipment: * Intake Structure Ventilation System; * Emergency Diesel Generator (EDG) Building Ventilation System; and * 'A' Supplemental Cooling Tower. b. Findings No findings of significance were identified. 1R04 Equipment Alignment

.1 Partial Walkdown (71111.04Q - 3 Samples) a. Inspection Scope The inspectors performed a partial walkdown of three systems to verify the operability of

redundant or diverse trains and components when safety-related equipment was inoperable. The inspectors reviewed selected applicable operating procedures, walked down system components, and verified that selected breakers, valves, and support equipment were in the correct position to support system operation. Documents reviewed during this inspection are listed in the Attachment. The inspectors walked

down the systems below: * E-1

EDG with E-3

EDG Out-Of-Service (OOS); * E-2, 3, and

4 EDG s with E-1

OOS; and * 'A' Control Room Chilled Water System with 'B' Control Room Chilled Water System OOS. b. Findings No findings of significance were identified.

.2 Complete Walkdown (71111.04S - 1 Sample) a. Inspection Scope The inspectors performed a complete system walkdown of the accessible portions of the

Unit 2 reactor core isolation cooling system (RCIC), verifying that accessible breakers, valves and support equipment were properly aligned to support system operation. The inspectors reviewed system operating procedures and piping and instrumentation drawings; walked down control system components; and verified that circuit breakers

and valves were in the appropriate positions. Documents reviewed during this inspection are listed in the Attachment.

b. Findings No findings of significance were identified 1R05 Fire Protection .1 Fire Protection - Tours (71111.05Q - 5 Samples) a. Inspection Scope The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment. The inspectors reviewed areas

to assess if

PBAPS had implemented the Peach Bottom Fire Protection Plan (

FPP [[) and adequately: controlled combustibles and ignition sources within the plant; maintained fire detection and suppression capability; and maintained the material condition of passive fire protection features. For the areas inspected, the inspectors also verified that]]

PBAPS had followed the Technical Requirements Manual (

TRM) and the FPP when

compensatory measures were implemented for OOS, degraded, or inoperable fire protection equipment, systems, or features. The inspectors verified: that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient combustible materials were managed in accordance with plant procedures; and fire doors, dampers, and

penetration seals appeared to be in satisfactory condition. Documents reviewed during this inspection are listed in the Attachment. The inspectors toured the following areas: * Unit 3 Reactor Building Closed-Cooling Water (RBCCW) Room, Unit 3 Radwaste Building, 116' Elevation (Fire Zone 12B); * Unit 3 High-Pressure Coolant Injection (HPCI) Room, Unit 3 Reactor Building, 88' Elevation (Fire Zone 62); * Unit

2 RRP [[]]

MG Set Room, Radwaste Building, 135' Elevation (Fire Zone 4C); * Main Control Room, Turbine Building, 165' Elevation (Fire Zone 108); and * Unit 3 Lube Oil Tank Room, Turbine Building, 116' Elevation (Fire Zone 89). b. Findings

No findings of significance were identified. .2 Annual Fire Protection Drill Observation (71111.05A - 1 Sample) a. Inspection Scope On April 16, 2009, the inspectors observed fire brigade classroom training and live-fire drills at the

PE [[]]

CO Energy Fire Academy in West Conshohocken, Pennsylvania. The inspectors noted that the classroom training provided a refresher on the Incident Management System and its techniques, methods, and terminology that are used to manage fire fighting or hazardous material events.

The inspectors noted that the live-fire fighting was done in burn facilities that simulated a transformer oil fire and fire involving plant cabling and equipment. The observation was used to determine whether appropriate learning opportunities were provided and to

determine the readiness of the plant fire brigade to fight fires. The inspectors verified that the

PBA [[]]

PS fire brigade participants and the training instructors identified deficiencies; openly discussed them in a self-critical manner at the drill debrief, and appropriately documented the identified issues to develop corrective actions for future training. Specific attributes evaluated were:

Proper Wearing of Turnout Gear and Self-contained Breathing Apparatus; * Proper Use and Layout of Fire Hoses; * Employment of Appropriate Fire Fighting Techniques; * Sufficient Fire Fighting Equipment Brought to the Scene; * Effectiveness of Fire Brigade Leader Communications, Command, and Control; * Search for Victims and Propagation of the Fire Into Other Plant Areas; * Smoke Removal Operations; * Use of Pre-planned Strategies; * Adherence to the Pre-planned Drill Scenario; and * Drill Objectives. The inspectors verified that procedure RT-F-101-922-2, "Fire Drill," was completed to record the fire drill scenario used, document that the drill objectives were met, and capture the critique results. b. Findings No findings of significance were identified.

1R11 Licensed Operator Requalification Program (71111.11Q - 1 Sample) .1 Resident Inspector Quarterly Review a. Inspection Scope On June 23, 2009, the inspectors observed two crews of licensed operators in the plant's simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance deficiencies, and training was being conducted in accordance with licensee

procedures. The crew's performance was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed during this inspection are listed in the Attachment. The inspectors evaluated the following areas: * Licensed Operator Performance; * Crew's Clarity and Formality of Communications; * Ability to Take Timely Actions in the Conservative Direction; * Prioritization, Interpretation, and Verification of Annunciator Alarms; * Correct Use and Implementation of Abnormal and Emergency Procedures; * Control Board Manipulations; * Oversight and Direction from Supervisors; and

Ability to Identify and Implement Appropriate Technical Specification (TS) Actions and Emergency Plan Actions and Notifications. b. Findings No findings of significance were identified. 1R12 Maintenance Effectiveness (71111.12Q - 2 Samples) a. Inspection Scope The inspectors evaluated

PBAPS 's work practices and follow-up corrective actions for safety-related structures, systems, and components (

SSC s) and identified issues to assess the effectiveness of

PBAPS 's maintenance activities. The inspectors reviewed the performance history of

SSC s and assessed Exelon's extent-of-condition (EOC) determinations for those issues with potential common cause or generic implications to evaluate the adequacy of the

PBA [[]]

PS 's corrective actions. The inspectors assessed

PBAPS 's

PI&R actions for these issues to evaluate whether

PBAPS had appropriately monitored, evaluated, and dispositioned the issues in accordance with Exelon procedures and the requirements of 10

CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance." In addition, the inspectors reviewed selected SSC classifications, performance criteria and goals, and Exelon's corrective actions that were

taken or planned, to evaluate whether the actions were reasonable and appropriate. Documents reviewed during this inspection are listed in the Attachment. The inspectors reviewed the following two samples: * Repeat Master Trip Solenoid Valve (MTSV) Issues (IR 918352); and * Apparent Cause Evaluation for Tritium Increase in Groundwater Monitoring Well #4 (IR 808183). b. Findings No findings of significance were identified. 1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 4 Samples)

a. Inspection Scope The inspectors evaluated

PBAPS =s implementation of their Maintenance Risk Program with respect to the effectiveness of risk assessments performed for maintenance activities that were conducted on

SSC s. The inspectors also verified that the licensee managed the risk in accordance with

10 CFR Part 50.65(a)(4) and procedure

WC -AA-101,

AO n-line Work Control Process." The inspectors evaluated whether

PBAPS had taken the necessary steps to plan and control emergent work activities and to manage overall plant risk. The inspectors selectively reviewed

PBA [[]]

PS's use of the online risk monitoring software, and daily work schedules. The activities selected were based on plant maintenance schedules and systems that contributed to risk. Documents reviewed during this inspection are listed in the Attachment. The inspectors reviewed the following samples:

10 * Emergent Power Reduction for Work to Correct Heating of Two Relays in the Unit

2 EHC System (Work Order (

WO ) C0227471 &

IR 870284-08); * Work Activities Associated with Unit 2 Residual Heat Removal (

RHR ) Discharge Valve

MO -2-10-154B and Unit 3

RHR Pump Suction Valve

MO -3-10-13D Underthrust Conditions (

WO C0228319); * Foreign Material was Found in Unit 3 'A'

EHC Pump's Discharge Filter (

WO C0228763); and * Exceeded Adverse Condition Monitoring Plan (ACMP) Action Level for Unit 3 Main Condenser (WO A1714585). b. Findings No findings of significance were identified. 1R15 Operability Evaluations (71111.15 - 4 Samples)

a. Inspection Scope The inspectors assessed the technical adequacy of the operability evaluations, the use and control of compensatory measures, and compliance with the licensing and design bases. Associated

AC [[]]

MPs, engineering technical evaluations, and operational and technical decision making documents were also reviewed. The inspectors verified these processes were performed in accordance with the applicable administrative procedures

and were consistent with

NRC guidance. Specifically, the inspectors referenced procedure

OP -AA-108-115, "Operability Determinations," and

NRC [[]]

IMC Part 9900, "Operability Determinations & Functionality Assessments for Resolutions of Degraded or Nonconforming Conditions Adverse to Quality or Safety." The inspectors also used Technical Specifications (TSs),

TRM ,

UFSAR, and associated Design Basis Documents

as references during these reviews. Documents reviewed during this inspection are listed in the Attachment. The inspectors reviewed the following samples: * Determine the Scope of Torus Material and Method (Wet\Dry) that Requires Recoat in Unit 2 [P2R19] and Unit 3 [P3R18] Refueling Outages (IR 873016-03); * Electrical Distribution Bases (3.8.7) Potential Needs Upgraded (IR 894904); * Exceeded

ACMP Action Levels for Unit 3 Main Condenser Air In-Leakage (

IR 928762); and * Unit 2 Reactor Recirculation Motor Breaker Action Level Changed from

BLUE to

YELLOW (IR 881184). b. Findings

No findings of significance were identified. 1R18 Plant Modifications (71111.18 - 1 Sample) .1 Temporary Modifications a. Inspection Scope

11 The inspectors reviewed one temporary modification to verify that implementation of the modification did not place the plant in an unsafe condition. The review was also conducted to verify that the design bases, licensing bases, and performance capability of risk significant

SSC s had not been degraded as a result of these modifications. The inspectors verified the modified equipment alignment through control room instrumentation observations;

UFSAR , drawings, procedures, and

WO reviews; and plant walkdowns of accessible equipment. Documents reviewed during this inspection are listed in the Attachment. The inspectors reviewed the following sample: *

ECR 09-00078 000, Re-Route Cables from Damaged Duct Bank To Support Duct Bank Repair. b. Findings No findings of significance were identified. 1R19 Post-Maintenance Testing (71111.19 - 7 Samples) a. Inspection Scope The inspectors observed selected portions of post-maintenance testing (PMT) activities and reviewed completed test records. The inspectors observed whether the tests were

performed in accordance with the approved procedures and assessed the adequacy of the test methodology based on the scope of maintenance work performed. In addition, the inspectors assessed the test acceptance criteria to evaluate whether the test demonstrated that the tested components satisfied the applicable design and licensing bases and the TS requirements. The inspectors reviewed the recorded test data to

verify that the acceptance criteria were satisfied. Documents reviewed during this inspection are listed in the Attachment. The inspectors reviewed the following samples: * Perform Leak Sealant Injection on Regenerative Heat Exchanger Tube Side Outer Vent Valve (WO C0228895); * 2 'A' Drywell Chiller, Rebuild and Eddy Current Test (WO C0220912); * 2 'A'

CAD Analyzer Failed to Trip During

ST -I-07G-103-2 (WO C0229040); * Replace Tube Bundles in the E-1

EDG (

WO C0225963); * Replace 'A' Control Room Supply Fan Motor (WO C0229077); * Troubleshoot

EDG E-1 Speed Switch, Rework as Required (

WO C0229510); and * Replace 3B

EHC Micron Filter (

WO M1716915). b. Findings

No findings of significance were identified. 1R22 Surveillance Testing (71111.22 - 5 Samples) a. Inspection Scope The inspectors compared test data with established acceptance criteria to verify the systems demonstrated the capability of performing the intended safety functions. The inspectors also verified that the systems and components maintained operational

2 readiness, met applicable TS requirements, and were capable of performing design basis functions. Documents reviewed during this inspection are listed in the Attachment. The inspectors reviewed the following samples:

RT -O-01D-402-2, Master Trip Solenoid Valves Operability Test; *

SI 3P-5-12-C1C2, Calibration Check of reactor protection system (RPS) Drywell Pressure Loop Instruments

PT /

PS 3-5-12C; *

ST -M-40D-905-2, Control Room Emergency Ventilation Filter Train 'A' Test; *

ST -O-010-301-2, 2 'A'

RHR [[Loop Pump, Valve, Flow, and Unit Cooler Functional and Inservice Test [Inservice Test Sample]; and *]]

ST [[-O-020-560-2, Reactor Coolant Leakage Test [RCS Leakage Sample]. b. Findings No findings of significance were identified. Cornerstone: Emergency Preparedness (EP)]]

1EP 6

EP Drill Evaluation (71114.06 - 1 Drill Sample) a. Inspection Scope The inspectors evaluated the conduct of a

PBA [[]]

PS emergency drill on June 1, 2009, to

identify any weaknesses and deficiencies in classification and notification activities. The drill was conducted to provide drill and exercise performance (DEP) opportunities for the

DEP performance indicator (

PI). The inspectors observed operators respond to events in the simulator control room through the declaration and notification of an alert. The inspectors observed the operations shift manager transition emergency response command and control responsibilities to the site emergency director in the technical support center (TSC). The inspectors relocated to the TSC to observe command and

control of the emergency response organization and dose assessment as the event escalated to the declaration and notification of a site area emergency. The inspectors verified that the event classification and notifications were done in accordance with

EP -

AA -1007, "Exelon Nuclear Radiological Emergency Plan Annex for

PBA [[]]

PS." The inspectors verified that the drill evaluators correctly counted the drill's contribution in the

calculation of the

DEP [[]]

PI. The inspectors also verified that operations personnel in the simulator control room identified weaknesses or deficiencies during the critique of the drill. The following simulated events were classified during this training exercise: *

FS 1 - Site Area Emergency, Fission Product Barrier Degradation; and *

HA5 - Alert, Natural and Destructive Phenomena. b. Findings

No findings of significance were identified.

4.

OTHER [[]]

ACTIVITIES 4OA1 Performance Indicator Verification (71151 - 10 Samples)

13 Cornerstone: Initiating Events and Barrier Integrity .1 Initiating Events

PI s (71151 - 6 Samples) a. Inspection Scope The inspectors sampled

PBAPS 's submittals for the

PI s listed below for Units 2 and 3 for the period from January 2008 through March 2009.

PI definitions and guidance

contained in Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 5, were used to verify the accuracy of the

PI data. The inspectors reviewed selected portions of the operating logs and raw

PI data, and selected applicable licensee event reports and

CAP documents from the period for each

PI specified below. The inspectors compared graphical representations from the most recent

PI report to the raw data and used the performance indicator definition in the

NEI guideline to verify that the data were correctly reflected in the report. Documents

reviewed during this inspection are listed in the Attachment. The following six

PI samples were reviewed: Units 2 and 3 * Unplanned Scrams; * Unplanned Scrams with Complications; and * Unplanned Power Changes. b. Findings No findings of significance were identified. .2 Barrier Integrity

PI s (71151 - 4 Samples) a. Inspection Scope The inspectors reviewed a sample of

PBAPS 's submittals for the four Barrier Integrity

PI s listed below to verify the accuracy of the data reported. The

PI definitions and the guidance contained in

NEI 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 5, and Exelon procedure

LS -

AA -2001, "Collecting and Reporting of

NRC Performance Indicator Data," were used to verify that the reporting requirements were met. The inspectors reviewed raw

PI data collected since January 2008 to April 2009 and compared graphical representations from the most recent

PI report to the raw data to verify the data was included in the report. Documents reviewed during this inspection are listed in the Attachment. The following four

PI samples were reviewed: Units 2 and 3 * Reactor Coolant System (RCS) Specific Activity; and *

RCS Leakage. 4

OA2 Identification and Resolution of Problems (PI&R) (71152 - 2 Samples) 1. Annual Sample: MOV Hardened Grease Challenges (1 In-depth Review Sample)

14 a. Inspection Scope This inspection focused on Exelon's identification, evaluation, and resolution of

challenges associated with hardened grease on safety-related

MOV. Specifically, two

HPCI valves failed to stroke to the full open position during surveillance testing on March 12 and March 21, 2009.

MOV disassembly and inspection identified hardened grease on the stem and inside the stem nut of both valves. Initial extent-of-condition evaluations revealed that two

RHR valves developed less-than-required closing thrust for successful diagnostic test acceptance. Hardened grease was also identified on the stem and inside the stem nut of both

RHR valves. The final extent-of-condition scoping determined that 45 safety-related

MOVs required additional evaluation appropriate to the circumstances, such as visual inspection, grease evaluation, diagnostic testing, and/or corrective maintenance. The inspectors reviewed Exelon's associated root cause evaluation, operability

evaluations, corrective action reports, and a sample of diagnostic and stroke time test data, and interviewed plant personnel to evaluate the adequacy of Exelon's performance in the areas of problem identification, evaluation, extent-of-condition scoping, and corrective actions. Additionally, the inspectors observed the integrity of damaged, worn, and newly machined stem nuts to evaluate the effect of plant conditions on stem nut

integrity. Finally, the inspectors reviewed

MOV program procedures to evaluate the quality and effectiveness of the Exelon

MOV program, as implemented at

PBAPS. Documents reviewed are listed in the Attachment. b. Findings and Observations Introduction: A Green, self-revealing

NCV of

10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," was identified. Specifically, Exelon's

MOV Program procedures lacked specific instructions to prescribe an acceptable frequency for performing valve stem lubrication, which resulted in test failures of safety-related

MOV s and affected the reliability of the

MOV s' safety functions. Description: During quarterly surveillance testing performed by Exelon on March 12, 2009, the Unit

2 HPCI torus inboard suction

MOV (MO-2-23-058) failed to stroke full open during its quarterly surveillance test and was subsequently declared inoperable. Investigation by Exelon identified dried and hardened grease on the valve stem and stem nut, and a root cause investigation was assigned to Exelon engineering staff.

Extent-of-condition inspections were performed by Exelon on select

HPCI [[]]

MOV s over the next several days. Degraded grease was identified on the outboard torus suction

MOV for Unit 3 (

MO -3-23-057), but the condition was determined not to impact valve operability. Exelon rescheduled the periodic stem lubrication interval on the Unit

3 HPCI [[]]

MOV from ten years to six years, and assigned this PM to the next Unit 3 refueling

outage (fall of 2009). Subsequently, on March 21, 2009, the Unit

3 HPCI torus outboard suction

MOV failed to stroke full open during quarterly surveillance testing and was declared inoperable. Investigation by Exelon identified hardened grease on the stem and inside the stem nut, as well as stem nut wear. As a result of the failure, Exelon expanded the extent-of-condition scope to include diagnostic testing of MOVs on both

units within the affected

HPCI valve group (total of 6

MOVs), as well as eleven other safety-related MOVs based on diagnostic test data margins, as well as similar stem characteristics.

15 During the diagnostic testing of the Unit

3 RHR loop 'D' torus suction

MOV (MO-3-10-13D) on March 26, 2009, Exelon identified less-than-required thrust at the torque switch trip, and the valve was subsequently declared inoperable. Investigation

by Exelon revealed that the stem grease was degraded and several stem nut threads were damaged. As a result of this test failure, the extent-of-condition scope was again expanded. Exelon concluded that 45 safety-related

MOV s required additional evaluation, such as visual inspection, grease evaluation, diagnostic testing, and/or corrective maintenance. This review identified one additional

MOV under-thrust

condition on the Unit

2 RHR loop 'B' outboard discharge

MOV (MO 2-10-154B) during diagnostic testing on April 2, 2009. Exelon investigation into this

MOV test failure identified a degraded grease condition, and the

MOV was declared inoperable. The

NRC inspectors reviewed the final extent-of-condition scoping, and found that it was appropriate to the circumstances. Exelon performed immediate corrective actions after each of the

MOV failures, which

included cleaning and removing the old grease from the stem and stem nut area, applying new grease, and performing diagnostic testing to ensure successful valve performance. Exelon performed operability evaluations for each of the four

MOV failures, and concluded three of the four

MOVs would have been capable of performing their intended safety function for all design basis events. The operability evaluation for

the Unit

3 RHR loop 'D' torus suction

MOV concluded that the valve would not have been able to perform its safety function of containment isolation for all design basis events. Operability evaluations for the other three MOVs determined that the valves would have

been capable of performing their safety functions for all design basis events. The Unit

2 RHR loop 'B' discharge

MOV is normally open in a standby mode for low pressure coolant injection, and was evaluated for its design function to close during suppression pool cooling and containment spray modes of the RHR system. Exelon concluded that the valve motor torque capability would have provided enough inertia to hard seat the

valve from the as-found torque switch trip condition in the extent-of-condition diagnostic test. The operability evaluations for the Unit 2 and Unit

3 HPCI torus suction

MOVs stated that the torque switch trip protection, which stopped the valve from completely opening through the degraded grease conditions during the surveillance tests, is bypassed during safety actuation signals to open. Exelon determined that the valve motor torque capability, absent torque switch trip protection, was sufficient to open the valve during all design basis events despite the degraded grease conditions. The

inspectors reviewed the operability evaluations and agreed that Exelon's conclusions regarding past operability were reasonable. However, the capability of the MOVs to perform their mitigating safety functions was challenged, thereby impacting their reliability.

A root cause evaluation was performed by Exelon in response to the four

MOV failures. The root cause evaluation determined that Peach Bottom

MOV [[]]

PM frequencies and actions had not appropriately included stem lubricant performance feedback. The

NRC inspectors reviewed the root cause evaluation and agreed that an adequate

MOV program would schedule and adjust

PM activities as necessary to assure that safety-

MOV [[]]

PM lubrication intervals in the entire nuclear fleet (up to 10 years). Previous industry guidance and vendor information had described Exxon Nebula Extreme Pressure (

EP ) - 1, the

MOV lubricant used at

PBAPS, as being

16 susceptible to degradation and hardening phenomena. The Exelon root cause identified that Exxon cancelled production of Nebula

EP -1 in 2001, stating a one-year limited shelf life. Additionally, the

EOC inspections performed by Exelon identified mixtures of

Nebula

EP -1, along with some remains of the former

PBAPS [[]]

MOV lubricant, N5000 NeverSeez, on several valve stems and stem nuts. Industry guidance has noted that NeverSeez is incompatible with Nebula

EP -1 due to an accelerated hardening and degradation effect. Finally, since using

EP -1 grease, Peach Bottom had many opportunities to re-evaluate their

MOV PM lubrication frequencies and actions, including:

October 2006:

MO -3-10-026B failed to successfully stroke. Internal inspection identified severely degraded grease, and the stem nut was replaced. * October 2007:

NRC [[]]

PI&R inspection of the October 2006

MO -3-10-026B failure to stroke noted that although Exelon identified a hardened grease condition, this was not determined to be the most probable cause of the failure, and no

EOC evaluation was performed. Subsequent walkdowns by the inspector identified degraded lubricating grease on

MO -3-10-031A. Exelon staff noted that the grease appeared to be a mixture of

EP -1 and NeverSeez. (

IR 689020). This was documented in

NRC Inspection Report 05000277&278/2007005. * October 2008:

MO -2-23-057 (Unit

2 HPCI outboard torus suction

MOV ) stroked slowly and failed to close. Degraded lubricating grease and stem nut wear were identified, and the stem nut was replaced. * January 2009:

MO -3-01A-077 failed to go full open. The valve stem was cleaned and re-lubricated and the stroke time decreased. Analysis: The inspectors determined that Exelon's failure to properly implement

MOV preventive maintenance activities, specifically with respect to stem lubrication necessary to assure that MOVs will function when required, constituted a performance deficiency. Specifically, degraded stem lubrication was identified as a common factor in four safety-

MOV test failures between March 12, 2009 and April 2, 2009. Unit 2: The finding for Unit 2 was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems (

MS) Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of

systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the

HPCI torus inboard suction

MOV and the

RHR loop 'B' outboard discharge

MOV experienced test failures, were declared inoperable, and required detailed operability evaluations as described above, thereby challenging their reliability and capability to perform their safety function. Using the Phase 1 worksheet in

of Manual Chapter 0609, "Significance Determination Process," the finding affected the

MS [[Cornerstone and was of very low safety significance (Green) because it was not a design or qualification deficiency, did not represent a loss of system safety function, and was not associated with any external events. Unit 3: The finding for Unit 3 was more than minor because it was associated with the configuration control attribute of the Barrier Integrity (]]

BI ) Cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers (e.g., containment) protect the public from radionuclide releases caused by accidents or events. Specifically,

RHR loop 'D' torus suction

MOV was determined by Exelon to not be capable of isolating for all design basis events. Using the Phase 1 worksheet in Attachment 4 of Manual Chapter 0609, "Significance Determination Process," the finding

affected the BI cornerstone and was of very low safety significance (Green) because it

17 did not represent an actual open pathway in the physical integrity of reactor containment. Although the Unit

3 HPCI torus outboard suction

MOV condition affected the mitigating system cornerstone, the Unit 3 finding analysis was assigned to the BI cornerstone

because it best reflected the dominant risk of the finding. This finding has a cross-cutting aspect in the area of

PI&R , Corrective Action Program, because

PBAPS did not thoroughly evaluate problems such that the resolutions addressed the causes and extent of condition P.1(c). Specifically,

PBA [[]]

PS failed to

thoroughly evaluate previous conditions of degraded and hardened grease on safety-related valves, such that the extent of the condition was considered and the cause was resolved. This cross-cutting aspect is applied to both Units 2 and 3. Enforcement: 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires, in part, that "Activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the

circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings." Contrary to the above, the Exelon

MOV program procedures (

ER -AA-300 Series and

MA -

AA-723-300 Series) were not appropriate to the circumstances, in that, they lacked specific instructions to prescribe an acceptable frequency for performing valve stem lubrication, given the limited shelf life of the

MOV lubrication grease used by the station as described in the above section. As a consequence of this, four safety-related

MOV s experienced test failures between March 12, 2009 and April 2, 2009, attributed to degraded and hardened lubricating grease. Because this finding is of very low safety significance and has been entered into Exelon's

CAP (IR 892191), this violation is being treated as a Green

NCV consistent with section

VI.A. 1 of the

NRC Enforcement Policy:

NCV 05000277/2009003-01, and

NCV 05000278/2009003-01,

MOV Program Procedures were Inadequate with Regard to Periodicity of Preventive Maintenance Activities for Stem Lubrication. .2 Semi-Annual Review to Identify Trends (1 Trend Review Sample) a. Inspection Scope The inspectors reviewed lists of

CAP items to identify trends (either

NRC or licensee identified) that might indicate the existence of a safety issue. First, the inspectors reviewed a list of approximately 7,250

IR s that

PBAPS initiated and entered into the CAP action tracking system from December 1, 2008 through June 1, 2009. The

inspectors also reviewed the approximately

3450 IR s that remained open with outstanding actions. The list was reviewed and screened to complete the required semi-annual

PI&R trend review. Based on the review, a sample of 58 IRs (listed in the Attachment) were selected for a more detailed review to determine whether the issues were adequately identified and evaluated, and that corrective actions were planned. The

inspectors evaluated the

IR s against the requirements of Exelon procedure,

LS -AA-125, and

10 CFR 50, Appendix B, Criterion

XVI, "Corrective Action." b. Findings and Observations Based on the review, the inspectors observed that there was an adverse trend of human performance related events during the period. Specific examples included: * the inadequate configuration control of an inoperable control rod (IR 880318);

18 * inadequate risk assessment and maintenance practices for work on the control circuitry for containment isolation valves (IR 887441); * inadequate procedure adherence that resulted in the trip of a

RRP (

IR 923239); * an inadequate understanding of the maintenance and operation of a

WRNM channel (

IR [[871864); and, * removal, for inspection, of an incorrect pin from a spent fuel bundle (IR 853625). The inspectors also noted an adverse trend in equipment reliability issues that challenged plant operations. Specifically: * the build-up of combustible gases in the 3 'A' main power transformer that resulted in an unplanned power reduction (IR 868369); * the failure of]]

EHC cards that led to an unplanned power reduction in response to turbine bypass valve cycling (

IR 891763); * indications of friction between selected Unit 3 control rods and fuel channels (IR 874398); and, * inoperable motor operated valves that resulted from inadequate preventive maintenance and hardened grease (IRs 892191 and 913965).

However, the inspectors noted that

PBAPS self-identified an adverse trend in station performance and proactively performed a common cause analysis (

IR 896381) to understand the causes for the adverse trend and to identify corrective actions and improvement plans.

.3 Review of Items Entered into the

CAP As required by

IP 71152, "Identification and Resolution of Problems," and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed screening of all items entered into the licensee'

CAP. This was accomplished by reviewing the description of each new action request/issue report and attending daily management review committee meetings. 4

OA3 Follow-up of Events and Notices of Enforcement Discretion (71153 - 4 Samples) .1 Personnel Performance - 3 'A' RRP Trip

a. Inspection Scope The inspectors reviewed corrective action documents listed in the Attachment to this report and discussed the events surrounding the trip of the 3 'A'

RRP with the personnel involved. The inspectors reviewed Revision 4 of

IC-11-02011, "Recirc MG Set Voltage

Regulator Tuning," and Revision 3 of

HU -

AA -104-101, "Procedure Use and Adherence." b. Findings Introduction: A Green, self-revealing finding occurred when

PBAPS personnel incorrectly performed a maintenance procedure for tuning the 3 'A'

RRP [[]]

MG set voltage regulator. Specifically, maintenance personnel adjusted a potentiometer in the wrong direction which resulted in a trip of the

RRP and an unplanned Unit 3 plant transient.

19 Description: On May 23, 2009, at approximately 9:30 a.m., the

PBAPS Unit 3 'A'

RRP tripped. The trip occurred while instrument and controls (I&C) maintenance technicians were performing procedure

IC -11-02011, "Recirc

MG Set Voltage Regulator Tuning,"

step 5.1.6.8. Step 5.1.6.8 states, "Verify step test box potentiometer is at

MAXIMU M resistance (fully counter-clockwise) and

CLOSE the switch of the step test circuit." Contrary to the procedure instructions, the potentiometer, on the step test box, that is used to vary the test current applied to the

RRP [[]]

MG set voltage regulator field, was incorrectly positioned to the minimum resistance (fully clockwise) position. When the

test box switch was closed, the incorrect positioning of the potentiometer resulted in an excessive

MG set field current that tripped the

MG set field breaker. The trip of the

MG set field breaker resulted in the loss of the 3 'A'

RRP. The loss of core flow caused reactor power to decrease from approximately 75 percent to 33 percent. In response to the loss of the 3 'A'

RRP , operators entered operational transient procedure,

OT-112, "Unexpected/Unexplained Change in Core Flow" and

executed actions to stabilize the plant in single loop operations.

I&C personnel aborted the performance of

IC -11-02011 and removed all test equipment. The 3 'A'

RRP was subsequently restored per system operating procedure,

SO 2A.1.B-3, "Starting the Second Recirculation Pump" at 4:32 p.m. the same day.

PBAPS [['s investigation indicated that there was a mindset among the technicians performing the work that the potentiometer had to be set to the maximum position and that this position was fully clockwise. Interviews with several I&C technicians indicated that the word "]]

MAXIMUM" as it relates to the operation of variable inputs almost always refers to the fully clockwise position. During the pre-job brief there was no mention of

rotating the potentiometer either clockwise or counter-clockwise, only of taking it to maximum. When the technicians reached the job site, the first technician verified the test box was in the maximum position by attempting to rotate the potentiometer in the clockwise

position. The technician then announced what his actions were and handed the procedure to a second technician who read the step and took the same action to verify the potentiometer position. This peer check was flawed because the first technician inappropriately took the action without a peer check and then asked for a peer check after the action was taken. The job supervisor was present during the entire evolution providing management oversight, and failed to notice the incorrect position of the potentiometer. Following the incorrect setting of the potentiometer, the technicians moved the test box switch from the

OPEN to the

CLOSE position which inserted the test signal and tripped the 3 'A'

MG set and

RRP. Immediately after the event, the technicians and their supervisor checked the connections and potentiometer position and all agreed the setup

was correct. When the team reached the main control room, the procedure was re-read and the technicians realized the error in the positioning of the test box potentiometer. The inspectors reviewed the root cause report to assess its details, accuracy, and planned corrective actions. The inspectors concluded that the root cause report was

thorough, detailed, and comprehensive. The planned and completed corrective actions were appropriate and comprehensive. The licensee identified two root causes and two contributing causes for this event. The root causes included failure to adhere to a Level 1 (step-by-step performance) procedure due to performing work in a

20 knowledge-based versus rule-based manner and the failure to perform an adequate peer check to verify the potentiometer position that resulted in a lost opportunity to identify the error prior to the plant transient.

PBA [[]]

PS's investigation determined that the

technician performing the work was operating in the knowledge-based thinking mode because he knew that the potentiometer needed to be in the maximum position. If the technician had operated in the rule-based thinking mode, he would have been complying with the procedure instructions verbatim. The peer check was flawed in that the first technician took the action without a peer check and inappropriately asked the second

technician for a peer check after the action was taken. Analysis: The inspectors determined that the

I&C technician's failure to follow the procedure for tuning the 3 'A'

RRP [[]]

MG set voltage regulator that resulted in a trip of the

RRP MG set and an unplanned plant transient was a performance deficiency. This finding was more than minor because it was associated with the human performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone

objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions. Specifically, this error resulted in an unplanned plant transient that reduced Unit 3 reactor power from 75 percent to 33 percent. In accordance with IMC 0609, Attachment 4, the inspectors determined this finding to be of very low safety significance (Green) since the finding did not contribute to both the likelihood of a reactor

trip and the likelihood that mitigation equipment or functions would not be available. This finding has a cross-cutting aspect in the area of human performance, Work Practices, because

PBA [[]]

PS did not define and effectively communicate expectations regarding procedural compliance and personnel did not follow procedures H.4(b).

Specifically,

PBAPS personnel did not follow procedure

IC -11-02011 instructions for tuning the 3 'A'

RRP [[]]

MG set voltage regulator Enforcement: The inspectors determined that the finding did not represent a violation of regulatory requirements because it involved a procedure violation of a non-safety related procedure. This finding will be tracked as

FIN 05000278/2009003-02, Inadequate Procedure Adherence Results in Trip of 3 'A' Recirc Pump and Plant Transient. .2 (Closed) Licensee Event Report (

LER ) 05000278/2009-03-00, Inoperable Containment Isolation Valve Results in Condition Prohibited by

TS s On March 26, 2009, it was discovered that the 3D

RHR pump suppression pool suction

isolation valve (MO-3-10-013D) was degraded due to a greasing deficiency identified during performance of

EOC testing associated with grease deficiencies previously discovered on motor-operated valves (

MOV s). It was determined that this condition was prohibited by TSs since this valve is a primary containment isolation valve and was inoperable for containment isolation purposes for a time period longer than allowed by

TS. The cause of the greasing deficiency was grease hardening primarily due to inadequate preventive maintenance. The valve was repaired and returned to service on March 27, 2009. A finding related to this event was documented in report section 4

OA2.1. This LER is closed.

.3 (Closed)

LER 05000277/2009-01-00, Clearance Performance Error Results in Condition Prohibited by

TSs

21 On February 13, 2009,

PBAPS personnel discovered that an operation prohibited by

TS existed when a TS required action for an inoperable Unit 2 control rod (Control Rod 10-51) was found not met. Specifically, at 9:33 a.m. on February 13, during a plant

walkdown being conducted in preparation to vent selected control rod drive (CRD) hydraulic control units (HCUs), the

CRD [[]]

HCU directional control valves (DCVs) for Control Rod 10-51 were discovered to be energized (armed). To comply with

TS 3.1.3, Condition C, these

DCV s should have been de-energized (disarmed) since the 10-51

CRD [[]]

HCU had been rendered inoperable for the conduct of maintenance on

February 11. This condition was due to an operator error that re-armed the

DCV during the modification of a safety tagging clearance that occurred at approximately 5:30 a.m. on February 12, 2009. On February 13, after the

TS non-compliance was identified at 9:33 a.m., prompt action was taken to disarm the

CRD and restore

TS compliance by 9:42 a.m. Since Control Rod 10-51 remained fully inserted during this event,

PBAPS concluded that there was no actual safety consequences associated with this event. There were no previous similar

LERs identified. A licensee-identified NCV for this issue

is documented in Section

4OA 7; therefore, this

LER is closed. .4 (Closed) LER 05000278/2009-01-00, Control Rods Inoperable During Mode 2 Operations As a Result of Interferences

As a result of control rod interference monitoring testing performed by Operations personnel on January 28, 2009, it was determined that three control rods were inoperable during the Unit 3 shutdown that was performed on January 21. This testing determined that Control Rods 14-55, 18-55, and 42-55 could be inoperable for operational conditions involving time periods when reactor pressure is below 850 psig

(Mode 2 operations). This occurrence was considered reportable as a common cause that resulted in the inoperability of three control rods for approximately 4.75 hours8.680556e-4 days 0.0208 hours 1.240079e-4 weeks 2.85375e-5 months on January 21, during Mode 2 operations. The common cause is related to control rod blade interferences with the fuel bundle channel.

PBA [[]]

PS concluded that there were no actual safety consequences associated with this event and that appropriate shutdown

margin was maintained during this event. Subsequently, a control rod interference monitoring and testing program was established.

EOC testing was performed on Units 2 and 3. There were no previous similar

LERS identified. The inspectors reviewed the event and concluded that the condition was appropriately reported as a common-cause inoperability. However, no violation or condition prohibited by

TS existed because, in accordance with

TS 3.1.3, Condition E, Unit 3 was taken to

Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of reactor pressure being reduced below 850 psig; therefore, this

LER is closed. 4

OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities a. Inspection Scope During the inspection period the inspectors conducted observations of security force

personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security. These observations took place during both normal and off-normal plant working hours.

2 These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status reviews and inspection activities. b. Findings No findings of significance were identified.

4OA 6 Meetings, Including Exit Exit Meeting Summary On July 17, 2009, the resident inspectors presented the inspection results to Mr. W. Maguire and other

PBAPS staff, who acknowledged the findings. The inspectors asked the licensee whether any of the material examined during the inspection should

be considered proprietary. No proprietary information was identified. 4OA7 Licensee-Identified Violations The following violation of very low significance (Green) was identified by the licensee

and is a violation of

NRC requirements which meets the criteria of Section

VI of the

NRC Enforcement Policy for being dispositioned as a

NCV. *

TS 3.1.3, Condition C, requires that control rods that are inoperable for reasons other than being stuck shall be fully inserted and disarmed.

TS 3.1.3, Condition E, requires the unit to be in Mode 3 within 12 hours if Condition C cannot be met. On February 11, the 10-51

CRD [[]]

HCU was declared inoperable for the conduct of

maintenance and the

TS required actions to fully insert and disarm the

CRD were met. Following the completion of maintenance on the

HCU , an operator erroneously re-armed the

CRD [[]]

HCU [[]]

DCVs during the modification of a safety tagging clearance that occurred at approximately 5:30 a.m. on February 12. Over 28 hours3.240741e-4 days 0.00778 hours 4.62963e-5 weeks 1.0654e-5 months later and in excess of the 12-hour completion time allowed by

TS 3.1.3,

PBAPS personnel discovered the error and disarmed the

CRD for Control Rod 10-51.

PBAPS documented this issue in the

CAP as

IR 880318. Since Control Rod 10-51 remained fully inserted and there was no loss of safety function during the period of non-compliance, this issue is of very low (Green) safety significance. The

LER associated with the event was documented in

Section

4OA 3.3.

ATTACH MENT:

SUPPLE [[]]

MENTAL [[]]

INFORM [[]]

ATION A-1

SUPPLE [[]]

MENTAL [[]]

INFORM [[]]

ATION [[]]

KEY [[]]

POINTS [[]]

OF [[]]

CONTACT Exelon Generation Company Personnel W. Maguire, Site Vice President G. Stathes, Plant Manager J. Armstrong, Regulatory Assurance Manager

E. Flick, Engineering Director P. Navin, Work Management Director L. Lucas, Chemistry Manager R. Franssen, Operations Director R. Holmes, Radiation Protection Manager D. DeBoer, Security Manager T. Wasong, Training Director

NRC Personnel F. Bower, Senior Resident Inspector M. Brown, Resident Inspector

E. Torres, Project Engineer A. Ziedonis, Reactor Inspector

LIST [[]]

OF [[]]

ITEMS [[]]

OPENED ,

CLOSED ,

AND [[]]

DISCUSSED

Opened None

Opened/Closed 05000277/2009003-01

NCV [[]]