IR 05000440/2007003

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July 26, 2007

EA-03-197EA-04-020 CAL 3-05-001Mr. Barry S. AllenSite Vice President FirstEnergy Nuclear Operating Company Perry Nuclear Power Plant P. O. Box 97, 10 Center Road, A-PY-290 Perry, OH 44081-0097

SUBJECT: PERRY NUCLEAR POWER PLANT NRC INTEGRATED INSPECTIONREPORT 05000440/2007003

Dear Mr. Allen:

On June 30, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection atyour Perry Nuclear Power Plant. The enclosed report documents the inspection findings which were discussed on July 2, 2007, with you and other members of your staff.The inspection examined activities conducted under your license as they relate to safetyand 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. In addition, because it has been determined that Perry is in the Regulatory Response column of the Action Matrix (as outlined in our letter to you of May 8, 2007), Perry performance will be further evaluated in a supplemental inspection conducted in accordance with Inspection Procedure 95001 "Supplemental Inspection for One or Two White Inputs in a Strategic Performance Area" for crossing the threshold from Green to White for the Emergency AC Power Systems mitigating systems performance index.

On May 1, 2007, the NRC reviewed Perry operational performance, inspection findings, and performance indicators for the first quarter of 2007. Based on this review, we concluded that Perry was operating safely. We determined that no additional regulatory actions, beyond the already increased inspection activities and management oversight, are currently warranted.Based on the results of this inspection, four findings of very low safety significance, twoof which involved violations of NRC requirements, were identified. Additionally, a licensee-

identified violation was determined to be of very low safety significance and is listed in this report. However, because of the very low safety significance of the violations and because they have been entered into your corrective action program, the NRC is treating these violations as non-cited violations (NCVs) in accordance with Section VI.A.1 of the NRC's Enforcement Policy.

B. Allen-2-If you contest the subject or severity of these non-cited violations, you should provide aresponse within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director,Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Perry Nuclear Power Plant.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of thisletter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS)

component of NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/Bruce L. Burgess, ChiefBranch 6 Division of Reactor ProjectsDocket No. 50-440License No. NPF-58

Enclosure:

Inspection Report 05000440/2007003

w/Attachment:

Supplemental Informationcc w/encl:J. Hagan, President and Chief Nuclear Officer - FENOCJ. Lash, Senior Vice President of Operations and Chief Operating Officer - FENOC D. Pace, Senior Vice President, Fleet Engineering - FENOC J. Rinckel, Vice President, Fleet Oversight - FENOC R. Anderson, Vice President, Nuclear Support - FENOC Director, Fleet Regulatory Affairs - FENOC Manager, Fleet Licensing - FENOC Manager, Site Regulatory Compliance - FENOC D. Jenkins, Attorney, FirstEnergy Corp.

Public Utilities Commission of Ohio Ohio State Liaison Officer R. Owen, Ohio Department of Health

SUMMARY OF FINDINGS

IR 05000440/2007003; 04/01/2007 - 06/30/2007; Perry Nuclear Power Plant; Fire Protection;Other ActivitiesThis report covers a three-month period of baseline resident inspection and announcedbaseline inspection of radiation protection and inservice inspection activities. The inspections were conducted by Region III inspectors and the resident inspectors. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (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. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.A.NRC-Identified and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

The inspectors identified a finding of very low significance and an associated non-cited violation of the operating license section C(6) for the storage of transient combustible material in the Turbine Building 620' elevation. Specifically, on May 7 and May 16, 2007, the inspectors identified several acetylene and oxygen cylinders as well as other combustible material in the area that exceeded the fire hazards analysis for the fire zone. The primary cause of this finding was related to the cross-cutting area of Human Performance per Inspection Manual Chapter 0305 H.4(b) because the licensee failed to properly communicate expectations regarding procedural compliance that specified combustible loading of the fire zone. As part of their immediate corrective actions, licensee personnel removed the excess combustible material from the area and entered the issue into their corrective action program.This finding was more than minor because it was associated with the protection againstexternal factors attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability.

Specifically, the combustible storage amount exceeded the licensee's fire hazard analysis limits. The finding was determined to be of very low safety significance because the inspectors determined that the combustible materials of significance, that exceeded the fire hazards analysis limits, were in approved containers. (Section 1R05)

Green.

A finding of very low safety significance and a non-cited violation of TechnicalSpecification 5.4, "Procedures," was self-revealed when reactor water level indication was lost while the reactor was shut down on May 5, 2007. Specifically, licensee personnel failed to implement appropriate procedures in the re-assembly of reactor core isolation cooling head spray piping during a 1993 refueling outage. This resulted in leakage from a flange connection that affected the reference leg of the reactor shutdown and upset range level indication system, which caused a loss of reactor level indication. As part of their immediate corrective actions, licensee personnel repaired the Enclosure3flange, restored reactor water level indication, and entered the issue into the correctiveaction program.The finding was more than minor because it was associated with the equipmentperformance attribute of the reactor safety Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the finding resulted in a loss of reactor water level indication.

The finding was determined to be of very low safety significance because the inspectors determined that it did not result in a loss of control of reactor water level and it did not affect decay heat removal systems. (Section 40A3.2)Green. A finding of very low safety significance was self-revealed when, during reactorpower ascension after a refueling outage, the main turbine generator tripped on reverse power on May 13, 2007. The primary cause of this event was licensee personnel's failure to appropriately install an electro-hydraulic control (EHC) circuit card following maintenance. The primary cause of this finding was related to the cross-cutting area of Human Performance per Inspection Manual Chapter 0305 H.4(a) because the organization failed to properly communicate human error prevention techniques for proper insertion of the control cards. As part of their immediate corrective actions, licensee personnel repaired the installation of the affected card and also repaired the installation of several other EHC system cards that were subsequently identified by the licensee as incorrectly installed. The licensee entered the issue into their corrective action program.This finding was considered more than minor because it was associated with theavailability and reliability of equipment attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability. Specifically, the finding resulted in a turbine trip. The finding was determined to be of very low safety significance because it did not affect the likelihood that mitigation equipment or functions would be available. No violation of NRC requirements occurred. (Section 4OA3.3)Green. A finding of very low safety significance was self-revealed when, during post-modification testing of the feedwater system after a refueling outage, the reactor scrammed on low reactor water level on May 15, 2007. The primary cause of this event was the licensee's failure to appropriately control the implementation of a digital feedwater control system design modification. Specifically, the licensee installed the modification with a control system software logic that was contrary to plant design and this resulted in a loss of feedwater flow to the reactor. The primary cause of this finding was related to the cross-cutting area of Human Performance per Inspection Manual Chapter 0305 H.3(a) because the organization failed to properly plan work activities that incorporated insights to risk. As part of their immediate corrective action, the licensee revised the digital feedwater control system software and entered the issue into their corrective action program.This finding was considered more than minor because it was associated with theavailability and reliability of equipment attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events Enclosure4that upset plant stability. Specifically, the finding resulted in a reactor scram. Thefinding was determined to be of very low safety significance because it did not affect the likelihood that mitigation equipment or functions would be available. No violation of NRC requirements occurred. (Section 4OA3.4)

B.Licensee-Identified Violations

One violation of very low safety significance that was identified by the licensee hasbeen reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. This violation and the licensee's corrective action tracking number is listed in Section 4OA7.

Enclosure5

REPORT DETAILS

Summary of Plant StatusOn April 1, 2007, the plant began the inspection period in Mode 1 at 94 percent power. At11:00 a.m. on the same day, operators began to reduce reactor power in preparation for a scheduled refueling outage (RFO). Shortly after midnight on April 2 the main generator output breaker was opened commencing Perry's 11th Refueling Outage (RFO11). A manual reactor scram was inserted on April 2 at 1:03 a.m. The plant reached Mode 4 later that same day. The plant entered Mode 5 on April 4 at 12:30 p.m. when the first reactor pressure vessel stud was detensioned. On May 2, at 2:31 p.m., following refueling activities, operators placed the plant in Mode 4. On May 11 at 1:18 a.m., operators commenced startup of the reactor. The plant entered Mode 1 on May 12 at 1:57 a.m. and operators synchronized the generator to the grid on May 13 at 4:31 a.m. On the same day a turbine trip occurred at 8:28 a.m. while the reactor was at 26 percent power. On May 14 at 4:11 p.m., following corrective actions associated with the turbine trip, operatorssynchronized the generator to the grid. On May 15 at 12:58 a.m. the reactor scrammed from 31 percent power on a Level 3 low reactor vessel level signal. Operators placed the plant in Mode 4 later that same day.On May 17 at 1:59 a.m., following corrective actions associated with the reactor scram,operators commenced a reactor startup. The plant entered Mode 1, and the generator was synchronized to the grid at 8:55 p.m. on the same day. When the reactor reached 31 percent power, licensee personnel discovered a hydraulic fluid leak from the main turbine generator mechanical trip assembly. Operators reduced reactor power to 20 percent and removed the generator from the grid on May 18 at 8:02 p.m. On May 19 at 12:21 a.m., following corrective actions associated with the turbine mechanicaltrip assembly fluid leak, operators synchronized the generator to the grid. On May 24, while the reactor was at 92 percent power, a safety glass cover associated with the isophase bus duct fell off. This disrupted cooling air to the generator and operators reduced reactor power to 52 percent to perform corrective actions. On May 26 at 1:47 a.m., following corrective actions associated with the isophase bus duct,operators recommenced power ascension until 99 percent indicated power was reached later that same day. Operators determined that generator output was higher than expected and questioned the reactor heat balance calculation accuracy. Operators then reduced power to 97 percent pending resolution of questions associated with the heat balance.On June 5 operators observed oscillations of the reactor recirculation 'A' flow control valveand took manual control of the valve. On June 21 at 8:30pm, operators commenced power reduction in preparation for a reactor shutdown in order to repair the reactor recirculation

'A' flow control valve. During the power reduction, while operators were attempting to shift reactor recirculation pumps to slow speed, the 'B' reactor recirculation pump tripped 6unexpectedly and then automatically attempted to start in fast speed several times. Operators prevented the 'B' recirculation pump from starting and removed the control power fuses for the 'B' recirculation pump. Operators completed plant shutdown to Mode 3 on June 22 at 2:30 a.m.On June 24 at 3:51 a.m., following corrective actions associated with the 'A' flow controlvalve and the 'B' recirculation pump, operators commenced reactor startup. On June 25 at 1:50 a.m., operators synchronized the generator to the grid. On June 27, while the reactor was at 87 percent power, the 'A' reactor recirculation pump tripped unexpectedly. Operators reduced power to 56 percent and subsequently placed the plant in single loop operations.

Operators commenced a plant shutdown on June 29 at 2:26 p.m., to perform troubleshooting of the 'A' recirculation pump. The plant entered Mode 4 on June 30 at 4:07 p.m. and remained in Mode 4 through the end of the inspection period.1.REACTOR SAFETYCornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity1R01Adverse Weather Protection (71111.01).1Tornado Warnings and Communications With the Electrical Grid Operator

a. Inspection Scope

During the week of April 23, 2007, tornado and high wind warnings were issued fornortheastern Ohio. The inspectors observed the licensee's preparations and planning for the significant weather potential. The inspectors reviewed licensee procedures and discussed potential compensatory measures with control room personnel. The inspectors walked down selected areas to evaluate plant equipment susceptible to high winds. Finally, the inspectors reviewed the licensee's communications protocols with the electrical grid transmission system operator to determine whether appropriate information was exchanged.This review represented one inspection sample.

b. Findings

No findings of significance were identified.

.2 Summer Warm Weather Preparations

a. Inspection Scope

During June 2007 the inspectors reviewed the facility design for past hot weatherchallenges and limitations and the licensee's procedures to prepare for adverse weather conditions, such as increasing ambient temperatures. The inspectors reviewed the NRC 2006 finding (FIN 05000440/2006003-01) related to summer seasonal readiness to determine if corrective actions were implemented in a timely 7manner. The inspectors walked down selected areas to evaluate plant equipmentsusceptible to high temperatures. Finally, the inspectors reviewed the status of licensee summer preparation work orders (WOs) to determine whether the work was completed in a timely manner. This review represented one inspection sample.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

a. Inspection Scope

The inspectors conducted a partial walkdown of the system trains listed below todetermine whether the systems were correctly aligned to perform their designed safety function. The inspectors used valve lineup instructions (VLIs) and system drawings during the walkdown. The walkdown included selected switch and valve position checks, and verification of electrical power to critical components. Finally, the inspectors evaluated other elements, such as material condition, housekeeping, and component labeling. The documents used for the walkdown are listed in the attached List of Documents Reviewed. The inspectors reviewed the following systems:*high pressure core spray (HPCS) system while designated as the primaryreactor water inventory control system during the week of April 9, 2007;*fuel pool cooling and cleanup system while designated as the primary decayheat removal system during the week of April 23, 2007;*residual heat removal (RHR) 'C' system while designated as the primary reactorwater inventory control system during the week of April 23, 2007; and*Division 2 emergency diesel generator (EDG) while the Division 1 EDG wasinoperable during the week of June 24, 2007.This review represented four quarterly partial system walkdown samples.

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05AQ).1Walkdown of Selected Fire Zones/Areas

a. Inspection Scope

The inspectors walked down the following areas to assess the overall readiness of fireprotection equipment and barriers:

8*Turbine Building; elevation 624' East;*Fire Zone 1RB-1C; Unit 1 Drywell;

• Fire Zone 1RB-1C; Unit 1 Containment to Drywell Space;

• Fire Zones 0CC-2A, 2B, and 2C; Control Complex elevation 599';

• Fire Zone 1DG-1C; Unit 1 - Division 1 Diesel Generator Building;elevation 620' - 6" and 646' - 6"; and*Fire Zones 1CC-5A and 2CC-5A; Unit 1 and Unit 2 Control Rooms.Emphasis was placed on evaluating the licensee's control of transient combustiblesand ignition sources, the material condition of fire protection equipment, and the material condition and operational status of fire barriers used to prevent fire damage or propagation. The inspectors utilized the general guidelines established in Fire Protection Instruction (FPI)-A-A02, "Periodic Fire Inspections," Revision 5; Perry Administrative Procedure (PAP)-1910, "Fire Protection Program," Revision 15; and PAP-0204, "Housekeeping/Cleanliness Control Program," Revisions 17 and 18; as well as basic National Fire Protection Association Codes, to perform the inspection and to determine whether the observed conditions were consistent with procedures and codes.The inspectors observed fire hoses, sprinklers, and portable fire extinguishers todetermine whether they were installed at their designated locations, were in satisfactory physical condition, and were unobstructed. The inspectors also evaluated the physical location and condition of fire detection devices. Additionally, passive features such as fire doors, fire dampers, and mechanical and electrical penetration seals were inspected to determine whether they were in good physical condition. The documents listed in the List of Documents Reviewed at the end of this report were used by the inspectors during the inspection of this area.These reviews represented six quarterly inspection samples.

b. Findings

Introduction:

The inspectors identified a finding of very low safety significance andan associated non-cited violation (NCV) of license condition C(6) for the presence of unauthorized transient combustible materials in the Turbine Building 620' East elevation.Description: During a routine plant walkdown on May 7, 2007, the inspectors identifiedthat there were three acetylene cylinders and one oxygen cylinder in the Turbine Building 620' East room. On May 16, 2007, the inspectors identified that there were two acetylene cylinders, a large amount of cloth rags scattered on the floor, and several empty wooden crates located in the same fire zone. The inspectors noted in each case that this condition was contrary to the fire protection plan, which did not allow transient compressed flammable gas cylinders and did not permit any flammable material in the fire zone that included the Turbine Building 620' East elevation. In each case, the inspectors promptly reported the condition to the licensee. In addition, on May 10, 2007, the licensee identified that the three acetylene cylinders and one oxygen cylinder were located in the Turbine Building 620' East room and in close proximity to several 55-gallon drums of oil.

9The inspectors determined that the licensee's failure to control combustible materialin this fire zone was a repetitive issue. On August 8, 2006, the inspectors noted that five 55-gallon drums of oil were stored in the turbine lube oil room located in Turbine Building 620' East elevation fire zone. The inspectors questioned the licensee whether this was consistent with FPI-TB, "Turbine Building", Revision 2, which allowed storage of minimal oil. The licensee performed an engineering analysis and determined that the maximum acceptable storage of oil in the affected fire zone was eight 55-gallon drums of oil. On November 22, 2006, the licensee issued FPI "Turbine Building",

Revision 3 to reflect the maximum allowed storage of eight 55-gallon oil drums. On March 7, 2007, the licensee identified that 21 55-gallon oil drums were located on Turbine Building 620' East elevation, and that nine drums were within the turbine lube oil room. On April 9, 2007, licensee personnel identified that nine 55-gallon oil drums were located in the turbine lube oil storage area and that this exceeded permitted levels. The inspectors noted that the automatic CO2 suppression system required by the fireprotection plan for the turbine lube oil room, which was part of the Turbine Building 620' East elevation, had been placed in manual operating mode since 2004 due to licensee concerns over system reliability.

Analysis:

The inspectors determined that the licensee's failure to control transientcombustibles in accordance with the fire hazards analysis from May 7 to May 16, 2007, was a performance deficiency warranting a significance evaluation in accordance with Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports,"

Appendix B, "Issue Disposition Screening," issued on November 2, 2006. The inspectors determined that the finding was more than minor because it was associated with the protection against external factors attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability. Specifically, the combustible storage exceeded the licensee's fire hazard analysis limits. The inspectors completed a Significance Determination Process (SDP) review of thisissue using IMC 0609, Appendix F, "Fire Protection Significant Determination Process,"

dated February 28, 2005. The inspectors determined that the finding represented a low degradation rating because the combustible materials of significance were in approved containers. Therefore, the inspectors determined through initial qualitative screening that the finding was of very low safety significance.The primary cause of this finding was related to the cross-cutting area of HumanPerformance per IMC 0305 H.4(b) because the organization failed to properly communicate expectations regarding procedural compliance that specified combustible loading of the fire zone.Enforcement: License condition C(6) required the licensee to implement and maintainin effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report (FSAR). Section 9A.5, Position C.8 of the FSAR stated that measures are established to ensure conditions adverse to fire protection, such as failures, malfunctions, deficiencies, deviations, defective components, uncontrolled combustible materials, and nonconformance are promptly identified, reported, and corrected. Contrary to the above, between May 7 and May 16, 2007, the licensee 10failed to promptly identify and correct the condition of uncontrolled combustible materialsin the Turbine Building East 620' elevation. Because this violation was of very low safety significance and because it was entered into the licensee's corrective action program (CAP) as Condition Report (CR) 07-20349, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 050004402007003-01).As part of their immediate corrective action, licensee personnel removed the excesscombustible material from the affected fire zone and began a program review of the site work control processes to address identified deficiencies in combustible material controls..2Observation of Unannounced Fire Drill

a. Inspection Scope

The inspectors observed an announced drill involving a fire in a safe shutdown area onJune 13, 2007. The drill was observed to evaluate the readiness of licensee personnel to fight fires. The inspectors considered licensee performance in donning protective clothing/turnout gear and self-contained breathing apparatus, deploying firefighting equipment and fire hoses to the scene of the fire, entering the fire area in a deliberate and controlled manner, maintaining clear and concise communications, checking for fire victims, propagation of fire and smoke into other plant areas, and the use of pre-planned fire fighting strategies in evaluating the effectiveness of the fire fighting brigade. In addition, the inspectors reviewed the post-drill critique report to evaluate the licensee's ability to self-critique fire fighting performance. This review constituted one annual sample.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities (71111.08).1Inservice Inspection

a. Inspection Scope

From April 9 through April 13, 2007, the inspectors conducted a review of theimplementation of the licensee's inservice inspection (ISI) program for monitoring degradation of the reactor coolant system boundary, and the risk-significant piping system boundaries, for Unit 1. The inspectors selected the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI required examinations and Code components in order of risk priority as identified in Section 71111.08-03 of the inspection procedure, based upon the ISI activities available for review during the onsite inspection period.

11The inspectors observed the nondestructive examination (NDE) of the following weldsto evaluate compliance with the ASME Code Section XI requirements and to verify that indications and defects (if present) were dispositioned in accordance with the ASME Code Section XI:*Ultrasonic Examination of 1E12-0696, RHR 12" elbow-to-pipe weld; and*Ultrasonic Examination of 1B13 DM, reactor vessel top head meridional weldat 195AZ. The inspectors reviewed the NDE reports for the following welds to evaluate compliancewith the ASME Code Section XI requirements and to verify that indications and defects (if present) were dispositioned in accordance with the ASME Code Section XI:*Magnetic Particle Examination of 1E22-C001-008, HPCS 24" suction flange to24" suction pipe weld;*Magnetic Particle Examination of 1E22-C001-009, HPCS 24" suction pipe tohead shell weld; and*Liquid Penetrant Examination of 1E51-C001-002, reactor core isolation cooling(RCIC) pump casing to suction nozzle weld.The inspectors also reviewed the following examinations with recordable indications thathave been accepted by the licensee for continued service to verify that the licensee's acceptance for continued service was in accordance with the ASME Code: *Liquid Penetrant Examination of 1E51-C001-002, RCIC pump casing tosuction nozzle weld (rounded indication in toe on suction nozzle side of weld at approximately 10 o'clock); and*Automated Ultrasonic Examination of 1B13-BF, reactor vessel No. 2 shellring long seam @ 280 AZ weld (indication acceptable per requirement of ASME IWB-3000).The inspectors reviewed licensee records related to pressure boundary weldingperformed on the following ASME Code Class 2 components:*RCIC system pipe replacement, WO No. 200143531, welds FW-1, 2, 3 and 4.

The reviews as discussed above counted as one inspection sample.

b. Findings

No findings of significance were identified..2Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed a sample of ISI related problems documented in thelicensee's CAP to assess conformance with 10 CFR Part 50, Appendix B, Criterion XVI,

"Corrective Action," requirements. The corrective action documents reviewed by the 12inspectors are listed in the attachment to this report. In addition, the inspectorsverified that the licensee correctly assessed operating experience for applicability to the ISI group.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification (71111.11)

a. Inspection Scope

On April 24, 2007, the resident inspectors observed licensed operator performance inthe plant simulator. The inspectors evaluated crew performance in the areas of:*clarity and formality of communication;*ability to take timely action in the safe direction;

• prioritizing, interpreting, and verifying alarms;

• correct use and implementation of procedures, including alarm responseprocedures;*timely control board operation and manipulation, including high-risk operatoractions; and*group dynamics.The inspectors also observed the licensee's evaluation of crew performance todetermine whether the training staff had identified performance deficiencies and specified appropriate remedial actions. This review represented one inspection sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the licensee's implementation of the maintenance rulerequirements to determine whether component and equipment failures were identified and scoped within the maintenance rule and that select structures, systems, and components were properly categorized and classified as (a)(1) or (a)(2) in accordance with 10 CFR 50.65. The inspectors reviewed station logs, maintenance WOs, selected surveillance test procedures, and a sample of CRs to determine whether the licensee was identifying issues related to the maintenance rule at an appropriate threshold and that corrective actions were appropriate. Additionally, the inspectors reviewed the licensee's performance criteria to determine whether the criteria adequately monitored equipment performance and to determine whether changes to performance criteria were 13reflected in the licensee's probabilistic risk assessment. During this inspection period,the inspectors reviewed the nuclear fuel system.This review represented one quarterly inspection sample.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed maintenance activities to review risk assessments (RAs) andemergent work control. The inspectors verified the performance and adequacy of RAs, management of resultant risk, entry into the appropriate licensee-established risk bands, and the effective planning and control of emergent work activities. The inspection activities included, but were not limited to, a verification that licensee RA procedures were followed and performed appropriately for routine and emergent maintenance, that RAs for the scope of work performed were accurate and complete, that necessary actions were taken to minimize the probability of initiating events, and that activities to ensure that the functionality of mitigating systems and barriers were performed.

Reviews also assessed the licensee's evaluation of plant risk, risk management, scheduling, configuration control, and coordination with other scheduled risk-significant work for these activities. Additionally, the assessment included an evaluation of external factors, the licensee's control of work activities, and appropriate consideration of baseline and cumulative risk.The inspectors observed maintenance or planning for the following activities or risk-significant systems undergoing scheduled or emergent maintenance for a total of four samples:*turbine generator electrohydraulic control (EHC) circuitry and bypass valvecircuit card repairs following an unexpected turbine trip during the week of May 14, 2007;*digital feedwater pump controller repairs following a reactor scram that wasassociated with the system during the week of May 14, 2007; *reactor recirculation flow control valve 'A' outage repairs following valvemalfunction during the week of June 11, 2007; and*reactor recirculation pump 'A' motor repair efforts following an unexpectedpump trip during the week of June 25, 2007.

b. Findings

No findings of significance were identified.

141R15Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors reviewed operability evaluations that affected mitigating systems orbarrier integrity to ensure that operability was properly justified and that the component or system remained available. The inspection activities included, but were not limited to, a review of the technical adequacy of the operability evaluations to determine the impact on Technical Specifications (TS), the significance of the evaluations to ensure that adequate justifications were documented, and that risk was appropriately assessed. The inspectors reviewed the following operability evaluations for a total of threesamples:*an operability evaluation associated with a Division 1 EDG modificationimplementation during the week of May 7, 2007; *an operability evaluation associated with a Division 2 EDG fuel oil transfer pumpoil leak during the week of June 24, 2007; and*an operability evaluation associated with a Division 1 EDG injector fuel oil leakduring the week of June 24, 2007.

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications (71111.17).1Motor Feed Pump Valve Digital Control Modification

a. Inspection Scope

During the week of April 16, 2007, the inspectors reviewed the design change packagefor the motor feed pump valve digital control modification. The inspectors reviewed the engineering change package, 10 CFR 50.59 safety evaluation, and the design interface evaluations relative to the Perry licensing basis. Finally, the inspectors reviewed the WOs and walked down the modification to determine whether it was installed per design documents. This review constituted one sample.

b. Findings

No findings of significance were identified.

15.2Division 2 EDG Governor Upgrade

a. Inspection Scope

During the week of April 16, 2007, the inspectors reviewed the design change packagefor the governor replacement upgrade for the Division 2 EDG. The inspectors reviewed the engineering change package, 10 CFR 50.59 safety evaluation, and the design interface evaluations relative to the Perry licensing basis. Finally, the inspectorsreviewed the WOs and walked down the modification to determine whether it was installed per design documents. This review constituted one sample.

b. Findings

No findings of significance were identified.3 Division 1 and 2 EDG Loss of Offsite Power (LOOP) Start Logic Modification

a. Inspection Scope

During the week of April 30, 2007, the inspectors reviewed the design change packagesfor modifications to the LOOP start logic circuit for the Division 1 and Division 2 EDG.

The inspectors reviewed the engineering change package, 10 CFR 50.59 safety evaluation, and the design interface evaluations relative to the Perry licensing basis.

Finally, the inspectors reviewed the WOs and walked down the modification to determine whether it was installed per design documents. This review constituted one sample.

b. Findings

No findings of significance were identified1R19Post-Maintenance Testing (71111.19)

a. Inspection Scope

The inspectors verified that the post-maintenance test procedures and activities wereadequate to ensure system operability and functional capability. Activities were selected based upon the structure, system, or component's ability to impact risk. The inspection activities included, but were not limited to, witnessing or reviewing the integration of testing activities, applicability of acceptance criteria, test equipment calibration and control, procedural use and compliance, control of temporary modifications or jumpers required for test performance, documentation of test data, system restoration, and evaluation of test data. Also, the inspectors verified that maintenance and 16post-maintenance testing activities adequately ensured that the equipment met thelicensing basis, TS, and Updated Safety Analysis Report (USAR) design requirements. The inspectors selected the following post-maintenance activities for review for a total ofseven samples:*Division 2 EDG after a maintenance outage during the week of April 23, 2007;*Division 1 EDG after LOOP logic circuit modification during the week ofApril 23, 2007;*Division 3 EDG following corrective maintenance during the week ofApril 30, 2007;*main steam isolation valve 'C' following corrective maintenance during the weekof April 30, 2007;*HPCS level 8 relays following maintenance during the week of May 12, 2007;

• reactor pressure vessel shutdown and upset reference leg union following repairduring the week of May 12, 2007; and*containment vacuum breaker and isolation valve testing following maintenanceduring the weeks of May 20, 2007, and June 3, 2007.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities (71111.20).1Refueling Outage

a. Inspection Scope

The inspectors evaluated outage activities for RFO11 that began on April 2, 2007,and ended on May 13, 2007, when the generator was synchronized to the grid. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.The inspectors observed or reviewed the reactor cooldown, outage equipmentconfiguration and risk management, electrical lineups, selected clearances, control and monitoring of decay heat removal, control of containment activities, startup and heatup activities, and identification and resolution of problems associated with the outage.The inspectors selected risk-significant heavy load lift evolutions conducted duringthe outage for observation and review. The inspectors reviewed the licensee's design basis, preventive maintenance program, lift procedures, and load drop analysis to determine whether the licensee performed heavy lifting evolutions in a manner consistent with safety.

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b. Findings

No findings of significance were identified..2Forced Outage

a. Inspection Scope

The inspectors evaluated outage activities that began after a turbine generator tripon May 13, 2007, and ended on May 14, 2007. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.The inspectors observed or reviewed the outage equipment configuration and riskmanagement, electrical lineups, selected clearances, and identification and resolution of problems associated with the outage.These outage inspection activities constituted a single forced outage inspection sample.

b. Findings

No findings of significance were identified..3Forced Outage

a. Inspection Scope

The inspectors evaluated outage activities that began after the reactor scram onMay 15, 2007, and ended on May 17, 2007. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.The inspectors observed or reviewed the outage equipment configuration and riskmanagement, electrical lineups, selected clearances, control and monitoring of decay heat removal, control of containment activities, startup activities, and identification and resolution of problems associated with the outage.These outage inspection activities constituted a single forced outage inspection sample

b. Findings

No findings of significance were identified.

18.4Forced Outage

a. Inspection Scope

The inspectors evaluated outage activities that began on May 18, 2007, and endedon May 19, 2007. The licensee removed the turbine generator from the grid to repair a hydraulic fluid leak from the main turbine mechanical trip system. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.The inspectors observed or reviewed the outage equipment configuration and riskmanagement, electrical lineups, selected clearances, and identification and resolution of problems associated with the outage.These outage inspection activities constituted a single forced outage inspection sample

b. Findings

No findings of significance were identified..5Forced Outage

a. Inspection Scope

The inspectors evaluated outage activities that began on June 21, 2007, and endedon June 25, 2007. The plant was shutdown to effect repairs to the 'A' flow control valve. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.The inspectors observed or reviewed the reactor shutdown, outage equipmentconfiguration and risk management, electrical lineups, selected clearances, control and monitoring of decay heat removal, control of containment activities, startup activities, and identification and resolution of problems associated with the outage.These outage inspection activities constituted a single forced outage inspection sample.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors reviewed surveillance testing activities to assess operational readinessand to ensure that risk-significant structures, systems, and components were capable of performing their intended safety function. Activities were selected based upon risk 19significance and the potential risk impact from an unidentified deficiency or performancedegradation that a system, structure, or component could impose on the unit if the condition was left unresolved. The inspection activities included, but were not limited to, a review for preconditioning, integration of testing activities, applicability of acceptance criteria, test equipment calibration and control, procedural use, control of temporary modifications or jumpers required for test performance, documentation of test data, TS applicability, impact of testing relative to performance indicator (PI) reporting, and evaluation of test data. The inspectors selected the following surveillance testing activities for review for a totalof six samples:*cooldown rate routine surveillance testing performed on April 2, 2007; *Division 2 EDG routine testing performed during the week of April 23, 2007;*low pressure core spray (LPCS) pump and valve in-service testing performed onApril 26, 2007; *Division 2 LOOP/loss-of-coolant accident (LOCA) routine testing performedduring the week of May 5, 2007; *containment isolation valve testing performed the week of May 19, 2007; and

• single recirculation loop operation setpoint calibration surveillance performedduring the week of June 25, 2007.

b. Findings

No findings of significance were identified.Cornerstone: Emergency Preparedness1EP6Drill Evaluation (71114.06)

a. Inspection Scope

The inspectors selected emergency preparedness exercises that the licensee hadscheduled as providing input to the Drill/Exercise PI. The inspection activities included, but were not limited to, the classification of events, notifications to off-site agencies, protective action recommendation development, and drill critiques. Observations were compared with the licensee's observations and CAP entries. The inspectors verified that there were no discrepancies between observed performance and PI reported statistics. The inspectors selected the following emergency preparedness activity for review for atotal of one sample:*the licensee's June 14, 2007, emergency plan drill to evaluate the drillconduct and the adequacy of the licensee's critique of performance to identify weaknesses and deficiencies.

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b. Findings

No findings of significance were identified.2.RADIATION SAFETYCornerstone: Occupational Radiation Safety2OS1Access Control to Radiologically Significant Areas (71121.01).1Review of Licensee PI for the Occupational Exposure Cornerstone

a. Inspection Scope

The inspectors reviewed the licensee's Occupational Exposure Control cornerstone PIsto determine whether or not the conditions surrounding any PI occurrences had been evaluated and whether identified problems had been entered into the CAP for resolution. This review represented one inspection sample.

b. Findings

No findings of significance were identified.

.2 Plant Walkdowns and Radiation Work Permit Reviews

a. Inspection Scope

The inspectors reviewed radiologically significant work areas within the plant andreviewed work packages associated with these areas to determine if radiological controls including surveys, postings, and barricades were acceptable. The following four areas were reviewed and were controlled as radiation areas, high radiation areas (HRAs), or airborne areas: *refuel floor ISI at 360o platform activities;*under vessel work associated with high activity low power range monitor(LPRM) retrievals;*grind welds of N2 nozzles in the bioshield in preparation for ISI exams; and

• snubber activities in the drywell.The inspectors reviewed the radiation work permits (RWPs) and WOs used toaccess these four areas and other high radiation work areas to identify the work control instructions and control barriers that had been specified. Electronic dosimeter alarm set points for both integrated dose and dose rate were evaluated for conformity with survey indications and plant policy. Workers were interviewed to assess whether they were 21aware of the actions required when their electronic dosimeters noticeably malfunctionedor alarmed. The inspectors walked down and performed radiological survey measurements in thesethree areas, with the exception of the under vessel work that was remotely viewed, to verify that the RWP procedure, and engineering controls were in place, that licensee surveys and postings were complete and accurate, and that air samplers were properly located. The inspectors reviewed RWPs for any airborne radioactivity areas that existed duringthe inspection to verify barrier integrity and engineering controls performance (e.g., high efficiency particulate air ventilation system operation) and to determine if there was a potential for individual worker internal exposures of greater than 50 millirem committed effective dose equivalent. There were no airborne radioactivity areas in the plant during this outage. Work areas having a history of, or the potential for, airborne transuranics were evaluated to verify that the licensee had considered the potential for transuranic isotopes and provided appropriate worker protection. This review represented four inspection samples.

b. Findings

No findings of significance were identified..3Problem Identification and Resolution

a. Inspection Scope

The inspectors reviewed the licensee's self-assessments, audits, Licensee EventReports, and Special Reports related to the access control program to verify that identified problems were entered into the CAP for resolution. The inspectors reviewed 15 CAP reports related to access controls and two HRAradiological incidents (non-PIs identified by the licensee in HRAs less than 1 rem per hour). Staff members were interviewed and corrective action documents were reviewed to verify that follow-up activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk based on the following:*initial problem identification, characterization, and tracking;*disposition of operability/reportability issues;

• evaluation of safety significance/risk and priority for resolution;

• identification of repetitive problems;

• identification of contributing causes;

• identification and implementation of effective corrective actions;

• resolution of NCVs tracked in the corrective action system; and

• implementation/consideration of risk-significant operational experience feedback.

22The inspectors evaluated the licensee's process for problem identification,characterization, and prioritization to assess whether problems were entered into the CAP and resolved. For repetitive deficiencies and/or significant individual deficiencies in problem identification and resolution, the inspectors assessed whether the licensee's self-assessment activities were capable of identifying and addressing these deficiencies.These reviews represented three inspection samples.

b. Findings

No findings of significance were identified..4Job-in-Progress Reviews and Review of Work Practices in Radiologically SignificantAreas

a. Inspection Scope

The inspectors evaluated the licensee's radiological controls, job coverage and radiationworker practices for the following jobs:*refuel floor ISI at 360o platform activities;*under vessel work associated with high activity LPRM retrievals;

• grind welds of N2 nozzles in the bioshield in preparation for ISI exams; and

• snubber activities in the drywell.The inspectors reviewed radiation survey information to support these work activities;the radiological job requirements; the adequacy of the information exchanges during pre-job briefings; and the access control provisions for these areas to assess conformity with TS and with the licensee's procedures.Job performance was observed to determine if radiological conditions in the work areaswere adequately communicated to workers through the pre-job briefings and area postings. The inspectors also evaluated the adequacy of the oversight provided by the radiation protection (RP) staff (including the performance of radiological surveys and airsampling), the work oversight provided by the radiation protection technicians (RPTs),

and the administrative and physical controls used over ingress/egress into these areas.The inspectors also reviewed the licensee's procedure and generic practices associatedwith dosimetry placement and the use of multiple whole body dosimetry for work in HRAs having significant dose gradients for compliance with the requirements of 10 CFR 20.1201(c) and applicable industry guidelines. Additionally, previously completed work in areas where dose rate gradients were subject to significant variation, such as on the reactor nozzles activities, were reviewed to evaluate the licensee's practices for dosimetry placement. These reviews represented three inspection samples.

23b.FindingsNo findings of significance were identified..5High Risk Significant, High Dose Rate HRA and Very High Radiation Area (VHRA)Controls

a. Inspection Scope

The inspectors held discussions with the acting RP manager concerning high doserate/HRA and VHRA controls and procedures, including procedural changes that had occurred since the last inspection, in order to verify that any procedure modifications did not substantially reduce the effectiveness and level of worker protection. The inspectors discussed with RP supervisors the controls that were in place forspecial areas that had the potential to become VHRAs during certain plant operations to determine if these plant operations required communication beforehand with the RP group, so as to allow corresponding timely actions to properly post and control the radiation hazards. The inspectors conducted plant walkdowns to verify the posting and locking ofentrances to high dose rate high radiation, and VHRAs. These reviews represented three inspection samples.

b. Findings

No findings of significance were identified..6Radiation Worker Performance

a. Inspection Scope

During job performance observations, the inspectors assessed radiation workerperformance with respect to stated RP work requirements and assessed whether workers were aware of the significant radiological conditions in their workplace, of the RWP controls and limits in place, and that their performance had accounted for the level of radiological hazards present. The inspectors reviewed radiological problem reports which found that the cause of theevent was due to radiation worker errors to determine if there was an observable pattern traceable to a similar cause and to determine if this perspective matched the corrective action approach taken by the licensee to resolve the reported problems. These problems, along with planned and taken corrective actions, were discussed with the RP manager. These reviews represented two inspection samples.

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b. Findings

No findings of significance were identified..7RPT Proficiency

a. Inspection Scope

The inspectors evaluated RPT performance during job performance observations,with respect to RP work requirements and evaluated whether they were aware of the radiological conditions in their workplace, the RWP controls and limits in place, and if their performance was consistent with their training and qualifications. The inspectors reviewed radiological problem reports that found RPT error as the causeof the event to determine if there was an observable negative trend and to determine if the corrective actions taken by the licensee adequately addressed the reported problems. These reviews represented two inspection samples.

b. Findings

No findings of significance were identified.2OS2As-Low-As-Reasonably-Achievable (ALARA) Planning and Controls (71121.02).1

a. Inspection Scope

The inspectors reviewed plant collective exposure history and current exposuretrends, along with ongoing and planned outage activities, in order to assess current performance and exposure challenges. This included reviewing the plant's current three-year rolling average collective exposure and comparing the site's radiological exposure on a yearly basis for the previous three years. The inspectors reviewed the outage work activities scheduled during the inspectionperiod along with associated work activity exposure estimates, including the four work activities which were likely to result in the highest personnel collective exposures:*refuel floor ISIs at 360o platform activities;*under vessel work associated with high activity LPRM retrievals;

• grind welds of N2 nozzles in the bioshield in preparation for ISI exams; and

• snubber activities in the drywell.Procedures associated with maintaining occupational exposures ALARA and processesused to estimate and track work activity specific exposures were reviewed. These reviews represented three inspection samples.

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b. Findings

No findings of significance were identified..2Radiological Work Planning.

a. Inspection Scope

The inspectors evaluated the licensee's list of work activities, ranked by estimatedexposure, that were in progress and selected the four work activities of highest exposure potential. The inspectors reviewed the ALARA work activity evaluations, exposure estimates,integration of ALARA requirement, into work procedure and RWP documents, and exposure mitigation requirements, in order to determine if the licensee had established procedures, along with engineering and work controls, that were based on sound RP principles, in order to achieve occupational exposures that were ALARA. This also involved determining if the licensee had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, or special circumstances. The inspectors evaluated the interfaces between operations, RP, maintenance,maintenance planning and scheduling, and engineering. The interfaces were evaluated to identify any problems or missing program elements.The inspectors compared and evaluated the person-hour estimates (provided bymaintenance planning and other groups to the RP group) with actual work activity time requirements.The inspectors evaluated the work activity planning that included consideration ofdose rate reduction activities such as shielding of N2 nozzle works in the drywell, job scheduling, and scaffolding installation and removal.These reviews represented two inspection samples.

b. Findings

No findings of significance were identified..3Verification of Dose Estimates and Exposure Tracking Systems

a. Inspection Scope

The inspectors reviewed the assumptions and bases for the current annual collectiveexposure estimate including procedures, in order to evaluate the licensee's methodology for estimating work activity-specific exposures and the intended dose outcome. Dose rate and man-hour estimates were evaluated for reasonable accuracy.

26The inspectors reviewed the licensee's exposure tracking system in order to determinewhether the level of exposure tracking detail, exposure report timeliness and exposure report distribution was sufficient to support control of collective exposures. In addition, the inspectors reviewed whether RWPs contained too many work activities that may cause a dose control problem. During the conduct of exposure significant maintenance work, the inspectors assessed whether licensee management was aware of the exposure status of the work and would intervene if exposure trends increased beyond exposure estimates.This review represented one sample.

b. Findings

No findings of significance were identified..4Job Site Inspections and ALARA Controls

a. Inspection Scope

The inspectors observed the four jobs that were being performed in radiation areas,airborne radioactivity areas, or HRAs for observation of work activities that presented the greatest radiological risk to workers.The licensee's use of engineering controls to achieve dose reductions was evaluated toassess whether procedures and controls were consistent with the licensee's ALARA reviews, that sufficient shielding of radiation sources was provided for, and that the dose expended to install and remove the shielding did not exceed the dose reduction benefits afforded by the shielding. This review represented one inspection sample.

b. Findings

No findings of significance were identified..5Source-Term Reduction and Control

a. Inspection Scope

The inspectors reviewed licensee records to determine the historical trends and currentstatus of tracked plant source terms and to evaluate if the licensee was making allowances and developing contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry. This review represented one sample.

b. Findings

No findings of significance were identified.

27.6Radiation Worker Performance

a. Inspection Scope

Radiation worker and RPT performance were observed during work activitiesbeing performed in radiation areas, airborne radioactivity areas, and HRAs that presented the greatest radiological risk to workers. The inspectors assessed whether workers demonstrated the ALARA philosophy in practice by being familiar with the work activity scope and tools to be used, by utilizing ALARA low dose waiting areas, and by complying with work activity controls. This review represented one inspection sample.

b. Findings

No findings of significance were identified..7Problem Identification and Resolution

a. Inspection Scope

The inspectors reviewed the licensee's self-assessments, audits, and special reportsrelated to the ALARA program since the last inspection. The inspectors assessed the adequacy of the licensee's overall audit program's scope and frequency to meet the requirements of 10 CFR 20.1101(c). Corrective action reports generated during the RFO11 that related to the ALARAprogram were selectively reviewed, and staff members were interviewed to verify that follow-up activities were being conducted in a timely manner commensurate with their importance to safety and risk using the following criteria:*initial problem identification, characterization, and tracking;*disposition of operability/reportability issues;

• evaluation of safety significance/risk and priority for resolution;

• identification of contributing causes; and

• identification and implementation of effective corrective actions.The licensee's CAP was also reviewed to determine if repetitive deficiencies in problemidentification and resolution were being addressed. This review represented two inspection samples.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As discussed in previous sections of this report, the inspectors routinely reviewedissues during baseline inspection activities and plant status reviews to determine whether they were being entered into the licensee's CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed.This is not an inspection sample.

b. Findings

No findings of significance were identified.

.2 Semi-Annual Trend Review

a. Inspection Scope

The inspectors reviewed monthly performance reports, self-assessments, qualityassurance assessment reports, performance improvement initiatives and CRs to identify any trends that had not been adequately evaluated or addressed by proposed corrective actions.This review represented one semi-annual trend review inspection sample.

b. Findings

No findings of significance were identified.

4OA3 Event Followup

.1 High Grid Voltage Periods

a. Inspection Scope

During the month of April 2007, the licensee responded to several periods of highelectrical grid voltage and implemented Off-Normal Instruction (ONI) S11, "Hi/Low Voltage," Revision 4. The inspectors observed the licensee's response and followup actions. The inspectors reviewed licensee actions to determine whether the actions were consistent with licensee procedures.This review represented the first of six inspection samples.

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b. Findings

No findings of significance were identified..2Loss of Reactor Pressure Vessel Shutdown Level Indication

a. Inspection Scope

On May 5, 2007, at about 4:25 p.m., operators responded to a rapid rise of indicatedreactor water level while the reactor was shutdown. A flange associated with the RCIC system head spray piping was determined to be leaking. Due to the leak location, the leak affected the shutdown and upset range reactor water level indication reference leg system and caused a loss of level indication. Operators placed the reactor in a stable condition and licensee personnel repaired the flange to restore reactor level indication later that same day. The inspectors reviewed the licensee's response and follow-up actions to determine whether the actions were consistent with licensee procedures. This review represented the second of six inspection samples.

b. Findings

Introduction:

A finding of very low safety significance and an associated NCV ofTS 5.4, "Procedures," was self-revealed when reactor water level indication was lost while the reactor was shutdown on May 5, 2007. Specifically, licensee personnel failed to implement appropriate procedures for the re-assembly of RCIC head spray piping during a 1993 RFO.Description: On May 5, 2007, at about 4:25 p.m., operators responded to an apparentrapid rise in reactor water level indication while the reactor was shutdown. Reactor water level was being maintained in a band of 360 to 485 and reactor pressure was about 625 psig for pressure testing when the loss of level indication occurred.

Operators suspended work activities associated with the reactor vessel, lowered reactor vessel pressure, and vented the reactor vessel to the drywell sump. When the reactor vessel was vented to the drywell sump, reactor water level indicated 480";

however, indication from a drywell drain sump recorder indicated that water level was up to the head vent. At about 4:54 p.m., licensee personnel reported an air leak from a flange leading to the condensing pot for the shutdown and upset range reactor water level instrument reference leg. This flange was an ASME Class 1 tongue-and-groove connection for a 1" diameter pipe associated with the RCIC system head spray piping. Licensee personnel inspected the flange, identified that three gaskets were installed inthe flange, and that two of the installed gaskets were not engaged in the joint. One Flexitallic style CG gasket was engaged in the joint and two style R-3 gaskets were not engaged. The licensee determined that the appropriate gasket configuration for this joint was one style R-3 gasket.

30In addition, licensee personnel found that the fasteners associated with the flange werenot at the appropriate torque. The as-found torque values for the four bolt fasteners associated with the flange were found to be 190, 125, 100, and 175 ft-lbs. The licensee determined that the required torque for these fasteners was 200 ft-lbs.Licensee personnel performed a search of work history associated with the head-spraypiping to determine when the affected flange was last worked. The licensee determined that the flange was last worked during a 1993 RFO. The inspectors determined that the licensee failed to implement appropriateprocedures during the 1993 maintenance activity because the maintenance resulted in an improperly assembled flange connection.As part of the licensee's immediate corrective actions, the flange connection wasrepaired at 12:48 a.m. on May 6, 2007, reactor water level indication was restored, and the issue was entered into the CAP.Analysis: The inspectors determined that the failure of licensee personnel toimplement maintenance and test procedures appropriate to the circumstances affecting the safety-related RCIC head spray piping was a performance deficiency warranting a significance evaluation. The inspectors concluded that the finding was greater than minor in accordance with Appendix B, "Issue Screening," of IMC 0612, "Power Reactor Inspection Reports," dated November 2, 2006. The finding was associated with the equipment performance attribute of the reactor safety Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the finding resulted in a loss of reactor water level indication and challenged plant stability. The inspectors performed a significance determination of this issue using IMC 0609,"Significance Determination Process," dated November 22, 2005, Appendix G,

"Shutdown Operations Significance Determination Process," dated February 28, 2005.

The inspectors evaluated the plant conditions and determined that the finding did not meet the criteria for a "Loss of Control" per Table 1 of Appendix G. Specifically, the finding did not result in a reactor water level drop of 2' and it did not result in inadvertent reactor vessel pressurization. In addition, adequate mitigation capability per Checklist 8 criteria (core heat removal, inventory control, power availability, and containment guidelines) were met. Because the leaking flange was located at the top of the reactor vessel and because level instrumentation associated with low reactor water level remained available, the inspectors determined that the finding did not affect the licensee's ability to maintain water inventory in the vessel and did not affect decay heat removal systems. As such, the finding was determined to be of very low safety significance (Green).Enforcement: Technical Specification 5.4, "Procedures," required the implementationof the applicable procedures recommended in Regulatory Guide 1.33, "Quality Assurance Program Requirements (Operation)," Revision 2, dated February 1978.

Regulatory Guide 1.33, Appendix A, Part 9a, stated, "Maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed 31in accordance with written procedures, documented instructions, or drawingsappropriate to the circumstances." Contrary to this requirement, during a RFO in 1993, licensee personnel failed to implement appropriate procedures during maintenance on a reactor core isolation cooling pipe flange. This led to a loss of reactor water level instrumentation while the reactor was shut down on May 5, 2007. However, because of the very low safety significance of the issue and because the issue has been entered into the licensee's CAP (CR 07-20046), the issue is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000440/2007003-02)..3Main Generator Turbine Trip Due to EHC Circuitry Card Installation

a. Inspection Scope

At 8:28 a.m. on May 13, 2007, while the reactor was at 25 percent power, the maingenerator turbine tripped on reverse power. An inadvertent signal from the EHC circuitry caused both turbine control valves and combined intermediate valves to close.

As a result, the main generator turbine tripped offline, four turbine bypass valves opened fully and a fifth bypass valve opened halfway. Operators reduced reactor power to 10 percent and placed the plant in a stable condition.The inspectors reviewed licensee actions to determine whether the actions wereconsistent with licensee procedures and TS. This review represents the third sample of six for this procedure.

b. Findings

Introduction:

A finding of very low safety significance was self-revealed when the mainturbine generator tripped on reverse power due to an improperly seated EHC system control circuit card on May 13, 2007, at 8:28 a.m.Description: On May 13, 2007, during initial power ascension after a RFO, technicianswere conducting an inspection of electrical cabinets associated with the EHC system in preparation for post-maintenance testing. Work had been conducted during the RFO that required some EHC electrical cards to be removed and reinstalled. The inspection was intended to provide a preliminary survey of the cards so that output readings could be taken at power. Operators were in the process of increasing reactor power from 20 percent to 30 percent at the time of the inspection walkdowns. Following an inspection activity, technicians closed the door to cabinet 1H13P821 and then heard relays changing state. Subsequently, the main turbine control valves closed, the turbine bypass valves opened, and the main turbine tripped. The reactor was at 27 percent power at the time of the turbine trip. The reactor did not scram because this power level was within the capability of the bypass valve system. Operators reduced reactor power to 10 percent and stabilized the plant.The licensee's investigation determined that the primary cause of the event wasmaintenance personnel's failure to fully insert a low value gate card in the turbine speed control circuit after maintenance was completed during the RFO. The licensee 32determined that the technician's action of closing the cabinet panel door agitated theimproperly installed card. This agitation caused the card to generate a speed error signal that caused the control system to view the turbine in an overspeed condition. As part of their immediate investigation, the licensee performed an extent-of-conditionreview. During this review, licensee personnel identified another card that was not fully inserted that was also worked on during the RFO. The affected card was associated with a function of providing no-load limit signal and no setback signal for a loss of circulating water condition. When licensee personnel fully inserted the card, a turbine control valve amplifier alarm occurred. Licensee personnel further identified five other control circuit cards, some associated with the turbine control system, that were not fully seated, but were not worked on during the RFO. As part of their immediate corrective action, licensee personnel repaired the installationof all affected circuit cards and entered the issue into their CAP.

Analysis:

The inspectors determined that licensee personnel's failure to properlyinstall EHC system control circuit cards during the RFO was a performance deficiency warranting a significance evaluation in accordance with IMC 0612,

"Power Reactor Inspection Reports," Appendix B, "Issue Disposition Screening,"

dated November 2, 2006. The inspectors determined that the finding was more than minor because it was associated with the protection against external factors attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability. Specifically, the finding resulted in a main turbine trip while at 27 percent reactor power.The inspectors performed a significance determination of this issue, using IMC 0609,"Significance Determination Process," dated November 22, 2005, Appendix A,

"Significance Determination of Reactor Inspection Findings for At-Power Situations,"dated March 23, 2007. The inspectors determined that the finding was a transient initiator contributor and that it did not affect the likelihood that mitigation equipment or functions would not be available. Therefore, the inspectors determined that the finding was of very low safety significance. The primary cause of this finding was related to the cross-cutting area of Human Performance per IMC 0305 H.4(a) because the organization failed to properly communicate human error prevention techniques for proper insertion of the control cards.

Enforcement:

The inspectors determined that no violation of regulatory requirementsoccured (FIN 05000440/2007003-03)..4Reactor Scram Due to Loss of Feedwater Flow

a. Inspection Scope

At 12:58 a.m. on May 15, 2007, while at 31 percent power, the reactor automaticallyscrammed due to a reactor protection signal for reactor pressure vessel (RPV) Level 3.

At the time of the event, licensee personnel were in the process of tuning the 'A' 33reactor feed pump turbine (RFPT) following installation of a digital control modification. The 'A' RFPT was in manual control, 'B' RFPT was in standby mode, and the motor feedwater pump was secured. Operators placed 'A' RFPT in automatic control. When

'A' RFPT was placed in automatic control, actual RPV level was 196.2" and the level controller was set to 196.0". The RPV level decreased rapidly and operators attempted to take manual control of feedwater flow. The reactor scrammed automatically on low RPV level.The inspectors reviewed licensee actions to determine whether the actions wereconsistent with licensee procedures and TS. This review represents the fourth of six inspection samples.

b. Findings

Introduction:

A finding of very low safety significance was self-revealed when thereactor scrammed on low reactor water level on May 15, 2007, at 12:58 a.m.Description: On May 15, 2007, during testing and tuning of a recently installed digitalfeedwater control system (DFWCS), the plant was at 31 percent power. The 'A' RFPT was feeding the reactor vessel, and the 'B' RFPT was idle. Operators placed the 'A' RFPT in manual mode for tuning. A new design feature, auto-tracking, allowed the 'A' RFPT to receive input from'B' RFPT even though the 'B' RFPT was in standby mode. During the design modification acquisition process, the licensee had provided the design vendor with design requirements that stated the various feedwater configurations in which the new system would be required to perform. One of the configurations specified was a condition of one RFPT in an on-line status and the other RFPT in an available status.

The vendor interpreted the term "available" as an RFPT that was providing feedwater to the reactor vessel. However, the RFPT, when considered available while idled at 1100 rpm, did not provide feedwater to the reactor vessel. This design translation error was not identified during the preparation, acceptance, and testing processes of the licensee. On May 15, 2007, while the 'A' RFPT was in manual mode, actual reactor water levelwas higher than the automatic level controller setpoint level. The difference between actual reactor level and controller setpoint level caused the 'B' RFPT control circuitry to generate a signal to reduce feedwater flow. Because the 'B' RFPT was not feeding the reactor vessel while in idle, the 'B' RFPT control circuitry's signal to reduce flow had no effect on actual reactor water level. The 'B' RFPT control circuitry continued to generate a signal to reduce flow. Due to the auto-tracking feature of the new design, the 'A' RFPT control circuitry received this same signal to reduce flow. Because the 'A' RFPT was in manual mode, the signal to reduce flow had no effect on the 'A' RFPT and the reactor water level remained higher than the level controller setpoint. This condition existed for approximately 30 minutes, which created a 0 percent flow demand signal that affected both RFPT controllers. When operators placed the 'A' RFPT in automatic control, the controller immediately reduced feedwater flow. The operators 34were not able to restore manual control before the reactor automatically scrammed ona reactor protection system low reactor water level signal.The licensee subsequently identified the design flaw in the software modification andperformed corrective action to install a software package that corresponded to actual plant design. In addition, the licensee evaluated other areas of concern to determine whether other latent issues would impact plant startup.On May 19, 2007, during testing and tuning of the recently installed DFWCS, the plantwas at 50 percent power. The 'A' RFPT was feeding the reactor vessel, and the 'B' RFPT was idle. Operators placed the 'B' RFPT in automatic control and reactor level oscillations occurred. Operators placed the 'B' RFPT in manual control and reactor water level continued to oscillate. The operators placed the 'A' RFPT in manual mode and restored control of reactor water level. During the event, the lowest reactor water level reached was 183 ".The licensee subsequently identified that the cause of the May 19 event was improperadjustment of the servo position controllers for the RFPTs. During the RFO, controllers for both RFPTs were replaced and required post-maintenance tuning. Licensee engineering personnel that were implementing the DFWCS modification did not include this tuning in the modification test procedure TXI-0373, "Digital Feedwater Control Systems Startup Test and Tuning". Licensee personnel performed tuning operations outside of TXI-0373 on May 21, 2007. This process revealed that the 'B' RFPT null current had been set to 90 milliamps while the appropriate value should have been 19 milliamps, and that gain had been set to 5 milliamps while the appropriate gain value should have been 14 milliamps. Licensee personnel adjusted the controllers to the correct settings and the RFPTs subsequently operated normally in manual control.On May 22, 2007, during testing and tuning of the recently installed DFWCS, theplant was at 50 percent power. The 'A' RFPT was feeding the reactor vessel, and the

'B' RFPT was idle. The 'B' RFPT was placed in automatic control and reactor level oscillations occurred. The 'A' RFPT was placed in manual mode and reactor water level continued to oscillate and a low reactor water level alarm was received. The operators restored water level and attempted to idle the 'A' RFPT. Reactor water level lowered to 182". Operators then regained control of reactor water level and restored level to the normal band. The licensee subsequently identified that the cause of the May 22 event was thatthe RFPT recirculation valve position controllers were incorrectly set. This caused the

'A' RFPT recirculation valve to improperly open and caused a loss of feedwater. The licensee determined that the positioner spans were set to be too short and that the positioner zero position was set too high. In addition the locking pressure was set to about 10 pounds pressure when 67.5 pounds pressure was required. During the RFO, maintenance on both RFPTs was performed and required post-maintenance testing. Licensee engineering personnel responsible for the DFWCS modifications did not include this testing in the test procedure TXI-0373, "Digital Feedwater Control Systems Startup Test and Tuning". When licensee personnel repaired the actuator settings, the RFPTs operated normally in all modes.

35Analysis: The inspectors determined that the licensee's failure to adequatelycontrol design modifications associated with the DFWCS was a performance deficiency warranting a significance evaluation in accordance with IMC 0612,

"Power Reactor Inspection Reports," Appendix B, "Issue Disposition Screening,"

issued on November 2, 2007. The inspectors determined that the finding was more than minor because it was associated with the protection against external factors attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability.

Specifically, the finding resulted in a reactor scram and challenged reactor water level control.The inspectors performed a significance determination of this issue, using IMC 0609,"Significance Determination Process," dated March 21, 2003, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations," dated March 23, 2007. The inspectors determined that the finding was a transient initiator contributor and that it did not affect the likelihood that mitigation equipment or functions would not be available. Therefore, the inspectors determined that the finding was of very low safety significance. The primary cause of this finding was related to the cross-cutting area of Human Performance per IMC 0305 H.3(a) because the organization failed to properly manage design and configuration work activities that incorporated insights to risk.Enforcement: The inspectors determined that no violation of regulatory requirementshad occurred (FIN 05000440/2007003-04)..5Recirculation Pump Trip/Auto Restart

a. Inspection Scope

On June 21 at 8:30 p.m., operators commenced a reactor shutdown in order to repairthe reactor recirculation 'A' flow control valve. During power reduction, while operators were attempting to shift reactor recirculation pumps to slow speed, the 'B' reactor recirculation pump tripped unexpectedly and then attempted to start in fast speed several times. Operators removed the power fuses for the 'B' recirculation pump and subsequently completed plant shutdown to Mode 3.After repairs were completed to the 'A' low control valve and the 'B' recirculation pump,operators commenced reactor startup on June 24 at 3:51 a.m. and synchronized to the grid on June 25 at 1:50 a.m. The inspectors observed operator actions in response to the recirculation pump trip. The inspectors reviewed licensee actions to determine whether the actions were consistent with licensee procedures.This review represents the fifth of six inspection samples.

b. Findings

No findings of significance were identified.

36.6Recirculation Pump Trip

a. Inspection Scope

At 11:48 p.m. on June 27 the reactor was at 87 percent power when the'A' recirculation pump automatically tripped off due to a protective relay lockout. Operators stabilized the plant at 57 percent power and subsequently entered single loop operations. The inspectors responded to the control room and observed operator actions inresponse to the recirculation pump trip. The inspectors reviewed licensee actions to determine whether the actions were consistent with licensee procedures.This review represents the sixth of six inspection samples.

b. Findings

No findings of significance were identified.

4OA5Other Activities.1(Closed) VIO 05000440/2004005-01: Improper Maintenance Causes EmergencyService Water Pump FailureClosed by NRC correspondence dated March 2, 2007, re: Closure of theConfirmatory Action Letter (CAL 3-05-001); Closure of Long-Standing Open White Findings; and, Transition from Multiple/Repetitive Degraded Cornerstone Column (ADAMS Accession # ML 070610103).

.2 (Closed) VIO 05000440/2004006-01:

Inadequate LPCS/RHR 'A' Fill and VentProcedures Results in System Inoperability After Loss of Offsite Power.Closed by NRC correspondence dated March 2, 2007, re: Closure of theConfirmatory Action Letter (CAL 3-05-001); Closure of Long-Standing Open White Findings; and, Transition from Multiple/Repetitive Degraded Cornerstone Column (ADAMS Accession # ML 070610103). 4OA6Meetings.1Exit MeetingThe inspectors presented the inspection results to Barry Allen and other members oflicensee management on July 2, 2007. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

37.2Interim Exit MeetingsInterim exits were conducted for:*ISI for Inspection Procedure 71111.08 with Mr. B. Allen on April 13, 2007; and.*access control to radiologically significant areas and the ALARA planning andcontrols program with Mr. L. W. Pearce, Site Vice President on April 13, 2007.4OA7Licensee-Identified ViolationsThe following violation is of very low safety significance (Green) that was identified bythe licensee and is a violation of NRC requirements that meets the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.Cornerstone: Initiating Events

• Technical Specification 5.4, "Procedures," required the implementationof the applicable procedures recommended in Regulatory Guide 1.33,

"Quality Assurance Program Requirements (Operation)," Revision 2, dated February 1978. Regulatory Guide 1.33, Appendix A, Part 9a, stated,

"Maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances." Contrary to this requirement, the licensee identified that on May 7, 2007, maintenance was performed without the use of appropriate procedures to modify the safety-related reactor dryer and moisture separator strongback (CR 07-20132). The inspectors completed a Phase 1 SDP review of this issue in accordance with Appendix G," Shutdown Operations Significance Determination Process," dated May 25, 2004 of IMC 0609, "Significance Determination Process (SDP)," dated November 22, 2005. The inspectors determined that the finding was of very low safety significance because the finding did not require quantitative assessment.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

K. Freeman, Radiation Protection Supervisor

S. Lee, Acting, Radiation Protection Manager

S. Thomas, Radiation Protection Manager

C. Wirtz, ISI Program Owner

J. Lausberg, Regulatory Compliance Manager

D. Evans, Operations Manager

M. Wayland, Maintenance Director

J. Shaw, Nuclear Engineering DirectorNuclear Regulatory Commission

B. Burgess, Chief, Reactor Projects Branch 6

C. Brown, DRS

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and

Closed

05000440/FIN-2007003-01NCVImproper Storage of Combustible Material (Section 1R05)

05000440/FIN-2007003-02NCVFailure to Implement Appropriate Procedure in Re-Assembly of Reactor Core Isolation Cooling Piping

(Section 4OA3.2)

05000440/FIN-2007003-03FINMain Turbine Generator Tripped on Reverse Power(Section 4OA3)

05000440/FIN-2007003-04FINReactor Scrammed on Low Reactor Water Level(Section 4OA3.4)

Closed

05000440/FIN-2007003-01NCVImproper Storage of Combustible Material (Section 1R05)

05000440/FIN-2007003-02NCVFailure to Implement Appropriate Procedure in Re-Assembly of Reactor Core Isolation Cooling Piping

(Section 4OA3.2)

05000440/FIN-2007003-03FINMain Turbine Generator Tripped on Reverse Power(Section 4OA3)

05000440/FIN-2007003-04FINReactor Scrammed on Low Reactor Water Level(Section 4OA3.4)

LIST OF DOCUMENTS REVIEWED

The following is a list of documents reviewed during the inspection.

Inclusion on this list doesnot imply that the NRC inspectors reviewed the documents in their entirety but rather that selected sections of portions of the documents were evaluated as part of the overall inspection effort.

Inclusion of a document on this list does not imply NRC acceptance of the document or any part of it, unless this is stated in the body of the inspection report.Section 1R01 Adverse Weather ProtectionCR 07-20483, Summer Prep Orders Rescheduled Due to Unresolved Restraint; dated May 10, 2007Section 1R04 Equipment AlignmentSDM G41, Fuel Pool Cooling and Clean-up System, Rev. 5SOI-G41 (FPCC), Fuel Pool Cooling and Clean-up System, Rev.20

Drawing 302-0651, Fuel Pool Cooling and Clean-Up System, Rev. KK

Drawing 302-0653, Fuel Pool Filter Demineralizer System, Rev. T

Drawing 302-0654, Fuel Pool Cooling and Clean-Up System, Rev. P

Drawing 302-0655, Fuel Pool Cooling and Clean-Up System, Rev. U

System Description Manual, Section E12, "Residual Heat Removal System, Revision 9

System Operating Instruction

SOI-E12, Residual Heat Removal System, Revision 32, dated March 30, 2007

Drawing 302-0642, Residual Heat Removal, Revision DD, dated January 8, 2007

Drawing 302-0643, Residual Heat Removal System, Revision VV dated January 8, 2007

VLI-E22A; High Pressure Core Spray; Revision 7

VLI-R45; Division 1 And 2 Diesel Generator Fuel Oil System; Revision 5Section 1R05 Fire ProtectionFPI-TB; Turbine Building; Revision 3FPI-1RB; Reactor Building; Revision 4

FPI-OCC; Control Complex; Revision 7

FPI-1DG; Diesel Generator Building; Revision 5

CR 07-15930, Housekeeping in Turbine Lube Oil Storage Room Warrants Attention, dated March 7, 2007

CR 07-18012, Used Oil Storage Exceeds

CA 06-03843 Requirements, dated April 9, 2007

CR 07-18569, NRC ID - Incorrect Type of Oil Identified on TCP T-07-TB1-129, dated April 16, 2007

CR 07-20349, Improperly Stored Acetylene Cylinders in the Plant, dated May 10, 2007

CR 07-21085, Fire Protection Program Violation - Transient Combustibles Permits, dated May 24, 2007

FPI-A-B02, Scenario

FDM-1125-061307, Fire Drill on June 13, 2007 in Intermediate Building

CR 07-22597, Credit for Fire Drills Not Given Due to Missed Procedure Revision, dated June 26, 2007Section 1R08 Inservice Inspection ActivitiesCR 05-02892; Rust Stains On CRD Housings Under Vessel; dated March 31, 2005CR 06-01843; ISI Exams of Class 3 Support Attachments Performed with Wrong VT Method;

dated April 26, 2006

Attachment3CR 06-02029; Missed

GL 88-01 Category E (Flawed and Stress Improved) Weld Examination;dated May 8, 2006

NQI-0941; Liquid Penetrant Examination; Revision 11

NQI-0942; Magnetic Particle Examination; Revision 9

NDE-008; Manual Ultrasonic Examination of Ferritic Piping Welds; Revision 10

GE-UT-300; Procedure for Manual Examination of Reactor Vessel Assembly Welds in Accordance With PDI; Revision 10

GWI-0004; General Welding Requirements; Revision 12

PQR 002; dated November 4, 1983

PQR 009; dated January 30, 1985

WPS 1.1.2-001; Manual GTAW/SMAW; Revision 10; dated January 31, 2005Section 1R11 Licensed Operator RequalificationOTC 3058RFO11_PY; Cycle 12 Update Training; dated April 24, 2007

Section 1R12 Maintenance Effectiveness

PAP-1125; Monitoring The Effectiveness of Maintenance Program Plan; Revision 8

Maintenance Rule Report; Nuclear Fuel dated April 23, 2007Section 1R13 Maintenance Risk Assessments and Emergent Work ControlPAP-1924; Risk Informed Safety Assessment And Risk Management; Revision 4NOP-WM-0001; Work Management Process; Revision 2

CR 07-22706, Recirculation Pump A Trips After Receiving "Recirc A Motor Lockout" Annunciator, dated June 27, 2007

RFO 11; Level 1 Schedule

RFO 11; Level 2 Schedule Perry Work Implementation Schedule; Week 1, Period 1

Perry Work Implementation Schedule; Week 2, Period 1

Perry Work Implementation Schedule; Week 3, Period 1

Perry Work Implementation Schedule; Week 4, Period 1Section 1R15 Operability EvaluationsCR 07-19643; NRC Residents Question Status of Div II EDG With Open DCP; dated April 30, 2007

CR 07-19788; Incorrect PLCO Referenced in

CR 07-19643; dated May 2, 2007

PLCO P06-R43-002; Division 1 EDG Potential LCO Tracking Record

PLCO P07-R43-007; Division 2 EDG Potential LCO Tracking Record

WO 200175694; Division 2 Diesel Generator LOOP Start Logic Modification; dated April 24, 2007

CR 07-19926; Division 1 LOOP/LOCA Test SVI R43 T5366; dated May 3, 2007

CR 07-21988; Division 1 DG Fuel Oil Leak RB Injector #2; dated June 13, 2007

CR 07-21070; Division 2 Diesel FO Pump #2 Leaks Oil From Pump Seal - Coupling End;

dated May 24, 2007Section 1R17 Permanent Plant Modifications

WO 200173859; Install Digital Feedwater Control System; dated April 18, 2007

ECP 04-0049; Standby Diesel Generator (SDG)

WO 200188144; Install

ECP 04-0049, Upgrade Division 2 EGA/EGB-C Governor; dated April 18, 2007

Attachment4WO

200195772;

ECP 04-0049, Drill Holes in Flywheel; dated April 18, 2007WO

200238660;

ECP 04-0049, Electrical Work; dated April 18, 2007

WO 200188145;

ECP 04-0049, Implement Division 2 Upgrade; dated April 18, 2007

WO 200175694;

ECP 05-0229-01; Division 2 Diesel Generator LOOP Start Logic Modification;

dated April 6, 2007

ECP 05-0229; 10

CFR 50.59 Screen; Division 1 & 2 Diesel Generator Bus Under/Degraded Voltage Start Logic Modification

U.S. Nuclear Regulatory Commission, Region 3 Letter; Response to Disputed Violations

(IR 05000440/2005003); Perry Nuclear Power Plant; dated September 7, 2005Section 1R19 Post-Maintenance TestingWO

200195773; Functional Testing of Diesel Governor Modifications Installed underECP 04-0049; dated April 18, 2007

CR 07-17928; Steps for Standby Diesel Engine Logic Modification Found to be Missing; dated April 8, 2007

CR 07-18910; Admin Controls of DG Governor Mod Not Adequately Addressed in ECP; dated April 20, 2007

CR 07-18912; Division 2 Diesel Generator Unexpectedly Tripped After Start During Testing;

dated April 20, 2007

CR 07-18945; Wiring Problem Found in New Diesel Generator Control System; dated April 20, 2007

CR 07-19134; Unable to Close Work Packages; dated April 24, 2007

WO 200175691; Division 1 EDG LOOP Start Logic Modification for

ECP 05-0229; dated April 28, 2007

WO 200262095; Division 3 HPCS Diesel Generator Loss Of Off-Site Power Test; dated May 5, 2007

WO 200170106; MSIV C LLRT Repair; dated April 20, 2007

CR 07-18167; Leakage Rate of 1B21F0028C Exceeds Acceptance Criteria in SVI-B21-T9000;

dated April 10, 2007

CR 07-19355; MSIV Outboard Leakage Exceeds T.S. Limit; dated April 26, 2007

WO 200231764; Containment Vacuum Breaker and Isolation Valve Operability Test; dated May 22, 2007

WO 200231765; Containment Vacuum Breaker and Isolation Valve Operability Test; dated June 6, 2007

Drawing 351-0725-00000; Reactor Vessel Head Piping; Revision A

Drawing

SS-301-725-103.2; Nuclear Boiler System - Reactor Building; Revision B

WO 200167898; Reassemble Reactor Vessel and Drywell Head; dated May 5, 2007

GMI-0185; Reactor Vessel Disassembly And Assembly; Revision 8Section 1R20 Refueling and Outage ActivitiesSOI-E12; Residual Heat Removal System; Revision 32VLI-E12; Residual Heat Removal System; Revision 07

CR 07-16617; RHR A Minimum Flow Valve 1E12F064A Undesired Stroke Closed During

SVI E12 T2001; dated March 21, 2007

CR 07-16972; RHR A/LPCS Waterleg Pump Shaft Seal Leak; dated March 27, 2007

NOP-OP-1001; Clearance and Tagging Program; Revision 08

PAP-1313; Control of Lifting Operations; Revision 06

GMI-0004; General Guidelines for Rigging; Revision 08

GMI-0185; Reactor Vessel Disassembly and Assembly; Revision 07

Attachment5NOP-LP-2601; Procedure Use and Adherence; Revision 00GAI Report Number 2329; Control of Heavy Loads Study - Perry Nuclear Power Plants Units 1 & 2; Revision 02

GAI Report Number 1918; Equipment Removal Scheme - Perry Nuclear Power Plants Units 1 & 2; Revision 01

CR 07-17736;

GMI-0185 Procedure Change; dated April 5, 2007

CR 07-18310; NRC Identified Issue - RPV Head Removal; dated April 13, 2007

General Electric Report; 1982; Structural Analysis Summary for Vessel Head, Shroud Head, and Steam Dryer Assembly Drop Consequences in Perry

BWR-6/238 Plants; dated March 9, 1982

PMI-0015; Reactor Polar Crane Preventative Maintenance; Revision 06

CR 07-21915; Recirc FCV A Velocity Feedback Not Functioning for Excess Velocity Trip; dated June 11, 2007

Reactivity Plan; Shutdown for Reactor Recirc Flow Control Valve Repair; dated June 20, 2007Perry Nuclear Power Plant Work Implementation Schedule; FCV "A" Repair Hot Shutdown Forced Outage; dated June 19, 2007

CR 07-22474; Rod Drift During Anticipatory Rod Stroking; dated June 23, 2007

CR 07-22452; SRM B Does Not Pass Channel Check; dated June 22, 2007

CR 07-21375;

PY-PA-07-02 Negative Trend for RFO11 Design Modifications; dated May 31, 2007Section 1R22 Surveillance TestingSVI-B21-T1176; RCS Heatup and Cooldown Surveillance; Revision 9CR 07-17349; RCS Cooldown Surveillance; dated April 2, 2007

SVI-P57-T20001; Safety-Related Instrument Air Motor-Operated Valve Operability Test;

Revision 05

PAP-1101; Inservice Testing of Pumps and Valves; Revision 07

TAI-1101-1; Inservice Testing of ASME Section XI Pumps

TAI-1101-2; Inservice Testing of ASME Section XI Valves; Revision 00

TAI-1101-3; Inservice Testing of ASME Section XI and Augmented Pressure Relief Devices;

Revision 04

SVI-R43T1318; Diesel Generator Start and Load Division 2; Revision 10

Tagout

PY-CYC-011; Clearance

PYR-E12-0030; dated April 25, 2007

SOI-E21; Low Pressure Core Spray System; Revision 21

SVI-E21-T2001; Low Pressure Core Spray Pump and Valve Operability Test; dated April 26, 2007

CR 07-19616; Diesel Generator Output Breaker Un-expected Response During the LOOP Test;

dated April 30, 2007

SVI-R43-T1338; Division 2 Standby Diesel Generator Loss of Offsite Power (LOOP) Test;

Revision 11

WO 200147369; Division 2 Standby Diesel Generator Loss Of Offsite Power; dated May 3,

2007

CR 07- 19955; Inboard MSIV D Fast Closure Time Was Slow; dated May 4, 2007

SVI-B21-T2001; MSIV Full Stroke Operability Test; Revision 10

ISTP; Pump and Valve Inservice Testing Program Plan; Revision 10

TAI-1101-2; Inservice Testing of ASME Section XI Valves; Revision 00Section 1EP6 Drill EvaluationController's Handbook, ERO Team 'B' Drill, dated June 14, 2007

2OS1Access Control to Radiologically Significant AreasCR 07-18150; Received Dose Alarm During Work on the 577' Turbine Building; datedApril 11, 2007

CR 07-17883; Incorrect Valve Worked Without Proper Planning; dated April 7, 2007

CR 06-03482; Contamination Events Due to Fuel Pool Cooling and Cleanup Deminelizer; dated August 02, 2006

CA 06-03482;

NOP-LP-2001-05:

Corrective Actions of the Contamination Events; dated August 4, 2006

CR 07-16012; Elevated Co-60 Activity in the Reactor Water; dated March 9, 2007

CR 07-15920; Radiation Protection Dose Received During 1E12 Scaffold Builds, dated March 8, 2007

CR 07-15992; Contamination Found in the RHR "A" Pump Room; dated March 3, 2007

CR 07-15780; Poor Housekeeping Practices On the Turbine Building Elevation 593'; dated March 8, 2007

HPI-C0013; Control of Radiography Operations; Revision 0; dated August 31, 2006

IOI-17; Drywell Entry and Access Control, In-Field Reference Procedure; Revision 07; datedMarch 20, 2007

HPI-B0003; Processing of Personnel Dosimetry, In-field Reference Procedure; Revision 17;

dated May 8, 2006

PAP-0123; Control of Locked High Radiation Areas; General Skill Reference; Revision 10;

dated October 27, 2006

NOPWM-7017; Contamination Control Program; Revision 0; dated November 30, 20052OS2ALARA Planning and ControlsALARA Work In Progress Review,

NOPWM-7002-07; Radiation Work Permit (RWP)07-6415-02; Grind Weld of Ten N2 Nozzles in Bioshield in Preparation for ISI Exams; dated April 11, 2007

ALARA Work In Progress Review,

NOPWM-7002-07,

RWP 07-6331-0; Snubber Activities-

High-Risk-During

RFO-11; dated April 11, 2007

ALARA Work In Progress Review,

NOPWM-7002-07,

RWP 07-0333; Upper Bioshield Annulus Insulation Removal/Reinstallation; dated April 3, 2007

RWP Number

076415; Location Drywell, Description Radiological Risk Bioshield AnnulusActivities Involving Nozzle Exams, Insulation, Shielding, ISI, and Scaffolding; dated April 6,

2007

RWP Number

076414;

RFO-1, Under Vessel Project and Support Activities-High Radiological Risks; dated March 16, 2007

NOP-WM-7002; Operational ALARA Program; Revision 0; dated November 30, 2005

HPI-C0012; Remote Monitoring; Revision 8; dated May 18, 2006

Perry Nuclear Power Plant Work Implementation Schedule for

RFO 11; Revision 0; dated April 10, 2007

RWP 076415; Radiological Survey Report No. 07-55148, Post Flush of Nozzles; dated April 9, 2007

ALARA Plan No. 07-6414-02; Under Vessel Activities High Radiological Risks,

RWP No. 07-6414-0; dated April 3, 2007

FENOC Shutdown Chemistry Program;

NOP-OP-3502; Revision 0; dated October 25, 2005

Perry Power Plant Water Management Plan; Revision Draft Perry Nuclear Power Plant Outage Radiological Report; dated April 11, 2007

FENOC Outage Control Center Shift Turnover Report; Challenges and Highlights; dated April 12, 2007

Attachment7Radiological Survey Reports; RWP No. 07-6321, Survey No.

0756164; Verify Dose Rates on360o Platform During Initial Spent Fuel Move at Elevation 690'; dated April 11, 2007NOP-CC-3002-01; Calculation No. 3.2.18, F-15 360 Degree Platform Dose Calculation; dated August 29, 2006

FENOC; Station ALARA Committee Members; Off-Normal ALARA Meeting Minutes; dated January 15, 2007

RFO-11 PWIS; Three Day Look Ahead Critical Path; dated April 1, 2007Section 4OA3 Event FollowupONI-S11; Hi/Low Voltage; Revision 4 and Revision 5PAP-0102; Interface With the Transmission System Operator; Revision 4

CR 07-20466, Unexpected Turbine Trip During Startup, dated May 13, 2007

CR 07-20527, Reactor Scram on Level 3, dated May 15, 2007

CR 07-20528, Automatic Reactor Scram Due to Reactor Level 3, dated May 15, 2007

CR 07-20550, Failure to Take Immediate Actions, dated May 15, 2007

CR 07-20576, Reactor Scram During Digital Feedwater Control System Testing Under TXI-373, dated May 15, 2007

CR 07-20585, Plant Restart and Testing and Oversight Plan, dated May 15, 2007

CR 07-20587, Organizational Issues Evaluation - Rx Scram During RFPT Digital Controls Tuning, dated May 15, 2007

CR 07-20588, Training Issues - Reactor Scram During RFPT Digital Controls Tuning, dated May 15, 2007

ONI-C34, Feedwater Flow Malfunction, Revision 6

Perry Post Scram Restart Report, Scram No 1-07-02

TXI-0373, Digital Feedwater Control Systems and Startup Test and Tuning, Revision 3

Operator Log Entry, May 21, 2007, 11:00 a.m.

CR 07-20046; Leaking 1B21 Flange Connection With Multiple Gaskets Installed; dated May 7, 2007

Control Room Logs; dated May 5-6, 2007

BETA Labs Report G202/07-22396; 1B33K115B Time Delay Relay; dated June 26, 2007

LIST OF ACRONYMS

USEDA ttachment8

ALARA as low as reasonably achievableASMEAmerican Society of Mechanical Engineers

CA [[]]

PC orrective Action Program

CFRC ode of Federal Regulations

CR condition report

DFWC [[]]

SDigital Feedwater Control System

EDGemergency diesel generator

EHC electrohydraulic control

FP [[]]

IF ire Protection Instruction

FSA [[]]

RF inal Safety Analysis Report

HP [[]]

CShigh pressure core spray

HRA high radiation area

IM [[]]

CInspection Manual Chapter

IRinspection report

ISI inservice inspection

LO [[]]

CA loss-of-coolant accident

LO [[]]

OP loss of offisite power

LP [[]]

CS low pressure core spray

LP [[]]

RMlow range power monitor

NCVnon-cited violation

NDE nondestructive examination

NR [[]]

CN uclear Regulatory Commission

ON [[]]

IO ff-Normal Instruction

PA [[]]

PPerry Administrative Procedure

PIperformance indicator

RA risk assessment

RC [[]]

ICreactor core isolation cooling

RFOrefueling outage

RFO 11Refueling Outage 11

RF [[]]

PTreactor feed pump turbine

RHRresidual heat removal

RPradiation protection

RPTradiation protection technician

RPVreactor pressure vessel

RWP radiation work permit

SD [[]]

PSignificance Determination Process

TST echnical Specification

USA [[]]

RU pdated Safety Analysis Report

VH [[]]

RA very high radiation area

VL [[]]

IValve Lineup Instruction

WO work order