IR 05000440/2002005

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IR 05000440-02-005, on 04/01/02 - 06/30/02, First Energy Nuclear Operating Co., Perry Nuclear Power Plant; Maintenance Risk Assessments and Emergent Work Evaluation, Surveillance Testing, Event Follow-Up
ML022110566
Person / Time
Site: Perry FirstEnergy icon.png
Issue date: 07/29/2002
From: Christine Lipa
NRC/RGN-III/DRP/RPB4
To: Kanda W
FirstEnergy Nuclear Operating Co
References
IR-02-005
Download: ML022110566 (33)
v • d • e


Text

uly 29, 2002

SUBJECT:

PERRY NUCLEAR POWER PLANT NRC INSPECTION REPORT 50-440/02-05

Dear Mr. Kanda:

On June 30, 2002, the NRC completed an inspection at your Perry Nuclear Power Plant. The enclosed report documents the inspection findings which were discussed on July 1, 2002, with you and other members of your staff.

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

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

Based on the results of this inspection, the inspectors identified three issues of very low safety significance (Green). Two of these issues were determined to involve violations of NRC requirements. However, because of their very low safety significance and because they were entered into your corrective action program, the NRC is treating these issues as Non-Cited Violations in accordance with Section VI.A.1 of the NRC s Enforcement Policy. If you deny these Non-Cited Violations, you should provide a response with a basis for your denial, within 30 days of the date of this inspection report, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Perry Nuclear Power Plant.

The NRC has increased security requirements at Perry in response to terrorist acts on September 11, 2001. Although the NRC is not aware of any specific threat against nuclear facilities, the NRC issued an Order and several threat advisories to commercial power reactors to strengthen licensees capabilities and readiness to respond to a potential attack. The NRC continues to monitor overall security controls and will issue temporary instructions in the near future to verify by inspection the licensee's compliance with the Order and current security regulations. In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter 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 NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/NRC/ADAMS/index.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Christine A. Lipa, Chief Branch 4 Division of Reactor Projects Docket No. 50-440 License No. NPF-58

Enclosure:

Inspection Report 50-440/02-05

REGION III==

Docket No: 50-440 License No: NPF-58 Report No: 50-440/02-05 Licensee: FirstEnergy Nuclear Operating Company (FENOC)

Facility: Perry Nuclear Power Plant, Unit 1 Location: P.O. Box 97 A200 Perry, OH 44081 Dates: April 1, 2002 through June 30, 2002 Inspectors: Ray Powell, Senior Resident Inspector Billy Dickson, Jr., Acting Senior Resident Inspector John Ellegood, Resident Inspector Robert Jickling, Emergency Preparedness Analyst John E. House, Senior Radiation Specialist James Belanger, Senior Physical Security Inspector Approved by: Christine A. Lipa, Chief Branch 4 Division of Reactor Projects

SUMMARY OF FINDINGS IR 05000440-02-05; on 04/01-06/30/2002; First Energy Nuclear Operating Company; Perry Nuclear Power Plant. Maintenance Risk Assessments and Emergent Work Evaluation, Surveillance Testing, Event Follow-Up.

This report covers a Quarterly Routine Inspection, an Occupational and Public Radiation Safety inspection, and a Physical Protection inspection. The inspections were conducted by resident inspectors and regional specialist inspectors. The inspection identified three Green findings, two of which were Non-Cited Violations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using IMC 0609, Significance Determination Process (SDP). The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described at its Reactor Oversight Process website at:

http://www.nrc.gov/NRR/OVERSIGHT/index.html. Findings for which the SDP does not apply are indicated by No Color or by the severity level of the applicable violations.

A. Inspector Identified Findings Cornerstone: Initiating Events Green. The inspectors identified a Non-Cited Violation of Technical Specification 5.4.1.a for failure to follow procedures while paralleling to the grid.

Licensee personnel failed to verify synchronization prior to closure of a main generator output breaker.

The finding was of very low safety significance because the event did not effect the likelihood of a loss of coolant accident, contribute to both a scram and loss of mitigation equipment, nor increase the likelihood of flooding or fire. (Section 4OA3.2).

Cornerstone: Mitigating Systems GREEN. The inspectors identified a licensee performance deficiency associated with the protection of Emergency Service Water B and C trains during a Division 1 (A train) outage. Although the B and C pumps were posted as protected equipment, the motor control centers were not.

The finding was of very low safety significance because, although the inspectors observed considerable work activities in the immediate vicinity of the motor control centers, the mitigation systems remained operable. (Section 1R13).

GREEN. A Non-Cited Violation of 10 CFR 50 Appendix B, Criterion XVI for failure to ensure conditions adverse to quality are corrected. The licensee failed to correct a previously identified procedure deficiency associated with test equipment used to test the level 3 and level 8 Reactor Protection System and Residual Heat Removal shutdown insolation functions. As a result, during the April 2002 performance of the 24-month surveillance, the licensee experienced a similar failure.

The finding was of very low safety significance because, although the procedure deficiency had an actual impact causing the loss of one channel of level protective functions for several hours, no actual loss of safety function occurred. (Section 1R22).

B. Licensee Identified Violations No findings of significance were identified.

Report Details Summary of Plant Status: The plant began the inspection period with Unit 1 at 100 percent power. The unit remained at 100 percent power with periodic power reductions for rod line changes until June 1, 2002, when the licensee began reducing power due to a generator exciter ground. Due to the exciter ground, the unit entered mode 4 on June 4. After replacing the exciter, the unit reached criticality on June 12 and synchronized to the grid on June 13.

Because the operators paralleled out of phase, the plant slowly ascended in power while monitoring key generator parameters. On June 18, the plant achieved 100 percent power and, except for scheduled power reductions for rod lines changes, remained at 100 percent for the remainder of the inspection period.

1. REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity 1R01 Adverse Weather (71111.01)

a. Inspection Scope The inspectors reviewed licensee Off-Normal Instruction (ONI) ZZZ-1, Tornado or High Winds, and discussed severe weather preparations and response with operations personnel. The inspectors also reviewed the licensees response to the tornado watch posted on May 9, 2002. The inspectors verified that the ONI was entered, that immediate actions were performed, and that site supervision was appropriately notified as required by the procedure. Finally, the inspectors walked down a sample of credited tornado depressurization barriers to review position and material condition.

b. Findings No finding of significance were identified.

1R04 Equipment Alignment (71111.04)

.1 Complete System Walkdown a. Inspection Scope The inspectors performed a complete walkdown of accessible portions of the Standby Liquid Control (SLC) system to verify system operability. The SLC system was selected due to its high risk significance. The inspectors used SLC system valve lineup instructions (VLIs) and system drawings to accomplish the inspection.

The inspectors observed selected switch and valve position, electrical power availability, component labeling, and general material condition. The inspectors also reviewed open system engineering issues as identified in the licensees quarterly system health reports, outstanding maintenance work requests, and a sampling of licensee condition reports to

verify that problems and issues were identified, and corrected, at an appropriate threshold. The documents used for the walkdown and issue review are listed in the attached List of Documents Reviewed.

b. Findings No findings of significance were identified.

.2 Partial System Walkdowns a. Inspection Scope The inspectors conducted a partial walkdown of:

  • The HPCS system prior to and during mode changes associated with the Unit startup on June 12, 2002.

The inspectors used licensee VLIs and system drawings during the walkdowns. The walkdowns 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 walkdowns are listed in the attached List of Documents Reviewed.

b. Findings No findings of significance were identified.

1R05 Fire Protection (71111.05Q)

a. Inspection Scope The inspectors walked down the following areas to assess the overall readiness of fire protection equipment and barriers:

  • Fire Areas CC-1a and CC-1b, Emergency Closed Cooling Pumps and Heat Exchangers
  • Fire Area 1CC-3c, Division 1 Switchgear Room
  • Fire Area IB-1, Intermediate Building 574'
  • Fire Area 1DG-1a, Division 2 Diesel Generator
  • Fire Area 1AB-3a, Auxilary Building, 620' East
  • Fire Area 1AB-2a, Auxiliary Building, 599' East Emphasis was placed on the control of transient combustibles and 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 looked at fire hoses, sprinklers, and portable fire extinguishers to verify that 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 verify that they were in good physical condition. The documents listed at the end of the report were used by the inspectors during the assessment of this area.

b. Findings No findings of significance were identified.

1R06 Flood Protection (71111.06)

a. Inspection Scope The inspectors reviewed licensee documentation containing design flood levels for areas containing safety equipment to assess whether flooding mitigation plans and equipment were consistent with the design analysis and risk analysis assumptions.

Specifically, the inspectors reviewed:

  • flood zone 13, control complex elevation 576'10"
  • plant underdrain system The inspectors also assessed the adequacy of the plants underdrain system to meet design requirements of the Updated Safety Analysis Report (USAR). Additional inspection activities included reviews of appropriate design documentation, condition reports, safety analysis, and walkdowns of the underdrain system, flood zone 13, and areas susceptible to flooding. The documents at the end of this report were used by the inspectors during assessment of this area.

b. Findings No findings of significance were identified.

1R11 Licensed Operator Requalification (71111.11)

a. Inspection Scope On April 16, 2002, the resident inspectors observed licensed operator performance in the plant simulator. The evaluated scenario included a leak in underground ESW piping, a seismic event, and a failure to scram.

The inspectors evaluated crew performance for clarity and formality of communication; the ability to take timely action in the safe direction; the prioritizing, interpreting, and verifying of alarms; the correct use and implementation of procedures, including alarm response procedures; timely control board operation and manipulation, including high-risk operator actions; and group dynamics. The inspectors also observed the licensees evaluation of crew performance to verify that the training staff had observed important performance deficiencies and specified appropriate remedial actions.

b. Findings No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation (71111.13)

a. Inspection Scope The inspectors reviewed the licensees evaluation of plant risk, scheduling, configuration control, and performance of maintenance associated with planned and emergent work activities, to verify that scheduled and emergent work activities were adequately managed. In particular, the inspectors reviewed the licensees program for conducting maintenance risk assessments to verify that the licensees planning, risk management tools, and the assessment and management of on-line risk were adequate. The inspectors also reviewed licensee actions to address increased on-line risk when equipment was out-of-service for maintenance, such as establishing compensatory actions, minimizing the duration of the activity, obtaining appropriate management approval, and informing appropriate plant staff, to verify that the actions were accomplished when on-line risk was increased due to maintenance on risk-significant structures, systems, and components. The following specific activities were reviewed:

  • The revised maintenance risk assessment for work planned for the week beginning April 8, 2002. The inspectors verified that the risk profile was appropriately revised due to emergent work associated with the Division 2 DG lube oil pump that resulted in Division 2 DG unavailability.
  • The maintenance risk assessment for work planned for the week beginning April 15, 2002. The work week included a planned HPCS system outage.
  • The maintenance risk assessment for work planned for the week beginning April 29, 2002. The work week included a planned diesel fire pump inoperabilty due to electrical bus maintenance and planned maintenance on the B train of ESW pumphouse ventilation.
  • The revised maintenance risk assessment for work planned for the week beginning April 29, 2002. The inspectors verified that the risk profile was appropriately revised due to emergent work associated with the RCIC turbine oil leak that resulted in RCIC system unavailability.
  • The maintenance risk assessment for the planned Division 1 outage which included work on the A ESW train, the Division 1 DG, the A RHR Train, and the LPCS.
  • The maintenance risk assessment for work involving the feedwater seal water injection pump.

b. Findings GREEN. The inspectors identified a licensee performance deficiency associated with the protection of ESW B and C trains during a Division 1 (A train) outage. Although the B and C pumps were posted as protected equipment, the respective motor control centers (MCCs) were not.

On May 20, 2002, the licensee commenced a planned Division 1 outage which included work on the A ESW train, the Division 1 DG, the A RHR Train, and the LPCS system.

Commensurate with the increased risk profile, the licensee established restricted access areas which included the B and C ESW trains. On May 20, the inspectors conducted a walkdown of the identified restricted areas to determine whether they were appropriately posted and controlled.

Upon entering the ESW pumphouse the inspectors observed a high amount of activity involving planned forebay diving activities. The inspectors proceeded to the ESW B and C train pump areas and noted the areas were roped off with the licensees red protected equipment signs posted at all points of entry. The MCCs located on the north side of the pumphouse were not, however, similarly posted. The inspectors observed caution tape attached to the front of the MCCs. The inspectors also observed numerous activities supporting the diving operations occurring in the immediate vicinity of the MCCs.

The inspectors discussed their observations with the on-duty Shift Manager and the on-coming Shift Manager. Both Shift Managers were aware of the caution tape usage and the diving operations. In fact, prior to entering the pumphouse, the inspectors had been advised by the Shift Manager to exercise extra caution due to the large volume of diving equipment (hoses, tanks, suits, etc.) and activity in the area.

The inspectors conveyed three specific concerns to licensee management. First, the use of caution tape, with no amplifying instructions/signs to designate protected equipment, was not consistent with the licensees Industrial Safety Manual which

described yellow caution tape as appropriate for marking physical hazards such as tripping, stumbling, and falling nor was it consistent with the licensees established practice for posting protected equipment. Second, the inspectors noted there was no standoff area established between the caution tape and the MCCs. In addition to being a poor practice, the condition was contrary to guidance in the Industrial Safety Manual which stated in part when posting an area with barrier rope or tape, the barriers should be no closer to the hazard than six feet unless this is physically impossible or creates an additional hazard. The inspectors did not identify any condition, other than the diving activities, which would have prevented establishing the suggested six foot standoff area.

Finally, the inspectors noted that there was no procedure in place that governed protection of equipment that increased in risk significance due to planned unavailability of opposite train safety equipment.

The performance deficiency associated with this event was failure to adequately post and restrict potential access, intended or inadvertent, to protected train equipment. The finding was greater than minor because the licensees practice was considered to be a precursor to a significant event such as inadvertently rendering multiple trains of mitigating systems inoperable. The finding was of very low safety significance because although the inspectors observed considerable work activities in the immediate vicinity of the ESW B and C MCCs, the mitigation systems remained operable. In accordance with NRCs Enforcement Policy, the issue is not a violation of NRC requirements since potential procedure noncompliances were associated with the Industrial Safety Manual, rather than a Technical Specification (TS) or 10 CFR Appendix B required procedure.

The licensee initiated Condition Report 02-1555 to document the inspectors findings and corrected the conditions (FIN 50-440/02-05-01).

1R14 Personnel Performance During Nonroutine Plant Evolutions (71111.14)

a. Inspection Scope The inspectors reviewed licensee performance during aborted startup testing of the hydrogen water chemistry system. The inspectors observed crew briefs, observed testing, reviewed test results, and reviewed licensee response to equipment challenges.

Finally, the inspectors reviewed licensee radiological control practices relative to the potentially changing radiological conditions due to hydrogen injection.

b. Findings No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope The inspectors selected Condition Reports (CRs) related to potential operability issues for risk significant components and systems. These CRs were evaluated to determine whether the operability of the components and systems was justified. The inspectors

compared the operability and design criteria in the appropriate sections of the TSs and USAR to the licensees evaluations to verify that the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors verified that the measures were in place, would work as intended, and were properly controlled. Additionally, the inspectors verified, where appropriate, compliance with bounding limitations associated with the evaluations. The inspectors reviewed:

  • the licensees evaluation of the potential spurious opening of the ESW sluice gates due to a fire resulting in a hot short
  • the licensees evaluation of the impact of identified leaks in the RCIC turbine oil system on RCIC system operability
  • the licensees evaluation of the potential inadequate engagement of the RCIC system trip throttle valve following a trip of the RCIC system
  • the licensees evaluation of the impact of the feedwater venturi water leakage on a junction box in the RCIC pump room
  • the licensees evaluation of low ESW flow to the HPCS room cooler b. Findings No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19)

a. Inspection Scope The inspectors evaluated the following post-maintenance testing activities for risk significant systems to assess the following (as applicable): the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written; and equipment was returned to its operational status following testing. The inspectors evaluated the activities against TS, the USAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications. In addition, the inspectors reviewed CRs associated with post-maintenance testing to determine if the licensee was identifying problems and entering them in the corrective action program. The specific procedures and CRs reviewed are listed in the attached List of Documents Reviewed. The following post-maintenance activities were reviewed:

  • RCIC following trouble shoot and repair of flow controller
  • RCIC following water leg pump repair
  • DG 1 day tank level instrumention replacement
  • Main Condenser/Feedwater Heater Drain Line b. Findings No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope The inspectors observed surveillance testing or reviewed test data for risk-significant systems or components to assess compliance with TS, 10 CFR Part 50 Appendix B, and licensee procedure requirements. The testing was also evaluated for consistency with the USAR. The inspectors verified that the testing demonstrated that the systems were ready to perform their intended safety functions. The inspectors reviewed whether test control was properly coordinated with the control room and performed in the sequence specified in the surveillance instruction (SVI), and if test equipment was properly calibrated and installed to support the surveillance tests. The procedures reviewed are listed in the attached List of Documents Reviewed. The specific surveillance activities assessed included:

  • HPCS Logic System Functional Test
  • Average Power Range Monitor F Flow Channel Calibration
  • LPCS Quarterly Surveillance Test

On April 8, 2002, the licensee used a piece of test equipment that was not adequate to properly surveil the level 3 and level 8 RPS and RHR shutdown insolation functions.

On the previous performance of this 24-month surveillance, the licensee experienced a similar failure and concluded that the test equipment used was not adequate. However, the governing procedure was not revised and the error recurred.

Licensee procedure SVI-B21-T0035-D, Reactor Pressure Vessel (RPV) Low Level 3 and High Level 8 RPS and RHR Shutdown Isolation Channel D Calibration for 1B21-N680D, calibrated the RPV level 3 and Level 8 instruments to satisfy Surveillance Requirements 3.3.1.1.13 and 3.3.6.1.4 with a 24-month frequency. The procedure specified use of two Transmation 1040 or equivalent test devices. However, plant experience demonstrated that the Transmation 1040 lacked sufficient power to effectively test the system. The licensee determined that a Fluke 702 had adequate power and must be used for certain steps of the surveillance. The Transmation 1040 was still required on other steps since the Fluke 702 did not have a high enough current output. The inspectors determined that this procedure deficiency had not been entered into the licensees corrective action program. Instead, the licensee used a memo to technicians to communicate the proper equipment to use and gave the procedure revision a low priority since it permitted the use of the Fluke 702.

On April 8, 2002, while performing the procedure with the Transmation 1040, the licensee observed anomalous results from the SVI and failed the surveillance. The licensee replaced the Trip Unit but the retest failed. Eventually, licensee personnel recalled the past problems with use of test equipment, reinstalled the old trip unit and successfully completed the surveillance using appropriate test equipment. This resulted in the inoperablity of the affected channel for about 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />.

The performance deficiency associated with this event was the failure to assure conditions adverse to quality are properly identified and corrected. The finding was greater than minor because it had an actual impact causing the loss of one channel of level protective functions for several hours. In addition, the same problem existed in over 30 other procedures although this was the only instance where the improper test equipment was used. Further evaluation under the Significance Determination Process (SDP) categorized the finding as Green because no actual loss of safety function occurred.

This finding is a violation of 10 CFR 50 appendix B Criterion XVI which states, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformance are promptly identified and corrected. Contrary to this requirement, no condition report was initiated for the prior surveillance failure nor were procedures revised to specify the proper test equipment. The licensee entered the most recent failure into the corrective action program (CR 02-01037) and is in the process of correcting the affected procedures. Because of the very low safety significance and because the issue has been entered into the licensees corrective action program, it is being treated as a Non-Cited Violation, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 50-440/02-05-02).

Cornerstone: Emergency Preparedness 1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)

a. Inspection Scope The inspectors reviewed Revision 15 of the Perry Nuclear Power Plant Emergency Plan to determine whether changes identified in Revision 15, Temporary Change No. C-2, reduced the effectiveness of the licensees emergency planning, pending onsite inspection of the implementation of these changes.

b. Findings No findings of significance were identified.

1EP6 Drill Evaluation (71114.06)

a. Inspection Scope The inspectors observed the technical support center and the operations support center during an emergency preparedness drill conducted on May 15, 2002. The inspection focused on the ability of the licensee to appropriately classify emergency conditions, complete timely notifications, and implement appropriate protective action recommendations in accordance with approved procedures. Additionally, the inspectors observed controller training developed to improve controller performance during drill simulations.

b. Findings No findings of significance were identified.

2. RADIATION SAFETY Cornerstone: Occupational Radiation Safety (OS)

2OS1 Access Control to Radiologically Significant Areas (71121.01)

.1 Job In-Progress Reviews a. Inspection Scope The inspector observed aspects of work activities having significant dose potential, that were being performed in the Radwaste Building, in order to ensure that adequate radiological controls were assigned and implemented. The inspectors observed radiation protection preparations and radiological controls for the placement of a high integrity container into a shipping cask. The inspectors observed engineering controls, radiological postings, radiological boundary controls, and radiation monitoring locations to verify that radiological controls were effective in minimizing dose. The inspectors also observed radiation worker performance to verify that the workers were complying with radiological requirements and were demonstrating adequate radiological work practices.

b. Findings No findings of significance were identified.

Cornerstone: Public Radiation Safety (PS)

2PS3 Radiological Environmental Monitoring and Radioactive Material Control Programs (71122.03)

.1 Review of Environmental Monitoring Reports and Data a. Inspection Scope The inspector reviewed the licensees Radiological Environmental Monitoring Program (REMP) in order to verify that this program was implemented as required by the Offsite Dose Calculation Manual (ODCM) and associated TSs, and that changes, if any, did not affect the licensees ability to monitor the impacts of radioactive effluent releases on the environment. The Annual Radiological Environmental Monitoring Reports for the years 2000 and 2001 were reviewed including sampling location commitments, monitoring and measurement frequencies, land use census, the vendor laboratorys Interlaboratory Comparison Program, and data analysis. Anomalous results including data, missed samples, and inoperable or lost equipment were evaluated. The most recent quality assessment of the licensees REMP vendor laboratory for environmental sample analyses was evaluated to verify that the vendor laboratory performance was consistent with licensee and NRC requirements.

b. Findings No findings of significance were identified.

.2 Walkdowns Of Radiological Environmental Monitoring Stations and Meteorological Tower a. Inspection Scope The inspector conducted a walkdown of the seven environmental air sampling stations and selected thermoluminescent dosimeters to verify that their locations were consistent with their descriptions in the ODCM, and to evaluate the equipment material condition.

The meteorological monitoring site was observed to validate that sensors were adequately positioned and operable. The inspectors reviewed meteorological instrument calibration documentation for the onsite meteorological monitoring program, including data recovery, routine calibration, and maintenance activities to verify that the meteorological instrumentation was operable, calibrated, and maintained in accordance with licensee procedures. The inspectors also verified that readouts of wind speed, wind direction, and atmospheric stability measurements were available on the licensees computer system which was available in the Control Room, and that the system was operable.

b. Findings No findings of significance were identified.

.3 Review of REMP Sample Collection and Analysis a. Inspection Scope The inspector accompanied a licensee REMP technician to observe the collection and preparation of environmental samples including surface water, air filters (particulate) and charcoal cartridges (iodine) to verify that representative samples were being collected in accordance with procedures and the ODCM. The inspectors observed the technician perform air sampler field check maintenance to verify that the air samplers were functioning in accordance with procedures. Selected air sampler calibration and maintenance records for 2002 were reviewed to verify that the equipment was being maintained as required. The environmental sample collection program was compared with the ODCM to verify that samples were representative of the licensees release pathways. Additionally, The inspectors reviewed results of the vendor laboratorys Interlaboratory Comparison Program to verify that the vendor was capable of making adequate radio-chemical measurements.

b. Findings No findings of significance were identified.

.4 Unrestricted Release of Material From the Radiologically Restricted Area a. Inspection Scope The inspector evaluated the licensees controls, procedure, and practices for the unrestricted release of material from radiologically restricted areas and verified that:

(1) radiation monitoring instrumentation used to perform surveys for unrestricted release of materials was appropriate; (2) instrument sensitivities were consistent with NRC guidance contained in Inspection and Enforcement (IE) Circular 81-07 and Health Physics Positions in NUREG/CR-5569 for both surface contaminated and volumetrically contaminated materials; (3) criteria for survey and release conformed to NRC requirements; (4) licensee procedures were technically sound and provided clear guidance for survey methodologies; and (5) radiation protection staff adequately implemented station procedures.

The inspector reviewed the quality control records for radiochemistry instrumentation used to identify and quantitate radioisotopes in materials for free release, in order to verify that the instrumentation was calibrated and maintained as required by site procedures. This review included instrument calibrations, control charts, and the environmental lower limit of detection capability.

b. Findings No findings of significance were identified.

.5 Identification and Resolution of Problems a. Inspection Scope The inspector reviewed condition reports, the results of a Nuclear Quality Assessment Audit of the REMP, and a benchmark evaluation of the licensees vendor laboratory to determine if problems were being identified and entered into the corrective action program for timely resolution. These documents were also reviewed to verify that the licensees audit program met the requirements of 10 CFR 20.1101(c) and that the audit results demonstrated that the REMP was implemented as required by the ODCM and associated TSs. The inspectors also reviewed the licensees overall management of the REMP, including attention to details of the sampling program and the vendor laboratory, in order to evaluate the effectiveness of the REMP in collection and analysis of samples for the detection of offsite radiological contamination.

b. Findings No findings of significance were identified.

3. SAFEGUARDS Cornerstone: Physical Protection 3PP3 Response to Contingency Events (71130.03)

a. Inspection Scope The inspectors reviewed the licensees current protective strategy which included designated targets and target sets, their associated analysis, and security and operation response procedures. The inspectors also reviewed security event reports, and portions of the licensees problem identification and resolution program to determine that issues related to the licensees contingent event program were identified at the appropriate threshold and were entered into the licensees corrective action program. Items reviewed included self-assessments, audits, and a sample of training records, force on force drill evaluations, and the licensees procedure for their corrective action process.

In addition, the inspectors conducted interviews with security officers and security management to evaluate their knowledge and use of the licensees corrective action system.

The inspectors reviewed appropriate security records and procedures that were related to security drills, drill demonstrations, and drill critiques to verify the licensees continuing capabilities to identify issues that represented uncorrected performance weaknesses or program vulnerabilities.

The inspectors reviewed records and interviewed five selected members of the uniformed security force to evaluate and verify security training that related to alarm station operations, tactical force-on-force training, and weapon proficiency training.

The inspectors also reviewed performance indicator information related to alarm equipment performance to determine if isolated or system problems with the protected area intrusion alarm system and/or assessment system had become predictable and potentially exploitable by an adversary.

b. Findings No findings of significance were identified.

4. OTHER ACTIVITIES (OA)

4OA1 Performance Indicator (PI) Verification (71151)

a. Inspection Scope The inspectors reviewed reported first quarter 2002 data for the Emergency AC Power System Unavailability, Functional Failures, and Reactor Coolant System Leakage PIs using the definitions and guidance contained in Nuclear Energy Institute 99-02, Regulatory Assessment Indicator Guideline, Revision 2. The inspectors reviewed station logs, event notification reports, licensee event reports, condition reports, and TS logs to verify the accuracy of the licensees data submission.

b. Findings No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152)

a. Inspection Scope Due to an observed decline in licensee human performance, potentially affecting multiple cornerstones, the inspectors reviewed human performance related CRs to verify that corrective actions commensurate with the issues were identified and implemented in a timely manner, including corrective actions to address common cause or generic concerns.

b. Findings No findings of significance were identified.

4OA3 Event Followup (71153)

.1 Ground on the Turbine Generator Exciter a. Inspection Scope On June 2, the inspectors responded to the site to observe operator actions and plant conditions following receipt of a ground on the Turbine Generator Exciter. The fault

occurred late on June 1 and required a reduction of plant power and eventual shutdown of the plant to mode 4 to effect repairs on the exciter. The inspectors followed up on the event by observing licensee activities to troubleshoot the ground, and operate the reactor. Response included review of logs and technical documentation as well as interviews with licensee personnel.

b. Findings No findings of significance were identified.

.2 Improper Synchronization to the Power Grid a. Inspection Scope Inspectors performed follow up activities after the licensee paralleled the main generator out of phase to the grid. Following replacement of the Turbine Generators exciter, the licensee brought the reactor critical and raised power in preparation for synchronizing to the grid. The licensee properly synchronized and closed one generator output breaker; however, the breaker immediately tripped open. Unaware that this occurred, the operators closed the other output breaker without verifying synchronization. The inspectors reviewed logs, printouts and other documents as well as interviewed plant employees.

b. Findings Green. The inspectors identified a Non-Cited Violation of TS 5.4.1.a for failure to follow procedures while paralleling to the grid.

On June 13, 2002, at approximately 5:56 a.m., with reactor power at 20 percent, Perry Nuclear Power Plant synchronized to the grid using the S-611 main generator output breaker. Integrated Operating Instruction (IOI) 3, Power Changes, the procedure in effect for this evolution, required the operator to verify synchronization and close breaker S-610. Contrary to this requirement, synchronization was not verified prior to closure of the S-610 breaker. Immediately after the operator closed the S-610 breaker, numerous alarms sounded, including main transformer 345 KV neutral-ground over current relay 50-51, main generator A phase over current, and the oscillograph startup alarm. The operator then noted that the S-611 breaker had tripped and informed the Unit Supervisor. The licensee halted all power ascension activities.

A licensee investigation into this event revealed that the S-611 breaker tripped approximately 2 seconds after it was closed and 15 seconds before the S-610 breaker was closed. During the 15 seconds the generator was not connected to the grid, the turbine became out of phase with the grid. The licensee and General Electric (GE) both completed independent calculations of the amount the generator was out of phase when the breaker closed and determined the phase angle to be 70 degrees and 50 degrees respectively. The licensee informed the inspectors that GE would prescribe an inspection of turbine components if the generator had been 120 degrees or more out of phase. If 30 degrees or less out of phase, the generator would not be damaged and no

action would be required. Since the phase angle was between those values, GE recommended additional monitoring during power increase. The licensee accepted the GE recommendations and monitored for:

  • abnormal temperature readings at various generator locations
  • broken ties, cracked epoxy, cracked paint, cracked piping, loose bars and blocks Under normal conditions, once one of the output breakers was closed there would be no phase difference across the other output breaker. The operator would need to position the synchroscope selector switch to the proper breaker to satisfy an interlock, but no generator adjustments would be needed to close the breaker. However, procedurally the operator was required to verify synchronization across the breaker to guard against out of phase synchronization.

The performance deficiency associated with this event was the failure to follow procedures. Technical Specification 5.4.1.a required written procedures to be implemented covering applicable procedures recommended by Regulatory Guide 1.33.

Regulatory Guide 1.33 recommended procedures for Synchronization of the Generator.

The procedure for this synchronization, IOI 3, required verification of synchronization prior to closure of generator output breakers and this verification was not accomplished.

The finding was greater than minor because it had an actual impact of closing a turbine generator output breaker out of phase with the grid. This condition could reasonably be viewed as a precursor to a significant event because had the breaker been closed further out of phase, the resulting transient could have severely damaged plant equipment as well as caused actuation of fault protection for onsite equipment. In addition, the finding directly affected the Initiating Events cornerstone objective to limit the likelihood of those events that upset plant stability. Since the event does not effect the likelihood of a loss of coolant accident, contribute to both a scram and loss of mitigation equipment, nor increase the likelihood of flooding or fire, a phase 1 review in accordance with Chapter 0609 of the NRC inspection manual yields a Green result.

This finding is a violation of T.S. 5.4.1.a. The Licensee has entered this condition into their corrective action program (CR 02-01886) and is investigating the root cause of the event. Because of the very low safety significance and because the issue has been entered into the licensees corrective action program, it is being treated as a Non-Cited Violation, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 50-440/02-05-03).

.3 (Closed) Licensee Event Report (LER) 50-440/2001-005-01: Automatic RPV Level SCRAM, Specified System Actuations And Inoperability of the Division 3 Diesel Generator. On December 15, 2001, the plant experienced a reactor scram due to failure of a logic card in the feed control system. During system restoration, the licensee

improperly secured the HPCS diesel generator which resulted in failure of its next surveillance. Findings associated with this event are documented in IR 50-440/2001-015.The inspectors reviewed the LER. No inaccuracies or new issues were identified.

4OA6 Meetings

.1 Interim Exit Meetings Senior Official at Exit: W. Kanda, Plant Manager Date: June 6, 2002 Proprietary: No Subject: Baseline Security Inspection Change to Inspection Findings: No Senior Official at Exit: Mr. K. Ostrowski, Director, Nuclear Services Date: May 23, 2002 Proprietary: No Subject: Access Control Program, Radiological Environmental Monitoring and Radioactive Material Control Programs Change to Inspection Findings: No

.2 Exit Meeting The inspectors presented the inspection results to Mr. William Kanda, Site Vice President and other members of licensee management at the conclusion of the inspection on July 1, 2002. The licensee acknowledged the findings presented. No proprietary information was identified.

KEY POINTS OF CONTACT Licensee W. Kanda, Vice President-Nuclear B. Boles, Operations Manager G. Dunn, Manager, Regulatory Affairs D. Gudger, Supervisor, Compliance T. Lentz, Acting Director Nuclear Engineering K. Ostrowski, Director, Nuclear Maintenance D. Phillips, Manager, Plant Engineering T. Rausch, General Manager, Nuclear Power Plant Department R. Strohl, Superintendent, Plant Operations R. Coad, Radiation Protection Manager R. Hayes, Chemistry Manager B. Luthanen, Compliance Engineer T. Mahon, Site Protection Section Manager L. Lindrose, Supervisor Nuclear Security Operations S. Sovizal, Supervisor, Security Training J. Palinkas, Supervisor, Security Systems and Administration LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-440/02-05-01 FIN Inadequate Posting of Protected Equipment During Risk Significant Maintenance Activities 50-440/02-05-02 NCV Failure to Correct Procedure Deficiency Involving Surveillance Test Equipment 50-440/02-05-03 NCV Failure to Follow Procedures While Paralleling to the Grid Closed 50-440/2001-005- LER Automatic RPV Level SCRAM, Specified System Actuations And 01 Inoperability Of the Division 3 Diesel Generator 50-440/02-05-01 FIN Inadequate Posting of Protected Equipment During Risk Significant Maintenance Activities 50-440/02-05-02 NCV Failure to Correct Procedure Deficiency Involving Surveillance Test Equipment 50-440/02-05-03 NCV Failure to Follow Procedures While Paralleling to the Grid

LIST OF ACRONYMS USED CFR Code of Federal Regulations CR Condition Report DG Diesel Generator ESW Emergency Service Water FENOC FirstEnergy Nuclear Operating Company GE General Electric HPCS High Pressure Core Spray LER Licensee Event Report LOCA Loss of Coolant Accident LPCS Low Pressure Core Spray NCV Non-Cited Violation NRC Nuclear Regulatory Commission MCCs Motor Control Centers ODCM Offsite Dose Calculation Manual ONI Off-Normal Instruction PI Performance Indicator RCIC Reactor Core Isolation Cooling REMP Radiological Environmental Monitoring Program RHS Residual Heat Removal RPS Reactor Protection System RPV Reactor Pressure Vessel SDP Significance Determination Process SLC Standby Liquid Control SVI Surveillance Instruction TS Technical Specifications URI Unresolved Item USAR Updated Safety Analysis Report VLI Valve Lineup Instruction

LIST OF DOCUMENTS REVIEWED 1R01 Adverse Weather Drawing Series Control Complex Architectural D105 PAP 0911 Control Room Boundary Integrity and Tornado January 4, 1996 Depressurization Barrier Impairment , Rev. 0 Calculation Tornado Venting of the Control Complex November 2, 2000 1:05.15 ONI-ZZZ-1 Tornado or High Winds, Rev. 2 June 30, 1995 1R04 Equipment Alignment Drawing 302-0691 Standby Liquid Control System Drawing 302-0692 Standby Liquid Control Transfer System VLI-C41 Standby Liquid Control System (Unit 1), Rev. 5 March 14, 1989 System Health Standby Liquid Control System Status Report 4th Quarter 2001 Report Drawing Change Installation of Pressure Gage at Vent Valve June 29, 1995 Notice 4987 1C41F0546 and Placement of Vent Valve 1C41F0547 in Throttled Position CR 01-0450 Failure to Identify Unavailability of SLC Train B February 8, 2001 CR 01-0690 1C41F0029B As-Found Test Failure High February 21, 2001 CR 01-0691 1C41F0029A As-Found Test Failure Low February 21, 2001 CR 01-1250 SLC Concentration March 9, 2001 CR 01-1918 Storage of Boric Acid & Borax 620 IB Not In April 23, 2001 Accordance with FCR 022606 SOI-P45/49 Emergency Service Water and Screen Wash September 19, Systems, Rev. 2 1995 VLI-P45 Emergency Service Water System, Rev. 4 August 22, 1989 Drawing Emergency Service Water System July 25, 2001 D-302-791 Drawing Emergency Service Water System April 17, 2000 D-302-792 SOI-P42 Emergency Closed Cooling System, Rev. 7 March 16, 1996 VLI-P42 Emergency Closed Cooling System, Rev. 6 September 29, 1995 Drawing Emergency Closed Cooling System March 12, 2002 D-302-621

Drawing Emergency Closed Cooling System April 17, 2000 D-302-622 VLI-E51 Reactor Core Isolation Cooling System (Unit 1), September 27, Rev. 3 1988 1R05 Fire Protection Drawing E-023- Fire Protection Evaluation - Units 1 and 2 Control September, 2001 006 Complex Plan - El. 574-10" Drawing E-023- Fire Protection Evaluation - Unit 1 Auxiliary and September, 2001 002 Reactor Buildings Plan - El. 574-10" Drawing E-023- Fire Protection Evaluation - Units 1 and 2 Control September, 2001 011 Complex and Diesel Generator Building Plan - El.

620-6" Drawing E-023- Fire Protection Evaluation- Units 1 and 2 May 1995 003 Intermediate Buildings Plan El. 574-10" Drawing E-023-10 Fire Protection Evaluation- Unit 1 Auxiliary and September, 2001 Reactor Building Plan El. 620-6" USAR Section Fire Area 1CC-3c 9A.4.4.3.1.3 USAR Section Fire Zone CC-1a 9A.4.4.1.1 USAR Section Fire Zone CC-1b 9A.4.4.1.2 USAR Section Fire Zone 1AB-1c 9A.4.2.1.3 USAR Section Fire Area 1DG-1a 9A.4.5.1.1 USAR Fire Zone 1AB-3a 9A.4.2.1.9.1 USAR Section Fire Zone IB-1 9A4.3.1.1 1R06 Flood Protection Measures PTI-P72-P0001 Plant Underdrain Continuity test November 7, 1994 PTI-P72-P0002 Plant Underdrain Groundwater Inflow Test June 8, 1995 PTI-P72-P0005 Plant Underdrain Groundwater Level Readings October 12, 1998 CR 02-01892 PTI-P72-P0002 Not performed by late date due June 13, 2002 to ECP 01-5033

CR 02-00250 Plant Underdrain Temp Mod 1-02-001 50.59 not January 23, 2002 conservative Calculation IF-6 Flood Zone 13, Critical Volume and Flood Rates December 20, 1991 USAR 2.4 Hydrologic Engineering 1R11 Licensed Operator Requalification ONI D51 Earthquake, Rev. 5 June 26, 2001 ONI C71-1 Reactor Scram, Rev. 3 May 21, 2001 ONI ZZZ-6 Leak in Underground Piping, Rev. 1 June 21, 2001 PEI-B13 Reactor Pressure Vessel Control, Rev. 4 August 19, 1994 1R13 Maintenance Risk Assessments and Emergent Work Evaluation Week 8, Period 5 Forecast Risk Profile April 8, 2002 Week 9, Period 5 Forecast Risk Profile April 15, 2002 Week 11, Period 5 Forecast Risk Profile April 29, 2002 Week 1, Period 6 Forecast Risk Profile May 13, 2002 OAI-1701 Tracking of LCOs, Rev. 2 December 5, 2000 PAP 1924 On-Line Safety Assessment and Configuration November 30, 2000 Risk Management, Rev. 2 1R15 Operability Evaluations CR 02-00985 Latent Issues, Sluice Gates Do Not Have Hot April 2, 2002 Short Mod CR 02-01196 Excessive Oil Leakage From the RCIC Turbine April 21, 2002 1R19 Post-Maintenance Testing SVI-E51-T2001 RCIC Pump and Valve Operability Test May 5 2002 WO-02-4999 RCIC Turbine May 5, 2002 SVI-E51-T2003 RCIC Water Leg Pump and Associated Valves March 28, 2002 Cold Start SVI-E51-T2001 RCIC Pump and Valve Operability Test March 29, 2002 SVI-R43-T1317 Diesel Generator Start and Load Division 1 December 6, 2000 1R22 Surveillance Testing SVI-C51-T0033F APRM F Flow Channel Calibration for 1C51- 23 April 2002 K605F

SVI-B21-T0035D RPV Low Level and High Level 8RPS and RHR April 8,2002 Shutdown Isolation SVI-E22-T1192 HPCS Logic System Functional Test April 18, 2002 SVI-R43-T1318 Diesel Generator Start and Load Division 2 April 5, 2002 SVI-E21-T2001 Low Pressure Core Spray Pump and Valve March 12, 2001 Operability Test 1EP4 Emergency Action Level and Emergency Plan Changes Perry Nuclear Power Plant Emergency Plan, Rev. 15 Perry Nuclear Power Plant Emergency Plan, Rev. 15, Temporary Change No. 2 2PS3 Radiological Environmental Monitoring and Radioactive Material Control Programs REMP-0018 Radiological Environmental Monitoring Program: Revision 5 Reporting Requirements REMP-0022 Radiological Environmental Monitoring Program: Revision 3 Processing Data from the PNPP Meteorological Tower REMP-0006 Radiological Environmental Monitoring Program: Revision 6 Fish Sampling Instruction REMP-0007 Radiological Environmental Monitoring Program: Revision 7 Sediment Sampling REMP-0008 Radiological Environmental Monitoring Program: Revision 5 Precipitation Sampling REMP-0009 Radiological Environmental Monitoring Program: Revision 5 Surface and Drinking Water Sampling REMP-0010 Radiological Environmental Monitoring Program: Revision 5 Milk Sampling REMP-0012 Radiological Environmental Monitoring Program: Revision 5 Food Product Sampling REMP-0014 Radiological Environmental Monitoring Program: Revision 4 Exchange of Field Dosimeters REMP-0023 Radiological Environmental Monitoring Program: Revision 2 Air Sample Collection REMP-0016 Radiological Environmental Monitoring Program: Revision 4 Soil Sampling REMP-0013 Radiological Environmental Monitoring Program: Revision 9 Sampling Locations

REMP-0017 Radiological Environmental Monitoring Program: Revision 7 Land Use Survey For Residence, Gardens, and Milk Producing Animals REMP-0003 Radiological Environmental Monitoring Program: Revision 6 Completing The Sample Collection Field Form and Label REMP-0024 Radiological Environmental Monitoring Program: Revision 1 Air Sampler Maintenance and Calibration HPI-H0004 Identification of Radioactive materials and Revision 2 Release of Materials from RRAs CHI-0053 Operation of the Gamma Spectroscopy System Revision 0 Annual Meteorological Report For The Perry 2001 Nuclear Power Plant For 2001 Annual Environmental and Effluent Release 2000 Report for The Perry Nuclear Power Plant Annual Environmental and Effluent Release 2001 Report for The Perry Nuclear Power Plant Air Sampler Maintenance and Calibration 2002 Records PA 01-09 Audit Report: Radiation Monitoring November 20, 2001 Audit: Overview of Vendor Operation and May 7-8, 2002 Increased Confidence Level of Sample Analysis NUPIC Audit Number 17795 January 9, 2002 CR 02-00028 Annual TLD Found Missing During Quarterly February 5, 2002 Change-out CR 02-00095 REMP Air Sampler #7 Found Not Running February 4, 2002 CR 02-00263 Vendor Supplied Computer Software Error February 12, 2002 CR 02-00579 0D17-K606 and 0D17-R170 (0D170R945) April 8, 2002 ODCM Testing Requirements CR 01-3974 Request for Assistance Concerning Beta November 15, 2001 Monitoring of off Gas Tools CR 01-3997 RFA Conditional Release of Rad Material November 19, 2001 CR 02-00260 Radioactive Labcoat Found at MB100 January 25, 2002 CR 02-00530 Notification of Radioactive Contamination on February 19, 2002 Trailer Released from Perry Plant CR 02-00676 Clarification of Radwaste Surveyors March 7, 2002 Responsibilities

CR 02-00697 LHRA Door Lock Latching Mechanism Failed March 10, 2002 CR 02-00722 Evaluate Changing to a Pocketless Modesty March 12, 2002 Garment CR 02-00759 Evaluate White Finding at Comanche Peak for March 14, 2002 Relevance to PNPP CR 02-00937 Heise Gauge, Coming into the RRA Was Found March 28, 2002 to Be Contaminated CR 02-00942 Contaminated Tool Found at Turbine 593 East March 28, 2002 Results in Personnel Contamination CR 02-01085 Orange Painted Tools Found in Non-RRA Tool April 11, 2002 Storage Area CR 02-01141 Industry Experience with Hot Particle Control April 17, 2002 CR 02-01185 Contaminated Modesty Top April 19, 2002 CR 02-01268 Yellow Bag of Tools Found in SBHS Decon Area April 26, 2002 Without RAM Tag or RECS Decon Tag CR 02-01201 Rad Material Found in Excess of Posting Limits April 22, 2002 CR 02-01232 Shovel with Yellow and Orange Paint Found in April 24, 2002 MB-100 CR 02-01267 Increase in Discrete Particles Detected During April 26, 2002 January 2002 CR 02-01305 Heightened Awareness of RRA Tooling Needed April 30, 2002 by Some Personnel CR 02-01484 Drums Identified Without Radioactive Material May 15, 2002 Tags 3PP3 Physical Protection Tactical Response Team Manual Revision 99-06 Risk Informed Security Study November 1999 Scoped Rifle Training/Instructors Manual February 2002 Lesson Plan Task 07 Weapons Objectives June 1, 2002 Lesson Plan Task 06 Response Force Objectives September 1, 2000 Lesson Plan CAS/SAS Operator Certification September 13, 2000 Self-Assessment Effectiveness of Security Training Unit Firearms May 15, 2001 340-SPS 2001 Transition Surveillance No. OPID Operational Surveillance Report May 17, 2001 01-010

CR-01249 Security SAS Operator Made Untruthful April 17, 2002 Statements SCI-0037 Suspicious Aircraft February 7, 2002 SCI-003 Aircraft Threat February 7, 2002 Security Event Logs October 2001 to May 2002 Table Top Drill Records October 2001 to May 2002 4OA1 Performance Indicator (PI) Verification NEI 99-02 Regulatory Assessment Performance Indicator November 2001 Guideline, Rev. 2 Logs Plant Narrative Logs July 1, 2001 - March 31, 2002 Logs Monthly Safety System Unavailability Logs July, 2001-March, 2002 Logs Technical Specifications Rounds January-March, 2002 4OA2 Identification and Resolution of Problems CR 02-00501 Evaluation of Human Performance Trend in February 17, 2002 Operations Section CR 01-2662 Fire Protection Valve Misalignment July 9, 2001 CR 01-3467 Incorrect Starting of the Division 3 Diesel During September 28, 2001 Performance of Monthly Test CR 01-3533 Incorrect Data Recorded During PTI-P45-P0003 October 4, 2001 Performance CR 01-3536 Improper Tag Placement October 4, 2001 CR 01-3639 Incorrect Trains Posted as Protected in ESW October 15, 2001 Building for the Division 2 Outage CR 01-3704 Incorrect PT Drawer Opened October 20, 2001 CR 01-3840 Valve Left Out of Position During Operator November 4, 2001 Rounds CR 01-4120 Inadvertent Switch Manipulation November 30, 2001 CR 01-4158 Collective Significance Review of Component December 4, 2001 Misposition Errors CR 02-00409 Switch Misposition Error February 9, 2002

CR 02-00499 Incorrect P47 Chiller Shutdown During Chiller February 16, 2002 Swap for PWIS CR 02-00767 Div 3 Diesel Generator Wrong Control Switch March 13, 2002 Positioned 4OA3 Event Followup IOI-14 Fast Unload and trip of Main Turbine September 11, 1995 IOI-3 Power Changes November 11, 1993 CR 02-01712 Sequence of Events Relative to Exciter Field June 1, 2002 Ground Annunciator CR 02-01713 Exciter Field Ground Alarm Received June 1, 2002 CR 02-01895 Generator Out of Phase Synchronization June 13, 2002 Technical Recommendations CR 02-01898 S611 Breaker Cause Analysis CR June 13, 2002 CR 02-01886 Main Generator Potentially Synchronized Out of June 13, 2002 Phase During Loading 31

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