IR 05000315/2001019

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IR 05000315/2001-019(DRP), IR 05000316/2001-019(DRP), on 11/18-12/29/2001; Indiana Michigan Power Company, D.C. Cook Nuclear Power Plant, Units 1 and 2. Fire Protection, Radiological Environmental and Radioactive Material. Violations Noted
ML020230387
Person / Time
Site: Cook  American Electric Power icon.png
Issue date: 01/23/2002
From: Anton Vegel
NRC/RGN-III/DRP/RPB6
To: Bakken A
American Electric Power Co
References
EA-02-010 IR-01-019
Download: ML020230387 (60)
v • d • e


Text

ary 23, 2002

SUBJECT:

D. C. COOK NUCLEAR POWER PLANT, UNITS 1 AND 2 NRC INSPECTION REPORT 50-315/01-19(DRP); 50-316/01-19(DRP)

Dear Mr. Bakken:

On December 29, 2001, the NRC completed an inspection at your D. C. Cook Nuclear Power Plant, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on December 28, 2001 and January 23, 2002 with Mr. Joseph Pollock and other members of your staff.

This 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 two issues of very low safety significance (Green) and one No Color finding which were determined to involve violations of NRC requirements. However, because of their very low safety significance and because they have been 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 Enforcement Policy. The inspectors also identified one Green finding associated with the human performance cross-cutting area. If you contest the Non-Cited Violations, you should provide a response with the 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 20555-001; and the NRC Resident Inspector at the D. C. Cook facility.

A. Immediately following the terrorist attacks on the World Trade Center and the Pentagon, the NRC issued an advisory recommending that nuclear power plant licensees go to the highest level of security, and all promptly did so. With continued uncertainty about the possibility of additional terrorist activities, the Nation's nuclear power plants remain at the highest level of security and the NRC continues to monitor the situation. This advisory was followed by additional advisories over the coming weeks, and although the specific actions are not releasable to the public, they generally include increased patrols, augmented security forces and capabilities, additional security posts, heightened coordination with law enforcement and military authorities, and more limited access of personnel and vehicles to the sites. The NRC has conducted various audits of your response to these advisories and your ability to respond to terrorist attacks with the capabilities of the current design basis threat (DBT). From these audits, the NRC has concluded that your security programs are adequate at this time.

In accordance with 10 CFR 2.790 of the NRC's "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 NRC's 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/

Anton Vegel, Chief Branch 6 Division of Reactor Projects Docket Nos. 50-315; 50-316 License Nos. DPR-58; DPR-74

Enclosure:

Inspection Report 50-315/01-19(DRP);

50-316/01-19(DRP)

REGION III==

Docket Nos: 50-315; 50-316 License Nos: DPR-58; DPR-74 Report No: 50-315/01-19(DRP); 50-316/01-19(DRP)

Licensee: American Electric Power Company Facility: D. C. Cook Nuclear Power Plant, Units 1 and 2 Location: 1 Cook Place Bridgman, MI 49106 Dates: November 18, 2001 through December 29, 2001 Inspectors: J. Maynen, Acting Senior Resident Inspector K. Coyne, Resident Inspector Z. Falevits, Senior Reactor Inspector B. Kemker, Resident Inspector - Byron R. Krsek, Resident Inspector - Palisades J. Lennartz, Senior Resident Inspector - Palisades T. Madeda, Physical Security Inspector D. Passehl, Senior Project Engineer W. Slawinski, Senior Radiation Specialist R. Schmitt, Radiation Specialist R. Winter, Reactor Engineer Approved by: A. Vegel, Chief Branch 6 Division of Reactor Projects

Table of Contents SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Summary of Plant Status: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 1. REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 1R01 Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 1R02 Evaluations of Changes, Tests, or Experiments . . . . . . . . . . . . . . . . . . . . . . . . . 6 1R04 Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 1R11 Licensed Operator Requalification Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 1R12 Maintenance Rule Implementation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 1R13 Maintenance Planning and Emergent Work Control . . . . . . . . . . . . . . . . . . . . 10 1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 1R16 Operator Workarounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 1R17 Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 1R19 Post Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 2. RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 2OS1 Access Controls for Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . 13 2OS3 Radiation Monitoring Instrumentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 2PS3 Radiological Environmental Monitoring and Radioactive Material Control Programs

............................................................ 17 3. SAFEGUARDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 3PP4 Security Plan Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 4. OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 4OA3 Event Follow-Up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 4OA4 Cross-Cutting Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 4OA6 Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 4OA7 Licensee Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 LIST OF ACRONYMS USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

SUMMARY OF FINDINGS IR 05000315-01-19(DRP), IR 05000316-01-19(DRP), on 11/18-12/29/2001; Indiana Michigan Power Company, D. C. Cook Nuclear Power Plant, Units 1 and 2. Fire Protection, Radiological Environmental and Radioactive Material Control Program, Performance Indicator Verification, Identification and Resolution of Problems, Cross-Cutting Issues.

This report covers a 6-week routine inspection. The inspection was conducted by resident and Region III inspectors. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter 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: Mitigating Systems

  • No Color. The inspectors identified a Non-Cited Violation (NCV) for failure to ensure that coordination and selective tripping was provided in accordance with the Safe Shutdown Capability Assessment. The Current Transformers (CT) for protective relaying at the 4.16 kV level were undersized and could reach saturation conditions if a bolted fault were to occur on the associated cabling.

This condition could result in inadvertent tripping of 4.16 kV circuit breakers supplying safe shutdown equipment. The failure to ensure coordination and selective tripping is a violation of the D. C. Cook Operating license Section 2.C.(4) for Unit 1 and Section 2.C.(3)(0) for Unit 2.

The finding was determined to be No Color because the finding was not suitable for SDP evaluation because it did not involve the impairment or degradation of a fire protection feature. Because the finding was of very low safety significance and the finding was captured in the licensees corrective action system, this finding is being treated as a NCV consistent with Section VI.A1 of the NRC Enforcement Policy (Section 1R05).

  • TBD. The inspectors identified an apparent violation of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the licensees failure to include appropriate quantitative acceptance criteria in maintenance procedure 12-MHP 5021.056.007, "Auxiliary Feed Pump Trip and Throttle Valve Linkage Adjustment," Revision 2. Specifically, the procedure specified a trip throttle valve contact alignment criteria that was less conservative than the contact alignment specified in the vendors turbine driven auxiliary feedwater pump (TDAFWP) trip throttle valve test instructions. Alignment of the trip throttle valve using a less conservative contact acceptance criteria could result in less latch engagement than required by a surface contact area acceptance criteria and a greater potential for inadvertent disengagement of the trip throttle latching mechanism.

On June 14, 2000, the Unit 2 TDAFWP trip throttle valve was adjusted in

accordance with 12-MHP 5021.056.007. Subsequently, on August 10, 2001, the Unit 2 TDAFWP trip throttle valve failed to adequately engage during three successive start attempts. The licensee determined that the apparent cause of the August 2001 failure was insufficient engagement of the trip throttle valve latching mechanism.

The staffs significance determination of this finding was not complete at the time of issuance of this report; therefore, this issue is considered an unresolved item.

The safety significance of this issue has been characterized as "To Be Determined (TBD)" pending the completion of additional risk analysis.

(Section 4OA1)

  • Green. The inspectors determined that the licensee failed to address a design deficiency on the Unit 1 and the Unit 2 safety-related 4.16 kV circuit breakers in a timely manner. This design deficiency could result in exceeding the 4.16 kV circuit breakers momentary interrupting rating capability during a 3-phase bolted fault condition. This concern was initially noted by the licensee in 1988, was identified again by the NRC during a Safety System Functional Inspection in 1990, and during an Electrical Distribution Safety Functional Inspection in 1992.

The failure to properly evaluate and correct this degraded condition is a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion XVI.

The inspectors evaluated the risk significance of this issue using the Significance Determination Process. Because no actual loss of safety function occurred, the low probability of failure, and system redundancy, this issue screened as Green (very low risk significance) after a Phase 1 Significance Determination Process review. (Section 4A02)

Cornerstone: Public Radiation Safety

  • Green. A Non-Cited Violation of Technical Specification 6.8 was identified for the failure to meet Offsite Dose Calculation Manual (ODCM) required radioanalytical detection capabilities for some environmental samples collected during the third and fourth quarters of 2000, and the first quarter of 2001. This finding included a cross-cutting element as a contributing factor related to the timeliness of the licensees corrective actions, since the sample analytical problems were known but not effectively corrected for an extended period.

Although the licensees ability to evaluate the environmental impact from some exposure pathways was impaired, this finding was determined to be of very low safety significance because the majority of sample analyses satisfied detection requirements to enable the overall impact on the environment from actual plant effluents to be assessed. (Section 2PS3)

Cross-Cutting Issues: Human Performance

  • Green. The inspectors identified a Finding of very low safety significance associated with recent licensee human performance weaknesses. Specifically, two licensee identified violations of NRC requirements occurred during this period which indicated weaknesses in the human performance cross-cutting area. The violations involved inadequate control of the impact energy of loads carried over the spent fuel pool contrary to Technical Specification requirements and the failure to adequately align the Unit 1 "B" Train diesel generator (D/G)

voltage regulator for standby service. The human performance aspects of these issues are related to failures to follow procedural guidance, inadequate self checking, and the failure to perform adequate independent verifications.

The inspectors assessed the safety significance of this issue using the Significance Determination Process (SDP). The inspectors concluded that these human performance weaknesses had a credible impact on safety and could become a more significant safety concern if left uncorrected. Specifically, the failure to limit the impact energy of loads carried over spent fuel could result in fuel barrier damage greater than assumed in the safety analysis following a postulated crane failure. The inspectors determined that the failure to adequately control impact energy was associated with the fuel barrier; therefore, this issue was determined to be of very low safety significance following a Phase 1 SDP. Additionally, the failure to align the diesel generator voltage regulation system for standby service could result in the failure of the diesel generator to adequately provide power to supported equipment. The inspectors determined that, based on the as-found voltage regulator settings, the Unit 1 "B" Train D/G would have been able to perform its associated safety function.

Because the failure to adequately align the Unit 1 "B" Train D/G did not result in an actual loss of safety function, this issue was also determined to be of very low safety significance. Therefore, the inspectors concluded that these human performance weaknesses constituted a finding of very low risk significance based on the safety significance of the resultant issues and their impact to the cornerstones of reactor safety. (Section 4OA4)

B. Licensee Identified Violations Violations of very low safety significance, which had been identified by the licensee, were reviewed by the inspectors. Corrective actions taken or planned by the licensee are reasonable. These violations are listed in Section 4OA7 of this report.

Report Details Summary of Plant Status:

Unit 1 and Unit 2 both began the inspection period at full power. Both units operated at or near full power throughout the inspection period.

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

a. Inspection Scope The inspectors reviewed the implementation of the licensees winterization program in preparation for the cold weather season. The inspectors walked down the screenhouse area of the plant, which houses the essential service water (ESW) system pumps, and the main steam valve enclosures, which house the main steam isolation valves and the main steam safety valves. In addition, the inspectors walked down the safety-related spare parts storage areas. The inspectors verified the design features and implementation of the licensees procedures protected these systems and components from cold weather effects. The inspectors also reviewed a selection of previous condition reports (CRs) regarding winterization to verify that conditions adverse to quality were properly addressed.

b. Findings No findings of significance were identified.

1R02 Evaluations of Changes, Tests, or Experiments (71111.02)

.1 Review of Evaluations and Screenings for Changes, Tests, or Experiments a. Inspection Scope The inspector reviewed eleven full evaluations performed pursuant to Federal Regulations 10 CFR 50.59. The full evaluations were related to temporary and permanent plant modifications, set-point changes, procedure changes, potential conditions adverse to quality, and changes to the licensee's updated safety analysis report. The inspector confirmed that the full evaluations were thorough and that prior NRC approval was obtained when appropriate. The inspector also reviewed eleven screenings, where the licensee had determined that a 10 CFR 50.59 full evaluation was not necessary. In regard to the changes reviewed where no 10 CFR 50.59 full evaluation was performed, the inspector reviewed the changes to verify that they did not meet the threshold requiring a 10 CFR 50.59 full evaluation.

These 10 CFR 50.59 evaluations and screenings were chosen based on risk significance of samples from the different cornerstones.

b. Findings No findings of significance were identified.

.2 Identification and Resolution of Problems a. Inspection Scope The inspector reviewed the licensee's Condition Reports concerning 10 CFR 50.59 evaluations and screenings to verify that the licensee had an appropriate threshold for identifying issues. The inspector evaluated the effectiveness of the corrective actions for the identified issues.

b. Findings No findings of significance were identified.

1R04 Equipment Alignment (71111.04)

.1 Partial Equipment Walkdowns a. Inspection Scope The inspectors performed a partial system walkdown of the following risk-significant systems:

Mitigating Systems Cornerstone

  • Placing Unit 2 "A" Train containment spray system in standby readiness The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones. The inspectors reviewed operating procedures, Technical Specification (TS) requirements, Administrative Technical Requirements (ATRs), system diagrams, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered these systems incapable of performing their intended functions.

b. Findings No findings of significance were identified.

1R05 Fire Protection (71111.05)

.1 Fire Protection Safe Shutdown Analysis a. Inspection Scope The Fire Protection Safe Shutdown Analysis (SSA) for D. C. Cook assumes that coordination and selective tripping is provided for all circuits on the emergency power system. The inspectors examined the licensees existing coordination design against the assumptions made in the SSA.

b. Findings The inspectors identified a Non-Cited Violation for failure to ensure that coordination and selective tripping was provided. The existing current transformers (CTs) are undersized and are not suitable for their present application. The licensee documented in CR 00-9424, dated June 29, 2000, that under certain severe conditions, the CTs that feed the phase instantaneous current (PJC) relays may saturate and impact the timing of the PJC relays. The licensee stated that spurious tripping of safety-related equipment due to this phenomenon was highly unlikely since the instantaneous units were set at a high value (1.75 percent locked rotor amps) such that sufficient margin was provided to account for any error introduced by CT saturation effects. However, relay coordination problems were introduced by the identification of the CT saturation.

In response the licensee stated, Due to the potential for CT saturation, a postulated bolted fault may not result in a trip of the circuit breaker nearest the fault. The inspectors noted that this condition could result in the inadvertent trip of an entire 4.16 kV bus due to a load fault. If the downstream breaker were properly coordinated, only the affected load would be tripped. Since redundant trains exist, the loss of a single 4.16 kV bus is already bounded by the existing D. C. Cook Safety Analysis.

The SSA for D. C. Cook assumes that coordination and selective tripping is provided for all circuits on the emergency power system. The licensee has recognized that these CT saturation concerns present a condition that is inconsistent with the coordination assumptions in the SSA. Following NRC questioning, the licensee issued Condition Report (CR) 01208057 to evaluate and address this non-conformance. While a CR was written and the licensee plans to study the issue, no action plan appears to exist for completion and resolution. In the interim, the licensee has determined that the worst-case situation (i.e., a single fire induces severe faults in both trains of redundant 4.16 kV motors and results in loss of both trains of electrical power in the fire affected unit) is bounded by the analysis for a fire in the 4.16 kV switchgear room. The licensee informed the NRC that the issue has been addressed to ensure that the plant can be safely shut down.

Operating License Section 2.C.(4) for Unit 1 Docket No. 50-315, Operating License Number DPR-58, and Operating License Section 2.C.(3)(o) for Unit 2 Docket No. 50-316, Operating License Number DPR-74, requires D. C. Cook plant to implement and maintain, in effect, all provisions of the approved Fire Protection Program as described in the Updated Final Safety Analysis Report for the facility.

UFSAR Section 9.8.1 incorporates the Safe Shutdown Capability Assessment (SSCA)

by reference. SSCA Section 2.7.2 states, The electrical distribution system was reviewed to ensure that coordination and selective tripping is provided for all circuits on the emergency power system. It further states that a fuse/circuit breaker coordination study and a multiple high impedance fault study are maintained and reviewed for design changes to assure coordination and to remove this potential for functional loss of safe shutdown components. Contrary to the SSCA, undersized CTs could result in inadvertent tripping of 4.16 kV circuit breakers. This is considered a violation of the D. C. Cook Operating License. This violation is not suitable for SDP evaluation because it did not involve the impairment or degradation of a fire protection feature, and is therefore considered a No Color finding. Because the licensee entered the finding into the corrective action program as CR 01208057, this violation is being treated as a Non-Cited Violation in accordance with Section VI.A.1 of the NRCs Enforcement Policy (NCV 50-315/01-19-01(DRP); 50-316/01-19-01(DRP)).

.2 Routine Fire Zone Tours a. Inspection Scope The inspectors performed fire protection walkdowns of the following four risk-significant plant areas:

Mitigating Systems Cornerstone

  • Unit 1 Quadrant 1 Cable Tunnel (Fire Zone 7)
  • Auxiliary Building - Elevation 650 (Fire Zone 69)
  • Unit 1 Turbine Room - Elevation 609 (Fire Zones 91, 92, 93, 94)
  • Security Diesel Generator and Switchgear Room The inspectors verified that fire zone conditions were consistent with assumptions in the licensees fire hazard analysis. The inspectors walked down fire detection and suppression equipment, assessed the material condition of fire control equipment, and evaluated the control of transient combustible materials.

b. Findings No findings of significance were identified.

1R11 Licensed Operator Requalification Program (71111.11)

a. Inspection Scope On November 20, 2001, the inspectors observed Operations C Shift during licensed operator training. The training consisted of an evaluated simulator scenario that required the operators to respond to and mitigate a steam generator tube rupture event concurrent with a loss of reserve power. The training scenario also required the licensed operators to implement the emergency plan. The inspectors verified that the training was effective and assessed the operators ability to mitigate the event and to implement the emergency plan. The inspectors observed the post-scenario critique of

operator performance to assess the licensee evaluators ability to identify and assess operator performance deficiencies.

b. Findings No findings of significance were identified.

1R12 Maintenance Rule Implementation (71111.12)

a. Inspection Scope The inspectors evaluated the licensees implementation of 10 CFR 50.65 (the Maintenance Rule). The inspectors assessed: (1) functional scoping in accordance with the Maintenance Rule; (2) characterization of system functional failures; (3) safety significance classification; (4) 10 CFR 50.65 (a)(1) or (a)(2) classification for system functions; and (5) performance criteria for systems classified as (a)(2) or goals and corrective actions for systems classified as (a)(1). The inspectors reviewed the following risk-significant systems:

Mitigating Systems Cornerstone

  • Compressed Air System b. Findings No findings of significance were identified.

1R13 Maintenance Planning and Emergent Work Control (71111.13)

a. Inspection Scope The inspectors reviewed the risk assessment and risk management for the following risk significant maintenance activities:

Mitigating Systems Cornerstone

  • Installation of design change on Unit 1 A Train containment spray heat exchanger ESW outlet valve, December 1, 2001 These activities were selected based on their potential risk significance relative to the reactor safety cornerstones. As applicable for each of the above activities, the

inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensees probabilistic risk analyst or shift technical advisor, and verified that plant conditions were consistent with the risk assessment. The inspectors also reviewed TS and ATR requirements and walked down portions of redundant safety systems, when applicable, to verify that risk analysis assumptions were valid and applicable requirements were met.

b. Findings No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope The inspectors reviewed the following operability determinations and evaluations affecting the reactor safety cornerstones to determine whether operability was properly justified and that no unrecognized risk increase had occurred.

Mitigating Systems Cornerstone

  • CR 01347067 Internal degradation found on cells of Unit 2 station battery 2-BATT-AB during performance of surveillance
  • CR 01332066 Operability of the Unit 1 accumulator level instrument, 1-ILA-111 b. Findings No findings of significance were identified.

1R16 Operator Workarounds (71111.16)

.1 Review of the Cumulative Effect of Operator Workarounds (Unit 1)

a. Inspection Scope The inspectors reviewed the cumulative effect of Operator Workarounds, control room deficiencies, and degraded conditions on equipment availability, initiating event frequency, and the ability of the operators to implement abnormal or emergency operating procedures.

b. Findings No findings of significance were identified.

1R17 Permanent Plant Modifications (71111.17)

a. Inspection Scope The inspectors reviewed the engineering analyses, modification documents and design change information associated with the following permanent modifications:

Mitigating Systems Cornerstone

  • 1-DCP-744 Replace Unit 1 D/G high pressure fuel lines
  • 2-DCP-526 Replace Unit 2 D/G high pressure fuel lines
  • 2-DCP-5174 Provide ESW minimum flow path via Unit 2 containment spray heat exchanger The inspectors verified the design adequacy of the modifications and focused the inspection activities on the following parameters associated with the design changes:

heat removal, control signals, equipment protection, operations, flowpaths, process media, licensing basis, and failure modes.

Completed activities associated with the implementation of the modification were also inspected and the inspectors discussed the modifications with the responsible engineers, and operations staff. In addition, the inspectors reviewed the applicable sections of the Technical Specifications, Updated Final Safety Analysis Report, and condition reports associated with the design change packages and installation of the modification.

b. Findings No findings of significance were identified.

1R19 Post Maintenance Testing (71111.19)

a. Inspection Scope The inspectors reviewed the post maintenance testing requirements associated with the following scheduled maintenance activities:

Mitigating Systems Cornerstone

  • JO 01296060 Post modification wiring check for 2-DCP-5174, Alternate flow path for ESW
  • JO 01341004 Replace failed undervoltage relay on 1-CD-BC2, Unit 1 A Train 250 VDC station battery charger
  • JO 01355003 Replace failed control air regulating valve, 1-XRV-237, on Unit 1 A Train D/G

The inspectors reviewed post maintenance testing criteria specified in the applicable preventive and corrective maintenance work orders. The inspectors verified that test methodology and acceptance criteria were appropriate for the scope of work performed.

Documented test data was reviewed to verify that the testing was complete and that the equipment was able to perform the intended safety functions.

b. Findings No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope For each of the surveillance test procedures listed below, the inspectors observed selected portions of the surveillance test and reviewed the test results to determine whether risk significant systems and equipment were capable of performing their intended safety functions and to verify that testing was conducted in accordance with applicable procedural and TS requirements:

Mitigating Systems Cornerstone

  • 01-IHP 4030.SMP.131, Power Range Nuclear Instrumentation Functional Test and Calibration, Revision 0
  • 01-OHP 4030.STP.018, "Steam Generator Stop Valve Dump Valve Surveillance Test," Revision 14
  • 02-OHP 4030.STP.030, Daily and Shiftly Surveillance Checks, Revision 38 Barrier Integrity Cornerstone
  • 01-OHP 4030.STP.030, Daily and Shiftly Surveillance Checks, Data Sheet 19, Ice Condenser Tour Data Sheet, Revision 38 The inspectors reviewed the test methodology and test results in order to verify that equipment performance was consistent with safety analysis and design basis assumptions. The inspectors also reviewed condition reports concerning surveillance testing activities to verify that identified problems were appropriately characterized.

b. Findings No findings of significance were identified.

1EP6 Drill Evaluation (71114.06)

a. Inspection Scope On December 18, 2001, Operations B Shift performed an emergency planning drill in conjunction with licensed operator training. The drill involved a steam generator tube leak and recovery actions. The inspectors reviewed the drill scenario, observed the

licensed operators perform the drill in the simulator, and discussed the drill with members of the licensees training staff.

b. Findings No findings of significance were identified.

2. RADIATION SAFETY Cornerstone: Occupational Radiation Safety 2OS1 Access Controls for Radiologically Significant Areas (71121.01)

.1 Plant Walkdowns and Radiological Boundary Verifications a. Inspection Scope The inspectors conducted walkdowns of the radiologically protected area to verify the adequacy of radiological area boundaries and postings. Specifically, the inspectors walked-down numerous radiologically significant work area boundaries (high and locked high radiation areas) in the Unit 1 and 2 Auxiliary Buildings. Confirmatory radiation measurements were taken to verify that these areas and selected radiation areas were properly posted and controlled in accordance with 10 CFR Part 20, licensee procedures, and Technical Specifications. The inspectors also examined the radiological conditions of work areas within those radiation and high radiation areas walked-down, to assess the radiological housekeeping and contamination controls.

b. Findings No findings of significance were identified.

.2 High Risk Significant, High Radiation Area, and Very High Radiation Area Access Controls a. Inspection Scope The inspectors reviewed the licensees procedures and practices for the control of access to radiologically significant areas (high, locked high, and very high radiation areas) to verify compliance with Technical Specifications, procedures and the requirements of 10 CFR 20.1601 and 20.1602. Specifically, the inspectors evaluated the licensees latest revisions to their procedures and the current practices for the control/inventory of keys to locked high radiation areas (LHRAs), and the licensees methods for independently verifying proper closure and latching of LHRA doors upon area egress. Additionally, the inspectors reviewed radiological postings and challenged access control boundaries to determine if LHRAs and very high radiation areas were properly controlled.

b. Findings No findings of significance were identified.

.3 Radiation Work Permit Reviews a. Inspection Scope The inspectors reviewed several radiation work permits (RWPs) for work in radiologically significant areas, including the RWPs for routine plant tours, removal of test coupons from the spent fuel pool, and for a dive into the fuel transfer canal. The RWPs were evaluated for protective clothing requirements and contamination controls.

Electronic dosimeter alarm set points for both dose rate and integrated dose were evaluated to verify conformity with work area radiological conditions given the work activity and survey indications. The inspectors also reviewed work instructions specified in the RWPs, associated work packages, and pre-job briefing information in order to verify access control restrictions for compliance with Technical Specifications.

b. Findings No findings of significance were identified.

.4 Review of Radiologically Significant Work a. Inspection Scope The inspectors monitored the following high exposure or high radiation area work activities performed during the inspection:

  • Retrieval of test coupons from the Spent Fuel Pool
  • Dive in the fuel transfer canal, to repair fuel handling equipment The inspectors attended pre-job briefings for both of the aforementioned activities and evaluated the radiological job requirements for each. The inspectors also reviewed the licensees procedure and practices for dosimetry placement, including the use of multiple dosimetry for work in high radiation areas having significant dose gradients, for compliance with the requirements of 10 CFR 20.1201 and applicable Regulatory Guides. The inspectors examined the as-low-as-is-reasonably-achievable (ALARA) plan for the work in the spent fuel pool to determine if it contained adequate information to safely control radiological work. The inspectors observed the work evolution to retrieve the test coupons and for the transfer canal dive to verify adherence to the ALARA plan.

The inspectors reviewed those radiological surveys completed prior to and during the fuel pool work, and assessed the radiation protection job coverage and the overall work activities, to verify that the work was completed safely and consistent with work plans.

The inspectors also reviewed completed surveys and applicable postings and barricades associated with this work to verify their adequacy.

b. Findings No findings of significance were identified.

.5 Identification and Resolution of Problems a. Inspection Scope The inspectors evaluated the licensees calender year 2000-2001 condition report (CR)

database and a variety of individual CRs relating to problems with access controls to radiologically significant areas, as well as radiation worker performance and work practices in or around those areas. The inspectors also reviewed Performance Assurance Department Assessment Report No. PA-01-014, Radiation Protection, and several field observation reports, to verify the licensees ability to identify and correct problems and to evaluate the effectiveness of the licensees self-assessment process.

b. Findings No findings of significance were identified.

2OS3 Radiation Monitoring Instrumentation (71121.03)

.1 Operability and Testing of Post Accident Sampling System a. Inspection Scope The inspectors evaluated accident monitoring instrumentation associated with the Post Accident Sampling System (PASS) used for emergency plant assessment. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and reviewed surveillance test records to verify that the system was capable of obtaining representative samples of the containment sump, containment atmosphere, and reactor coolant system. The inspectors reviewed the licensees procedure for testing the PASS and reviewed surveillance records completed in 2000 and 2001, to verify that calibrations were conducted consistent with industry standards and in accordance with the station procedure. The inspectors performed a walkdown of the PASS to verify that equipment was in good material condition and reviewed training records for those station personnel qualified to operate the PASS.

b. Findings No findings of significance were identified.

.2 Calibration of Radiation Monitoring Instrumentation a. Inspection Scope The inspectors examined the electronic dosimeters (EDs) maintained in the licensees instrument calibration facilities and access control areas. The inspectors evaluated the EDs to verify that these instruments were source checked and had current calibrations

consistent with station procedures and industry standards. The inspectors reviewed the EDs to verify that an adequate number of those instruments were designated ready for use were operable and were in good physical condition. The inspectors observed radiation protection staff source check and calibrate a number of EDs, to verify that those activities were completed using appropriate radiation sources. The inspectors also reviewed the calibration procedures and selected calendar year 2001 calibration records to verify that the ED instruments had been properly calibrated.

b. Findings No findings of significance were identified.

.3 Identification and Resolution of Problems a. Inspection Scope The inspectors reviewed calendar year 2001 CRs that addressed radiation instrument (i.e. PASS or EDs) deficiencies to determine if any significant radiological incidents involving radiation instruments had occurred. Additionally, these CRs were examined to verify the licensees ability to identify repetitive problems, contributing causes and the extent of condition, and to implement corrective actions to achieve lasting results. The inspectors examined closed CR P-99-25781 and CR P-99-29165 related to prior deficiencies with some of the area and process radiation monitors, to verify that corrective actions taken by the licensee had adequately addressed UFSAR, Technical Specification and instrument drawing issues.

b. Findings No findings of significance were identified.

Cornerstone: Public Radiation Safety 2PS3 Radiological Environmental Monitoring and Radioactive Material Control Programs (71122.03)

.1 Review of Radiological Environmental Monitoring Reports and Data a. Inspection Scope The inspectors reviewed the Annual Radiological Environmental Operating Reports for calendar year 1999 and 2000, and results of monthly radiological environmental monitoring analyses for the first half of 2001. The inspectors also reviewed the land use census for 2000 and 2001, results of the inter-laboratory comparison program for 1999 and 2000, and changes made to the Offsite Dose Calculation Manual (ODCM) in 2000 and 2001 relative to the environmental monitoring program. These reviews were conducted to verify that the radiological environmental monitoring program (REMP) was implemented as required by Technical Specifications and the ODCM, and that any changes did not affect the licensees ability to monitor the impacts of radioactive

effluents on the environment. Additionally, the inspectors evaluated the locations of the environmental monitoring stations and the type of samples collected as part of the REMP, to determine if they were consistent with the UFSAR and NRC guidance.

b. Findings No findings of significance were identified.

.2 Walkdowns of Radiological Environmental Monitoring Stations and Meteorological Towers a. Inspection Scope The inspectors walked-down all six onsite environmental air sampling and thermoluminescent dosimeter (TLD) monitoring stations to determine whether they were located as described in the ODCM, and to assess equipment material condition and operability. The inspectors discussed tree growth in the vicinity of the air sampling stations with the REMP Coordinator, to verify that its potential impact on sample representativeness was recognized and to review those actions the licensee was contemplating to address this issue with the State of Michigan. Both the primary and backup meteorological towers were also walked-down by the inspectors, and data readouts in the control room were observed to verify Technical Specification required meteorological instruments were operable and that current meteorological conditions were available. In addition, the inspectors visited one of the two municipal drinking water sampling stations and discussed sampling practices with one of the sample collectors to determine if adequate methods were used to collect the sample and ensure its integrity.

b. Findings No findings of significance were identified.

.3 Review of Radiological Environmental Monitoring Equipment Maintenance and Testing a. Inspection Scope The inspectors reviewed the most recent air sample pump calibration records and associated procedures, and meteorological tower equipment calibration and maintenance records for calendar year 2000 through October 2001, to verify that the maintenance and testing program for this equipment was implemented consistent with Technical Specifications and procedural requirements. The most recent calibration of the air sample pump rotameter standard used by the licensee was also reviewed to verify that its certification met industry standards and had traceability to the National Institute of Standards and Technology. The inspectors discussed air sample pump calibration and maintenance activities with an instrument technician and the REMP Coordinator to assess the adequacy of the calibration methods, and to review actions being considered for a routine preventative maintenance program for associated equipment.

b. Findings No findings of significance were identified.

.4 Review of REMP Sample Collection and Analyses a. Inspection Scope The inspectors accompanied a REMP technician and observed the collection and change-out of air particulate filters and charcoal cartridges at each of the licensees six onsite environmental stations, to determine whether samples were collected consistent with procedures and if good practices were used. The inspectors observed the technician complete air sample pump field checks upon sample change-out to determine whether the checks were conducted in accordance with procedure. The inspectors assessed the analytical detection capabilities of the contract laboratory used by the licensee to analyze its environmental samples, and reviewed licensee identified problems with the vendors sample analyses. The inspectors assessment was conducted to determine if the radiological environmental sample analysis program was implemented consistent with the ODCM, and to verify that the vendor was capable of making adequate radiological measurements.

b. Findings The inspectors identified a Green Finding and an associated Non-Cited Violation concerning the failure to routinely meet ODCM required radioanalytical detection capabilities for a variety of environmental samples collected over an approximate 5 month period. The inspectors identified that the Finding also included a cross-cutting element in the area of problem resolution, because the licensees actions to effectively correct known problems were not timely.

The licensee utilized the services of a vendor laboratory to analyze the environmental samples collected by its staff. A variety of samples were collected to monitor each exposure pathway and included well, surface and municipal drinking water, air particulate and charcoal, vegetation, milk and other food products, which were all analyzed for their radioactivity content specific to each sample type. Analytical detection criteria for each sample type were specified in the ODCM in the form of lower limits of detection (LLD), which were consistent with industry standards and NRC guidelines for routine environmental measurements.

Beginning the second quarter of 2000, the licensee identified that the vendor laboratory failed to meet ODCM specified LLDs for several water samples. These problems were attributed to laboratory equipment failure and were corrected by the vendor laboratory.

Subsequently, the vendor moved its laboratory operation, as planned, to a new facility; however, the move affected its analytical capabilities because samples were not analyzed in a timely manner to meet the LLDs for shorter lived radionuclides. A fire occurred in one of the laboratory facilities about the same time the move took place, which exacerbated the analytical problems. As a result, between approximately September 2000 and January 2001, numerous (more than 50) environmental samples analyzed from several exposure pathways did not meet REMP sample LLD criteria

specified by the ODCM. Specifically, numerous drinking water samples and several milk samples were not analyzed in a sufficiently timely manner to achieve ODCM required LLDs for certain isotopes, including some LLDs that were not achieved by several orders of magnitude. The licensee recognized the problem and regularly communicated with the vendor to resolve the analysis difficulties; however, the problems continued for approximately 5 months until the vendors new laboratory operations stabilized in approximately February 2001.

This issue, if not corrected, would become a more significant concern because it could impact the licensees ability to assess the effect of plant effluents on the environment.

Therefore, the issue represents a Finding which the inspectors evaluated using the significance determination process (SDP) for the public radiation safety cornerstone.

Since the sample analysis problems related primarily to certain shorter lived isotopes that were not released in plant effluents during the affected time periods (other than a few samples that did not meet LLDs for iodine-131 and iron-59), a failure to assess the overall impact of plant operations on the environment for a given pathway did not occur.

Consequently, the inspectors concluded that the problem was of very low safety significance (Green).

Technical Specification 6.8.4(b) requires, in part, that a program be established, implemented, and maintained to monitor the radiation and radionuclides in the environs of the plant. The program shall be contained in the ODCM, and include sampling and analyses in accordance with the methodology and parameters in the ODCM. The ODCM (station procedure PMP-6010.OSD.001), Section 3.5, requires that sample analysis for the REMP be conducted in accordance with Attachment 3.20, Maximum Values for Lower Limits of Detection - REMP. The REMP bases specifies that analyses be performed in such a manner that the stated LLDs be achieved under routine analysis conditions. The failure to meet ODCM specified LLDs for numerous samples collected over an approximate 5 month period is a violation of Technical Specification 6.8.4. However, because of the very low safety significance of the violation and because the licensee included this item in its corrective action program (CR 01110029 and CR 00243086), this violation is being treated as a Non-Cited Violation (NCV 50-315/01-19-02; 50-316/01-19-02).

3. SAFEGUARDS Cornerstone: Physical Protection 3PP4 Security Plan Changes (71130.04)

a. Inspection Scope The inspector reviewed Revision 1 to the Donald C. Cook Nuclear Plant Security Training and Qualification Plan to verify that the changes did not decrease the effectiveness of the submitted document. The referenced revision was submitted in accordance with 10 CFR 50-54(p)(2) requirements by licensee letter dated November 16, 2001.

b. Findings No findings of significance were identified.

4. OTHER ACTIVITIES (OA)

4OA1 Performance Indicator Verification (71151)

.1 Unit 2 Turbine Driven Auxiliary Feedwater Pump Fault Exposure a. Inspection Scope The licensee estimated that approximately 1007 hours0.0117 days <br />0.28 hours <br />0.00167 weeks <br />3.831635e-4 months <br /> of fault exposure hours for the Unit 2 turbine driven auxiliary feedwater pump (TDAFWP) were accumulated during the second and third quarters of 2000. The inspectors reviewed the circumstances associated with this fault exposure time to assess the safety significance of this issue.

Because the licensee did not monitor system unavailability during the extended dual unit outage that began in September 1997, the licensee has reported safety system unavailability data only since the second quarter of 2000. Consequently, the licensee lacks sufficient data to calculate the final value of the system unavailability performance indicator; therefore, the safety system unavailability indicator was considered to be "Not Applicable" at the time of the inspection.

The licensee submitted frequently asked question (FAQ) 291 to the Nuclear Energy Institute to address calculation of the safety system unavailability performance indicator with less than twelve quarters of system performance data. This FAQ was answered in Revision 2 to NEI 99-02, "Regulatory Assessment Performance Indicator Guideline,"

with the recommendation to zero sum unavailability time prior to the second quarter of 2000 to enable calculation of the performance indicator. Additionally, the FAQ response stated that T/2 fault exposure time accumulated prior to obtaining twelve quarters of performance data would not be included in the performance indicator calculation but instead be evaluated within the inspection and significance determination processes.

Therefore, the inspectors reviewed T/2 safety system fault exposure time accumulated during the performance indicator reporting period using the SDP process.

b. Findings The inspectors identified a potential violation of 10 CFR 50, Appendix B, Criterion V,

"Instructions, Procedures, and Drawings," for the licensees failure to include appropriate quantitative acceptance criteria in maintenance procedure 12-MHP 5021.056.007, "Auxiliary Feed Pump Trip and Throttle Valve Linkage Adjustment," Revision 2. The safety significance of this issue has been characterized as "To Be Determined (TBD)" pending the completion of additional risk analysis.

On August 9, 2001, the licensee removed the Unit 2 TDAFWP from service to perform several pre-planned maintenance activities. Following completion of these activities on August 10, the licensee performed two unsuccessful TDAFWP start attempts in accordance with 02-OHP 4021.056.001, "Filling and Venting of the Auxiliary Feedwater

System." A subsequent TDAFWP start attempt for troubleshooting on August 10, 2001 was also unsuccessful. The licensee investigated the failure and determined that the cause of the failure to start was insufficient engagement of the trip throttle valve latching mechanism. The licensee repaired the trip throttle valve under Job Order (JO)

01222001 and returned the Unit 2 TDAFWP to an operable status on August 11, 2001.

The inspectors reviewed the licensee's apparent cause evaluation for the TDAFWP trip throttle valve failure performed for CR 01222001. The licensee determined that the trip throttle valve alignment criteria specified in maintenance procedure 12-MHP 5021.056.007, "Turbine Driven Auxiliary Feed Pump Trip and Throttle Valve Linkage Adjustment," Revision 2, was inconsistent with guidance used by the valve vendor for trip throttle valve alignment. Specifically, Procedure 12-MHP 5021.056.007 specified a trip throttle valve contact alignment of a minimum of 75 percent contact line from side to side on the trip hook as measured by blue check. However, the vendor trip throttle test procedure (Schutte & Koerting Co. Drawing 77S-0048V), written in 1977, specified a blue check latch face contact acceptance criteria of a minimum of 75 percent of the surface area. Alignment of the trip throttle valve using a line contact acceptance criteria could result in less latch engagement than required by a surface contact area acceptance criteria and a greater potential for inadvertent disengagement of the trip throttle latching mechanism. Procedure 12-MHP 5021.056.007 originally required a minimum 75 percent contact on the trip hook latch as determined by blue check, but did not specify if the contact criteria referred to a line or area blue check. In January 1997, the licensee evaluated the 12-MHP 5021.056.007 blue check acceptance criteria under an engineering evaluation supporting work request (WR) A0107471 in order to clarify the contact blue check criteria. This evaluation incorrectly concluded that the blue check acceptance criteria applied to line contact as measured from side to side rather than area contact. Consequently, Procedure 12-MHP 5021.056.007 was revised on June 11, 1997, to specify a trip throttle valve trip hook blue check criteria of 75 percent contact line. The licensee later determined that the contact line blue check acceptance criteria was applicable to a type of trip throttle valve not used at D. C. Cook.

During the apparent cause evaluation for the TDAFWP pump failure, the licensee identified that the trip throttle failed during testing in June 2000. During testing following a design change to the TDAFWP governor control system, the Unit 2 TDAFWP failed to start. The licensee determined that the cause of the failure was due to excessive wear of the trip hook latching mechanism. The trip hook latch mechanism was replaced under JO C0052930, "2-DCP-617, Rework TDAFWP Governor," and adjusted to at least a 75 percent line contact in accordance with 12-MHP 5021.056.007. The inspectors determined that the licensee failed to initiate a condition report to document and evaluate this previous failure. Initiation of a condition report for the June 2000 failure would have been appropriate since the trip throttle valve failure was unrelated to the original governor testing activities and trip hook latch assembly replacement was not within the original scope of the JO C0052930. The inspectors concluded that the failure to document the June 2000 failure of the Unit 2 TDAFWP trip throttle valve within the corrective action system potentially delayed adequate evaluation of the trip throttle valve failure mechanism and contributed to the August 2001 failure. The licensee initiated CR 01362027 to document this issue.

10 CFR 50 Appendix B, Criterion V, "Instructions, Procedures and Drawings," required in part that activities affecting quality be prescribed by documented instructions, procedures, or drawings of a type appropriate to the circumstances and shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to the above, Step 8.G of Procedure 12-MHP 5021.056.007, "Turbine Driven Auxiliary Feed Pump Trip and Throttle Valve Linkage Adjustment," Revision 2, did not include appropriate acceptance criteria for determining that alignment of the trip throttle linkage, an activity affecting quality, was satisfactorily accomplished. Specifically, Step 8.G of the procedure specified an alignment acceptance criteria of 75 percent contact line from side to side on the trip hook by blue check. The vendor test procedure for trip throttle valves specified a latch face alignment of face contact over 75 percent of the surface area of the latch face. Alignment of the trip throttle valve using a line contact acceptance criteria could result in less latch engagement than required by a surface contact area acceptance criteria and a greater potential for inadvertent disengagement of the trip throttle latching mechanism. The Unit 2 TDAFWP trip throttle valve was adjusted in accordance with 12-MHP 5021.056.007 on June 14, 2000. Subsequently, the Unit 2 TDAFWP trip throttle valve failed to engage during three successive start attempts on August 10, 2001. The licensee determined that the apparent cause of the pump start failure was due to insufficient engagement of the trip throttle valve latching mechanism.

This issue is considered an apparent violation of 10 CFR 50 Appendix B, Criterion V.

The licensee entered this issue into its corrective action program as CR 01222001.

The staffs significance determination of this finding was not complete at the time of issuance of this report; therefore, this issue is considered an Unresolved Item (50-316/01-19-03(DRP)). The safety significance has been characterized as TBD pending the completion of additional risk analysis.

.2 Safety System Unavailability Performance Indicators a. Inspection Scope Mitigating Systems Cornerstone The inspectors verified the following performance indicators for both units:

+ Safety System Unavailability - Emergency AC [Alternating Current] Power

+ Safety System Unavailability - Auxiliary Feedwater

+ Safety System Unavailability - High Pressure Safety Injection

+ Safety System Unavailability - Residual Heat Removal The inspectors reviewed operating logs, maintenance history and surveillance test history for unavailability information for these systems from October 2000 to September 2001. The inspectors also verified the licensee's calculation of required hours for both units and evaluated applicable safety system equipment unavailability against the performance indicator definition.

The inspectors noted that both units were returned to operation in 2000 following extended outages. The licensee has not yet had sufficient operational service to

calculate the safety system performance indicators. It is expected that these indicators will be calculated starting with the first quarter of 2002.

b. Findings No findings of significance were identified. However, the inspectors identified several issues related to the inaccurate reporting of performance indicator data.

During review of performance indicator data for the emergency AC power system, the inspectors identified that the licensee had not accounted for unavailability time for the D/Gs during the performance of periodic carbon dioxide fire suppression system puff testing consistent with the guidance in NEI [Nuclear Energy Institute] 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 1. The licensee entered this reporting discrepancy into its corrective action program as Condition Report (CR) 01355064.

During review of performance indicator data for the auxiliary feedwater system, the inspectors identified that the licensee had not included hours when an opposite units auxiliary feedwater system train is required to be available to perform its intended safety function per the Technical Specifications (TS) in its calculation of hours required. The inspectors noted that TS 3.7.1.2.b required at least one auxiliary feedwater system flowpath in support of the opposite units safe shutdown functions to be available whenever the opposite unit is in Modes 1, 2, or 3. Although the licensee entered the TS limiting condition for operation (LCO) during these times, it did not believe that unavailability monitoring was expected because the TS LCO was written for an Appendix R based safety function. The inspectors reviewed the definitions of hours required and off-normal events or accidents in NEI 99-02, Revision 1, and determined that unavailability monitoring for Appendix R based safety functions is consistent with the current guidance. The licensee entered this reporting discrepancy into its corrective action program as CR 01355072.

In addition, the inspectors identified multiple minor reporting discrepancies involving the reporting of unavailable hours for the wrong train of several mitigating systems on each unit and the inconsistent tracking of unavailable hours under the licensees Maintenance Rule Program. The licensee entered these reporting discrepancies into its corrective action program as CR 01355058 and CR 01355071.

None of the performance indicator reporting discrepancies noted above would lead to a performance indicator crossing a threshold. See Section 4OA1.1 for discussion of a finding related to the Unit 2 turbine driven auxiliary feedwater pump.

.3 Occupational Exposure Control Effectiveness and Radiological Effluent Technical Specification (RETS)/ODCM Radiological Effluent Occurrence PIs a. Inspection Scope The inspectors reviewed data associated with the Occupational Exposure Control Effectiveness PI and the RETS/ODCM PI, to determine if these indicators were accurately assessed and reported since last reviewed in December 2000. To evaluate

the PI data, the inspectors reviewed the licensees CR database and selected CRs generated between December 2000 and November 15, 2001, to identify any potential occurrences that were not recognized by the licensee. For the occupational radiation safety PI, the inspectors also selectively reviewed RCA egress transaction dose information and ED alarm reports generated in 2001 to determine if any potential unintended dose occurrences took place. For the public radiation safety PI, the inspectors selectively reviewed gaseous and liquid effluent release data and associated offsite dose information for December 2000 through October 2001.

The inspectors also reviewed quarterly PI verification records generated as required by station Procedure PMP 7110.PIP.001, Regulatory Oversight Program Performance Indicators, for the fourth quarter of 2000 and the first three quarters of 2001.

Additionally, PI data collection and analyses were discussed with involved staff to determine if the program and processes were implemented consistent with industry guidance in Nuclear Energy Institute 99-02, Revision 1, Regulatory Assessment Performance Indicator Guideline.

b. Findings No findings of significance were identified.

4OA2 Identification and Resolution of Problems a. Inspection Scope The inspectors reviewed the capability of 4.16 kV breakers to function properly during severe accident conditions.

b. Findings The inspectors identified a Non-Cited Violation for failure to address a long-standing design deficiency with 4.16 kV air circuit breakers. The inspectors noted that a potential safety concern exists with the capability of the 4.16 kV breakers to function properly during a severe fault condition. The fault current available on 4.16 kV load feeders could exceed the circuit breakers momentary interrupting capacity rating of 250 MVA during a 3-phase bolted fault condition. The momentary rating is used to measure the circuit breakers ability to safely close during a fault condition and carry the fault current.

Consequently, the affected circuit breaker could fail to trip and the upstream bus supply circuit breaker would potentially trip the entire 4.16 kV bus. This condition exists on all four independent 4.16 kV auxiliary buses of Unit 1 and 2, however, the redundant bus should remain available to perform the affected safety function.

This design deficiency was initially noted by the licensee in 1988. This issue was identified again by the NRC during the Essential Service Water (ESW) inspection in August 1990, during the Safety Systems Functional Inspection (SSFI) in March 1992, and was documented as an open item in NRC Inspection Report 50-315/316/92003-01(DRS). The NRC identified that the 4.16 kV switchgear short-circuit momentary duty exceeded the circuit breaker capability by 21 percent for the worst-case condition. The open item was subsequently closed out in NRC

Inspection Report 50-315/316/94022(DRS) based on licensees commitment to review this issue and perform detailed short-circuit calculations to address the concern noted by the Electrical Distribution Safety Functional Inspection team.

During the 1997 extended plant shutdown, the NRC issued a violation to D. C. Cook for a corrective action program breakdown. The licensee made significant improvements in the corrective action program; however, the inspectors determined that from 1988 to 1999, little progress had been made to address this particular design issue. On April 5, 1999, the licensee initiated CR 99-07602. The CR stated that the 4.16 kV breakers were operable in all modes of plant operations and that the short-circuit fault duty of each 4.16 kV load feeder was required to be limited to the interrupting capability of its 250 MVA air circuit breakers, even for a 3-phase bolted fault. The CR concluded that the worst-case short-circuit overduty for the Unit 1 4.16 kV switchgear was 11 percent over the tested breaker capability for momentary duty and 12.8 percent for the symmetrical interrupting breaker rating which represent significant overduty.

Calculations 1-E-N-ELCP-4 kV-001 and 2-E-N-ELCP-4 kV -001, dated October 31, 2000, also confirmed that the potential fault current available on 4.16 kV load feeders could exceed the circuit breakers momentary interrupting capacity rating of 250 MVA.

The licensee opened Corrective Action Item No. 8 in CR 99-07602 to address this design deficiency. Corrective Action Item No. 8 had a due date of July 31, 2001, and required that an engineering study be performed to address this issue. Sargent and Lundy (S&L) performed an engineering evaluation and on March 27, 2001, issued a report which included actions needed to resolve this issue. The report revealed that a retrofit of the 4.16 kV switchgear to a 350 MVA rating was the most feasible solution and recommended a breaker upgrade. Subsequently, the licensee informed the NRC that the scope of the S&L study was too narrow and that the licensee had decided to expand the scope of the study to identify and evaluate other options beyond breaker upgrades.

On May 9, 2001, the licensee initiated CR 01129088 to expand the S&L study and evaluate more options for resolution of the 4.16 kV breaker short circuit overduty concerns. Corrective Action Item No. 8 was still open in October 2001.

The inspectors noted that the condition of the 4.16 kV system was contrary to UFSAR Section 8.1.2.d which states the 4160 volt transformer secondary feeds four independent 4160 volt auxiliary buses of each unit. The short-circuit fault duty on each bus is limited to within the interrupting capability of the 250 MVA air circuit breakers.

The inspectors assessed these findings relative to the problem identification and resolution cross-cutting area. The inspectors informed the licensee that failure to correct a design deficiency which was noted in 1988 and which could result in exceeding the 4.16 kV breakers momentary interrupting rating capability during a severe fault condition, constituted a Violation of 10 CFR Part 50, Appendix B, Criterion XVI. Because the licensee entered the finding into the corrective action program as CR 99-07602, this violation is being treated as a Non-Cited Violation in accordance with Section VI.A.1 of the NRC Enforcement Policy (NCV 50-315/01-19-04(DRP), 50-316/01-19-04(DRP)).

This violation is in the licensees corrective action system as CR 99-07602, dated April 5, 1999. The inspectors determined that the failure to adequately resolve this design deficiency could have a credible impact on safety if left uncorrected. This issue

affects the mitigating systems cornerstone. This issue screened as GREEN during the Phase 1 Significance Determination Process review because it did not present an actual loss of safety function and it did not result in an actual loss of Technical Specification related equipment. Also, the redundant electrical train which would not be affected by a common mode fault should be available.

4OA3 Event Follow-Up (71153)

.1 Licensee Event Reports a. Inspection Scope The inspectors reviewed the corrective actions associated with the following licensee event reports.

b. Findings (Closed) Licensee Event Report 50-315/99011-01: Air system for emergency diesel generators may not support long term operability due to original design error. This LER was discussed and closed in NRC Inspection Report 50-315/00-03; 50-316/00-03 as Restart Action Matrix Item 1.38. The licensee documented the error in Condition Report 99-3087. The supplement to the LER described the corrective actions taken to correct the problem, but the supplement did not identify any new issues. Therefore, this LER is closed.

(Closed) Licensee Event Report 50-316/00006-00: Failure to comply with requirements of Technical Specifications for nuclear instrumentation. On June 22, 2000, the licensee commenced low power physics testing on Unit 2, using the special test exception of Technical Specification (TS) 3.10.3, Physics Test. This TS required that the thermal power not exceed 5 percent of rated thermal power (RTP), and the reactor trip setpoints for the operable intermediate range neutron flux and the power range neutron flux low setpoints are set at less than or equal to 25 percent RTP. The power range instruments were found to have a setpoint greater than 25 percent RTP. This represented a failure to meet the requirements of TS 3.10.3. Additionally, the requirements of TSs 2.2.1 and 3.3.1.1 which govern the setpoints and operability requirements during Modes 1 and 2, were not met, resulting in an unrecognized entry into TS 3.0.3. The inspectors reviewed this issue of power range trip setpoints above the TS limit in NRC Inspection Report 50-315/00-16(DRP); 50-316/00-16(DRP). The inspection report discussed the licensees failure to set the power range NIs to less than or equal to the values required in TS 2.2.1 and identified a Non-Cited Violation 50-316/00-16-05. Details of this event and the corrective actions performed by the licensee are documented in Condition Report P-00-09197. This LER is closed.

(Closed) Licensee Event Report 50-315/00007-00, -01: ESF (engineered safety feature) ventilation system inoperable due to Technical Specification surveillance test methodology. This licensee identified issue was entered into the corrective action program as Condition Report P-00-11175. During an evaluation of industry operating experience information, OE11256, Control Room Emergency Filtration Inoperable Due to Testing Method, systems engineering personnel determined that the issue was

applicable to D. C. Cook Nuclear Plant. Specifically, licensee personnel determined that Technical Specification flow requirements for the ESF ventilation system could not be met during testing if the system automatically started from an accident signal.

Consequently, both trains of the ESF ventilation system would be inoperable when aligned for testing per the plant procedures while the plant was in Modes 1-4 when technical specification required both trains to be operable. The event was appropriately reported to the NRC as a condition prohibited by technical specifications.

Licensee personnel analyzed the event and determined that inadequate test procedures caused the technical specification non-compliance. However, licensee personnel concluded that the inadequate test procedures would not have adversely impacted the plants ability to mitigate the consequences of an accident and therefore had minimal safety significance. The inspectors reviewed the licensees analysis and did not identify and findings of significance. Consequently, this technical specification non-compliance constitutes a violation of minor significance that is not subject to enforcement action in accordance with Section IV of the NRCs Enforcement Policy. The inspectors also verified that the corrective actions documented in Condition Report P-00-11175 were reasonable and that the corrective actions had been completed. This licensee event report is closed.

(Closed) Licensee Event Report 50-315/01-01-00: Reactor trip due to loss of main feedwater pump. On February 15, 2001, with reactor power at approximately 100 percent, a low vacuum trip on the Unit 1 east main feedwater pump turbine occurred. Plant operators manually tripped the reactor in accordance with plant procedures. The licensee identified the cause to be a loss of condenser vacuum as the result of corrosion debris, a condition that lead to an elevated condenser backpressure and low vacuum trip of the pump. The licensees corrective actions were reviewed and considered adequate. The licensees corrective actions included the cleaning of both east and west main feed pump condensers. Details of this event are documented in licensee Condition Report 01046054. This LER is closed.

(Closed) Licensee Event Report 50-316/01-01-00: Plant shutdown due to control rod shutdown bank misalignment. On January 22, 2001, the licensee was performing a routine surveillance test of the Unit 2 rod control system. During the surveillance test, Shutdown Bank C would not respond to movement commands. The licensee entered TS action statement 3.1.3.1.b, which required that the plant be placed in Mode 3 (Hot Standby) within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Additional testing identified that Shutdown Bank D also would not respond to movement commands. Subsequently, the licensee performed an operability review and decided that the shutdown banks remained operable and that TS action statement 3.1.3.1.b should be exited. The licensee identified the cause to be an inadequate cleaning and inspection program that failed to ensure the proper tightening of terminal connection. The licensees corrective actions were reviewed and considered adequate. Corrective actions included tightening the loose connections and inspecting all terminal board connections. The inspectors discussed this event in NRC Inspection Report 50-315/01-02(DRP); 50-316/01-02(DRP). Details of this event are documented in Condition Report 01029009. This LER is closed.

(Closed) Licensee Event Report 50-315/01-04-00: Unit 1 entered Mode 3 with the remote shutdown panel pressurizer level instrument channel inoperable. On

September 27, 2001, during Unit 1 startup activities, Unit 1 was taken from Mode 4 to Mode 3 with the remote shutdown pressurizer level instrument 1-NLP-151 inoperable.

Although the licensee identified the instrument as inoperable in Mode 4, Unit 1 was taken to Mode 3 in violation of Technical Specifications (TS) 3.0.4. The licensee identified the cause to be human error. Plant operators improperly used the operability requirements for the reactor protection instrumentation Technical Specification TS 3.3.1.1, instead of the remote shutdown instrumentation Technical Specification TS 3.3.3.5. The licensees corrective actions were reviewed and considered satisfactory. A proposed amendment to the Unit 1 TS 3.3.3.5 has been submitted to the NRC. Details of this event and the corrective actions performed by the licensee are documented in licensee Condition Report 01270063. Although this issue was corrected, it constitutes a violation of minor significance that is not subject to enforcement action in accordance with Section IV of the NRCs Enforcement Policy. This LER is closed.

(Closed) Licensee Event Report 50-316/01-04-00: Reactor protection system (RPS)

actuation initiated by power range, neutron flux, high negative rate. On October 7, 2001, Unit 2 reactor tripped from 8 percent power as a result of a loss of rod control system voltage. The licensee identified the cause to be a failed resistor at the input to the north control rod drive motor generator set. The failed resistor was replaced. The licensees corrective actions were reviewed and considered satisfactory.

The corrective actions included the replacement of similar series resistors in the Unit 2 south control rod drive motor generator set. Details of this event are documented in licensee Condition Report 01280017. This LER is closed.

4OA4 Cross-Cutting Issues

.1 Human Performance Issues a. Inspection Scope The inspectors assessed licensee performance relative to the human performance cross cutting issue. As documented in Section 4OA7 below, the licensee identified two violations of NRC requirements during this inspection report period: (1) a violation of TS 3.9.7 requirements associated with inappropriate movement of loads over the spent fuel pool, and (2) failure to adequately implement procedural requirements for placing the Unit 1 "A" Train D/G in standby. The inspectors assessed the circumstances and causes of these issues relative to the human performance cross-cutting area.

b. Findings The inspectors identified a Finding of very low safety significance related to human performance weaknesses that contributed to the licensee identified violations documented in Section 4OA7. The human performance aspects of these issues were related to failures to follow procedural guidance, inadequate self checking, and the failure to perform adequate independent verifications. The inspectors considered the following in the assessment of this issue:

Failure to Adequately Control Movement of Loads of the Spent Fuel Pool On November 19, 2001, the licensee moved the rod control cluster assembly (RCCA) change out tool over racks containing spent fuel with the crane height interlock bypassed and the crane carrying a load above the interlock setpoint height limit. The crane height interlock setpoint was intended to limit the impact energy of a postulated dropped load to less than the maximum impact energy specified in TS 3.9.7. The licensee bypassed the crane height interlock in accordance with plant procedures to lift the RCCA change out tool above the interlock height limit to perform modifications to support the upcoming Unit 2 refueling outage. When the spent fuel pool crane height interlock was initially bypassed, the crane was positioned in the fuel transfer canal in an area away from spent fuel assemblies. Prior to lowering the RCCA change out to a height below the interlock setpoint and removing the interlock from bypass, the crane operator moved the spent fuel pool crane over spent fuel assemblies at a height which exceeded the TS 3.9.7 maximum impact energy limit. Although the licensee immediately identified and corrected this condition, the inspectors determined that several human performance errors led to this occurrence. Fuel handling procedure 12-OHP 4050.FHP.046, "Control of Loads over the Spent Fuel Pool," step 2.2 required that a qualified spent fuel area supervisor (SFPAS)

supervise the handling of loads over the spent fuel pool. Additionally, step 4.2 of 12-OHP 4050.FHP.046 required performance of an impact energy calculation to determine the height at which loads may be carried over the spent fuel pool.

The inspectors determined that the crane operator failed ensure that TS 3.9.7 impact energy limitations were met prior to movement of the RCCA tool over spent fuel. Additionally, the SFPAS failed to provide adequate oversight of crane operation during the period of time that the crane height interlock was bypassed.

The inspectors concluded that administrative controls intended to limit the probability of a fuel handling accident failed due to these human performance weaknesses.

The inspectors assessed the safety significance of the violation of the impact energy requirement of TS 3.9.7 using the SDP. Updated Final Safety Analysis Report (UFSAR) Section 14.2.1, "Fuel Handling Accident," analyzed the consequences of a load drop over spent fuel pool racks containing spent fuel.

Because the maximum TS 3.9.7 impact energy was intended to bound the fuel assembly damage following a postulated crane failure, the inspectors determined that this issue was associated with the barrier integrity cornerstone. The inspectors concluded that this issue had a credible impact on safety and was more than a minor concern. Movement of loads over spent fuel with an impact energy greater than the TS limits could result in damage to spent fuel greater than analyzed in the event of a credible crane failure. Because this issue was determined to affect the fuel integrity barrier, this issue was determined to be of very low safety significance (GREEN) following a Phase 1 SDP.

Failure to Adequately Align the Unit 1 "B" Train D/G for Standby Service During a shift turnover walkdown on December 9, 2001, the oncoming shift manager noted that the manual and automatic voltage regulator settings for the

Unit 1 "B" Train D/G failed to match the Technical Data Book (TDB) required settings. The licensee's investigation determined that following routine D/G surveillance testing on December 8, 2001, the operations crew failed to align the voltage regulator controls for standby service and failed to perform an adequate independent verification of the D/G alignment. Following surveillance testing, the D/G was aligned in standby in accordance with Procedure 01-OHP 4021.008AB,

"Operating D/G Unit 1 "B" Train Subsystems." Procedure 01-OHP 4021.008AB required an operator to initially position the automatic and manual voltage regulator potentiometers to the TDB required setting. After the initial positioning, the procedure required a second verification of potentiometer settings by a different operator. The licensee stated that the initial positioner adjusted the manual voltage potentiometer to the required automatic potentiometer setting and failed to adjust the automatic potentiometer back to its normal standby position. (The automatic voltage regulator potentiometer was adjusted during the previous surveillance test to minimize generator circulating currents.) The second reactor operator performing the independent verification failed to identify that neither the manual nor the automatic voltage regulator potentiometers were set to their required TDB positions. The inspectors concluded that the failure to adequately identify safety related equipment prior to manipulation, the failure to adequately follow procedural requirements, and the failure to adequately perform an independent verification constituted weaknesses in the human performance cross-cutting area.

The inspectors assessed the safety significance of this human performance issue using the SDP. The failure align the diesel generator voltage regulation system for standby service could result in the failure of the diesel generator to adequately provide power to supported equipment and therefore impacted the mitigating systems cornerstone. The inspectors determined that this was more than a minor concern because the failure adequately align the D/G for standby service and adequately perform an independent verification of D/G alignment could result in a more serious safety concern if left uncorrected. Specifically, the failure to adequately identify system components prior to manipulation and the failure to perform an adequate independent verification of D/G system alignments could credibly result in the failure of the D/G to perform its associated safety function. In this case, although the automatic voltage regulator potentiometer was set inconsistently with TDB requirements, the as-found potentiometer settings would not have prevented the D/G from performing its safety function. Because the failure to adequately align the Unit 1 "B" Train D/G did not result in an actual loss of safety function, this issue was also determined to be of very low safety significance (GREEN).

The inspectors assessed the safety significance of this cross-cutting issue using the Significance Determination Process (SDP) assessments for the resultant issues. The inspectors concluded that these human performance weaknesses had a credible impact on safety and could become a more significant safety concern if left uncorrected; therefore, these human performance weaknesses were more than a minor concern.

Therefore, the inspectors concluded that these human performance weaknesses constituted a finding of very low risk significance based on the safety significance of the

resultant issues and their impact to multiple cornerstones of reactor safety.

(Section 4OA4)

4OA6 Management Meetings The inspectors presented the Occupational Radiation Safety - Access Controls for Radiologically Significant Areas and Radiation Monitoring Instrumentation and Public Radiation Safety - Radiological Environmental Monitoring Program inspection results (Report Section 2) on November 15, 2001. The baseline inspection results for Changes, Tests or Experiments (Report Section 1R02) was presented on November 30, 2001. The inspectors presented the Security, Training and Qualification Plan inspection results (Report Section 3) on December 5, 2001. The inspectors presented the remaining inspection results to licensee management listed below on December 28, 2001. The licensee acknowledged the findings presented. No proprietary information was identified.

4OA7 Licensee Identified Violations The following findings of very low safety significance (GREEN) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section IV of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as Non-Cited Violations (NCV).

NCV Tracking Number Requirement Licensee Failed to Meet 50-315/01-19-06 TS 4.9.7.2, "Crane Travel - Spent Fuel Storage Pool 50-316/01-19-06 Building," requires, in part, that the potential impact energy due to dropping a crane's load be determined to be less than or equal to 24,240 in-lbs prior to moving each load over racks containing fuel. Contrary to this requirement, on November 19, 2001, the licensee moved the rod control cluster assembly (RCCA) change out tool over storage racks containing fuel without determining the impact energy of the load. The impact energy associated with the RCCA change out tool movement exceeded the TS limit of 24,240 in-lbs. This issue is in the licensee's corrective action system as CR 01323024 and is being treated as a Non-Cited Violation.

50-315/01-19-07 TS 6.8.1 requires, in part, that procedures shall be established, implemented and maintained covering the activities recommended in Appendix "A" of Regulatory Guide 1.33, Rev 2, February 1978. Operations Procedure 01-OHP-4021-032-008AB, "Operating D/G Unit 1 "B" Train Subsystems," was written to cover activities recommended by RG 1.33. Steps 4.1.6 and 4.1.9 of 01-OHP-4021-032-008AB required that the control room panel diesel generator voltage regulator potentiometer settings be verified to match the required settings specified in the

Technical Data Book. Contrary to the above, on December 8, 2001, the licensee failed verify that the Unit 1

"B" Train D/G control room panel diesel generator voltage regulator potentiometer settings matched the required settings. This issue is in the licensee's corrective action system as CR 01343015 and is being treated as a Non-Cited Violation.

KEY POINTS OF CONTACT Licensee G. Arent, Manger, Regulatory Affairs C. Bakken, Senior Vice President, Nuclear Generation M. Barfelz, Regulatory Affairs J. Carlson, Environmental Superintendent P. Cowan, Licensing Supervisor, Regulatory Affairs R. Gaston, Regulatory Affairs Compliance Supervisor J. Gebbie, System Engineering Manager S. Greenlee, Director, Nuclear Technical Services J. Harner, REMP Coordinator R. LaBurn, General Supervisor, Radiation Protection Production E. Larson, Manager, Operations R. Meister, Regulatory Affairs D. Moul, Assistant Manager, Operations D. Noble, Radiation Protection Manager T. Noonan, Director, Performance Assurance J. Pollock, Plant Manager M. Rencheck, Vice President, Strategic Business Improvement E. Ridgell, Regulatory Affairs B. Robinson, General Supervisor, Health Physics Support A. Rodriguez, Manager, Security/Support R. Smith, Assistant Director, Plant Engineering K. Steinmetz, Licensing 50.59 Program Owner L. Weber, Performance Assurance D. Wood, RadChem Environmental Manager NRC A. Vegel, Chief, Reactor Projects Branch 6 H. Gonzalez, Reactor Engineer D. Rivera-Martinez, Reactor Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-315/01-19-01 NCV Failure to ensure that breaker coordination and selective tripping 50-316/01-19-01 was provided at the 4.16kV system (Section 1R05)

50-315/01-19-02 NCV Failure to meet analytical detection capabilities for numerous 50-316/01-19-02 radiological environmental samples collected between the third quarter of 2000 and the first quarter of 2001 (Section 2PS3)

50-316/01-19-03 URI Apparent violation of 10 CFR Appendix B, Criterion V for the failure to incorporate adequate quantitative acceptance criteria in turbine driven auxiliary feedwater pump maintenance instructions (Section 4OA1)

50-315/01-19-04 NCV Failure to correct a long standing design deficiency associated 50-316/01-19-04 with 4.16 kV breakers momentary interrupting rating capability (Section 4OA2)

50-315/01-19-05 FIN Human performance weaknesses related to procedural 50-316/01-19-05 adherence and independent verification (Section 4OA4)

50-315/01-19-06 NCV Failure to maintain load carried over spent fuel within impact 50-316/01-19-06 energy requirements of TS 3.9.7 (Section 4OA7)

50-315/01-19-07 NCV Failure to appropriately align Unit 1 "B" Train D/G for standby following testing (Section 4OA7)

Closed 50-315/99011-01 LER Air system for emergency diesel generators may not support long term operability due to original design error (Section 4OA3)

50-316/00006-00 LER Failure to comply with requirements of Technical Specifications for nuclear instrumentation (Section 4OA3)

50-315/00007-00 LER ESF ventilation system inoperable due to TS surveillance test 50-315/00007-01 methodology (Section 4OA3)

50-315/01-01-00 LER Reactor trip due to loss of main feedwater pump (Section 4OA3)

50-316/01-01-00 LER Plant shutdown due to control rod shutdown bank misalignment (Section 4OA3)

50-315/01-04-00 LER Unit 1 entered Mode 3 with the remote shutdown panel pressurizer level instrument channel inoperable (Section 4OA3)

50-316/01-04-00 LER Reactor protection system (RPS) actuation initiated by power range, neutron flux, high negative rate (Section 4OA3)

50-315/01-19-01 NCV Failure to ensure that breaker coordination and selective tripping 50-316/01-19-01 was provided at the 4.16kV system (Section 1R05)

50-315/01-19-02 NCV Failure to meet analytical detection capabilities for numerous 50-316/01-19-02 radiological environmental samples collected between the third quarter of 2000 and the first quarter of 2001 (Section 2PS3)

50-315/01-19-04 NCV Failure to correct a long standing design deficiency associated 50-316/01-19-04 with 4.16 kV breakers momentary interrupting rating capability (Section 4OA2)

50-315/01-19-05 FIN Human performance weaknesses related to procedural 50-316/01-19-05 adherence and independent verification (Section 4OA4)

50-315/01-19-06 NCV Failure to maintain load carried over spent fuel within impact 50-316/01-19-06 energy requirements of TS 3.9.7 (Section 4OA7)

50-315/01-19-07 NCV Failure to appropriately align Unit 1 "B" Train D/G for standby following testing (Section 4OA7)

Discussed None

LIST OF ACRONYMS USED ADAMS Agency-wide Documents and Management System AEP American Electric Power ALARA As Low As Is Reasonably Achievable ATR Administrative Technical Requirement AV Apparent Violation CFR Code of Federal Regulations CR Condition Report CT Current Transformer DRP Division of Reactor Projects DRS Division of Reactor Safety ED Electronic Dosimetry EP Emergency Preparedness ESW Essential Service Water FIN Finding IMC Inspection Manual Chapter LERF Large Early Release Frequency LHRA Locked High Radiation Area LLD Lower Limits of Detection LOOP Loss of Offsite Power NCV Non-Cited Violation NRC Nuclear Regulatory Commission NRR Nuclear Reactor Regulation OA Other Activities ODCM Offsite Dose Calculation Manual OHP Operations Head Procedure PARS Publically Available Records PASS Post Accident Sampling System PDR Public Document Room PI Performance Indicator PJC Phase Instantaneous Current PMP Plant Managers Procedure PMT Post-maintenance Testing RCA Radiologically Controlled Area RCCA Rod Control Cluster Assembly REMP Radiological Environmental Monitoring Program RHR Residual Heat Removal RPS Reactor Protection System RTP Rated Thermal Power RWP Radiation Work Permit RP Radiation Protection SDP Significance Determination Process SRO Senior Reactor Operator SSA Safe Shutdown Analysis SSC Structures, Systems, and Components SSCA Safe Shutdown Capability Assessment SSPS Solid State Protection System STP Surveillance Test Procedure

TDAFWP Turbine Driven Auxiliary Feedwater Pump TLD Thermoluminescent Dosimeter TS Technical Specification UFSAR Updated Final Safety Analysis Report VIO Violation

LIST OF DOCUMENTS REVIEWED 1R01 Adverse Weather Protection 12-TM-00-61-R2 Winterization/De-Winterization TM to Revision 2 Support 12-IHP 5040.EMP.004 PMI 5055 Winterization/Summerization Revision 0 12-IHP 5040.EMP.004 Plant Winterization and De-Winterization Revision 3 1R02 Evaluation of Changes, Tests, or Experiments 10 CFR 50.59 Evaluations 2000-1069-01 Lake Temperature Project - CCW and July 7, 2000 ESW 12-DCP-174 2000-1140-00 Feeding 600 Volt Buses Through Bus June 3, 2000 Breakers 2-OHP 4021.082.003 2000-1143-01 Addition of Administrative Technical May 27, 2000 Requirements for Unit 2 EDGs ATR2-EDG-1 2000-1649-00 ESS Thermal Overload List August 18, 2000 2000-2063-01 Unit 1 Boric Acid Concentration Reduction December 2, 2000 Modification /UCR 99-UFSAR-1343 and 13 47 1-DCP 120 2000-2077-02 Winterization and De-Winterization 12 December 29, 2000 TM-00-61 2000-2319-00 Unit 1 Core Reload 1-DCP- 4872 November 6, 2000 2000-2446-00 Change of Safety Analysis UCR-1540 November 22, 2000 2001-0223-00 Add New Evaluation Results Pertaining to May 4, 2001 SBO Coping UCR-1458 2001-1008-00 Removal of Auto-Open Feature on Diesel September 12, 2001 Start for EDG Coolers Alternate ESW Valves Temp Mod 12-TM-01-52-RO, ODE CR-1242013

2001-1197-00 Allow ESW Flow Normally Through CTS November 1, 2001 HXs to Meet ESW Flow Requirements during Low Lake Water 1-DCP-5173 and 2-DCP-5174 (includes TS Bases 3/4.1.2 and 3/4.5.5 Change and UCR-1609 10 CFR 50.59 Screenings 2000-1963-01 Unit 1Motor Operated Valve (MOV) November 30, 2000 Setpoint Control Data Sheets -

Component Cooling Water VDS-1 ccm-430/431/432/433.Revision 0 and VDS-1-CMO-410/411/412/413 2000-2061-00 Unit 2 Feed Pump Room Cooler ESW October 9, 2000 Return Valves Installed Backwards CR 00-09639 (Use-As-Is)

2000-2129-00 Safety Related Pump Inservice Test October 12, 2000, Hydraulic Reference Tech Databook Figure 1-15.1 2000-2263-01 Removal of Inner Debris Screens From November 8, 2000 EDG Intake Ventilation System Duct Work 1-LDCP-4889 2000-2490-00 Power Operated Valve Stroke Time Limits November 25, 2000 Technical Data Book Figure 1-19.1 2001-0013-00 Loss of All Offsite Power 01-OHP 4023. January 17, 2001 ECA-0.0, 2001-0378-00 Under 2-DCP-4908, the Unit 2 ECCS May 16, 2001 MOVs 2-IMO-255, 256 and 2.ICM-250, 251 will be Modified to Reduce the Stem Diameter in Order to Improve Valve Operation 2-DCP-4908 2001-0519-00 Annunciator #134 Response: Spent Fuel April 1, 2000 Pit 12-OHP 4024-134 2001-0575-00 Comp Action for Degraded 1-1A5 Breaker July 5, 2001 1-1A5 2001-0626-00 Locating 250 VDC Grounds 12-OHP August 2, 2001 4021-005-012, 2001-1033-00 Increase Structural Integrity of the Unit 2 September 12, 2001 ESW Strainers 2-LDCP-5147

2001-1214-00 Fuel Transfer Pump HELB Protection 1- October 30, 2001 DCP-5021 2001-1266-00 Revise Setting of Differential Relays for October 26, 2001 4kV/600V Transformers Relay Setting Sheets RSC1-4072, Etc.

2001-1278-00 Operation of the Boric Acid Reserve Tank October 23, 2001 12-OHP 4021-005-008 Condition Reports CR 00293063 12 4021.006.002 Allows Deenergization of October 19, 2000 Conductivity Cell Which May Not Have Been Evaluated in 10 CFR 50.59 CR 00318068 Unit Technical Specifications Bases November 13, 2000 Change for Spray Additive Test Parameters Did Not Have a Complete Safety Evaluation CR 01039036 Potential 10 CFR 50.59 Bypass in PMP- February 8,2001 7030-OPR-001, Operability Determination in Providing Guidance for the SS/SM to Implement Required Compensatory Measures PRIOR to Completing a 10 CFR 50.59 Review CR 01114018 Calculations for Spent Fuel Pool April 24, 2001 Performed Using Methodology Not in Compliance With the CNP Current Licensing Basis Issued as Unrestricted Without a 10 CFR 50.59 Review CR 01221046 The Validation to Use Safety August 9, 2001 Screening/Safety Evaluation (SS/SE)

1999-1608-01(2-DCP-4247) for SS/SE 2000-1468-00(1-DCP-4247) Did Not Address Effects of the LOOP in the Winter on Unit 1 "B" Train Battery CR 01265020 Instrument Change Package ICP-00758, September 22, 2001 Revision 0, Does Not Contain All Relevant Data CR 01284045 A 10 CFR 50.59 Screen Was Determined October 11, 2001 to Be Inadequate (10 CFR 50.59 Tracking Number 2001-0729-00)

CR P-00-09957 DIT S-00625-00 Changed the AFW Room July 14, 2000 Cooler Setpoint Without an SE or SS and Without Evaluation of Potential Cooler Freeze Conditions at Higher ESW Flowrates than Test Qualification. The Temperature Switch is Not on Appropriate Plant Control Lists 1R04 Equipment Alignment (71111.04)

TS 3.6.2.1 Containment Spray System Amendment 188 OP-2-5144 Flow Diagram - Unit 2 Containment Spray 01-OHP 402.032.008AB Operating DGUnit 1 "B" Train Subsystems Revision 2 01-OHP 5030.001.001 Operations Plant Tours Revision 19a 02-OHP 4021.009.001 Placing the Containment Spray System in Revision 6b Standby Readiness Technical Data Book Diesel Generator Pot Settings Revision 20 1-Figure 19.9 CR 01339050 The door between the control rooms, 12- December 5, 2001 DR-AUX415, was found in the open position CR 01216057 Received low control air pressure August 4, 2001 annunciator during surveillance testing 1R05 Fire Protection

.1 Fire Protection Safe Shutdown Analysis Calculations 1-E-N-PROT-RLY-002 4kV SR Motors Phase Instantaneous Revision 0 Relay (PJC) Setting Calculation, U1 1-E-N-PROT-BKR-007 U1 600V SWGR Breaker 11A6, 11A7, August 14, 2000 11B3, 11C3, 11C9, 11C8, and 11D9 Settings 1-E-N-ELCP-4 kV-001 U1 4.16 kV/600V Load Control Calcs October 31, 2000 2-E-N-ELCP-4 kV-001 U2 4.16 kV/600V Load Control Calcs January 14, 2000 2-E-N-PROT-RLY-002 4.16 kV SR Motors Phase Instantaneous February 15, 2000 Relay (PJC) Setting Calculation, U2

Drawings OP-2-12003 25O VDC Main One-Line ESF Train A, B, Revision 23 and N 1-1412-27,1-1421-80, 1- Conduit Routing 1428-32, 1-1431-34, 1-1433-23,1-1435-81, 1-2074-34,1-2037-49 Condition Reports CR P-00-03109 This CR Documents Superceded February 23, 2000 Calculations, Uninstalled DCPs, Limitation, Equipment Not Meeting Acceptance Criteria and Recommendations in Calc. 2-E-N-ELCP-4.16 kV-001, Revision 1 CR P-99-18634 Discrepancy in Electrical Protection July 16, 1999 Calculations CR 01129088 S&L Study to Resolve 4.16 kV Switchgear May 9, 2001 Short Circuit Overduty Concerns was OARd with Comments CR P-99-07602 Calculation PS-4.16 kVD-002 Shows that April 5, 1999 the Momentary Ratings on the 4.16 kV Circuit Breakers are Exceeded for Fault Conditions CR P-00-01627 Discrepancy with FSAR Q&A 40.7 January 28, 2000 CR P-00-09424 Instrument Overcurrent Settings for June 29, 2000 Several 4.16 kV ESS Pump Motors May Require Revision CR P-00-02519 Instantaneous Overcurrent Relay Settings February 11, 2000 for the AFW-2W, AFW-2E, CTS-2W and ESW-2W Pump Motors May Require Revision Procedures EHI-2070 Engineering Support Personnel (ESP) Revision 0a Training and Qualification PMI-1030 Personnel Selections and Administrative Revision 4 Controls Miscellaneous

AEP Engineering Position Description January 1, 1997 Matrix ANSI N18.1-1971 Selection and Training of Nuclear Power Plant Personnel AEP Exempt Summary Job Description VTD-GENE-1188 General Electric Instructions for May 27, 1996 Instantaneous Current Relays Type PJC (Pub. #GEH=1790B)

GEH-1753 Time Overcurrent Relays PS-EPCS-001 Electrical Protection Coordination Study CRs Initiated as a Result of NRC Questions CR 01129088 S&L Study to Resolve 4.16 kV Switchgear May 9, 2001 Short Circuit Overduty Concerns to be Expanded Options Other than Replacement of Existing Overduty Breakers CR 01208057 The Impact Assmt for Calculations 1-E-N- July 27, 2001 PROT-RLY-002 and 2-E-N-PROT-RLY-002 Fail to Identify the Impact on the Appendix R Program

.2 Routine Fire Zone Tours UFSAR Section 7.7.6 Control Room Fire Prevention Design UFSAR Section 9.8.1 Fire Protection System D. C. Cook Nuclear Plant Fire Hazards Revision 8 Analysis, Units 1 and 2 D. C. Cook Nuclear Plant Units 1 and 2 February 1995 Probabilistic Risk Assessment, Fire Analysis Notebook Fire Hazards Analysis Fire Zone 7, Quadrant 1 Cable Tunnel ESAT 01352053 NRC identified a 3' rope hanging from the December 18, 2001 bottom of ventilation louver PMP 2270.CCM.001 Control of Combustible Materials Revision 1 PMP 2270.FIRE.002 Responsibilities for Cook Plant Fire Revision 0 Protection Program Document Updates PMP 2270.WBG.001 Welding, Burning and Grinding Activities Revision 0

PMI 2270 Fire Protection Revision 26 PA-01-10 Performance Assurance Audit, Fire November 13, 2001 Protection 1R11 Licensed Operator Requalification RQ-E-1717 Cook Nuclear Plant Simulator Evaluation Revision 4 Guide, Steam Generator Tube Rupture with Loss of Reserve Power Desktop Guide For Emergency Planning Revision 1 Performance Indicators Simulator Crew Evaluation Standards Operating crew performance evaluation comments 1R12 Maintenance Rule Implementation

.1 Annunciator System Maintenance Rule Scoping Document August 28, 2001 Annunciator System Unit 1 and Unit 2 Blocked Alarm Index November 27, 2001 CR 00345028 Source range level trip bypass December 10, 2000 annunciator came in and cleared with no alarm or operator action ESAT 00353035 Annunciator 1-30cd-cdap-8 does not December 18, 2000 annunciate when tested CR 01107036 Annunciator maintenance rule scoping April 17, 2001 document does not address cumulative failures ESAT 01117050 Fire panel Unit 1 30-RS-RSAP April 27, 2001 annunciator ground when tested CR 01143065 Annunciator 122 drop 29 came in and May 23, 2001 cleared with no audible tone CR 01226026 Licensee identified that maintenance August 14, 2001 rule evaluation for CR 00-10013 was inadequate

CR 01226027 Licensee identified that maintenance August 14, 2001 rule review for annunciator system was inadequate CR 01249091 Annunciator bus ground alarm drop 40 September 6, 2001 panel 121 illuminated CR 01289053 Control room annunciator panel 101, October 16, 2001 drop 22, failed to light during performance of 12-PPP-2270-066-019 CR 01323025 Evaluate all abnormal positions and November 19, 2001 blocked alarms in place for greater than 30 days to determine if 50.59 evaluation is required CR 01325007 Ice condenser door open annunciator November 21, 2001 did not alarm when personnel entered ice condenser CR 01332080 Annunciator 204 drop 4 reflashed November 28, 2001 several times while clearance 2013443 was in effect. The annunciator should not have reflashed

.2 Reactor Protection System Maintenance Rule Scoping Document May 11, 2001 Reactor Protection System CR 00350032 1-BLP-140 reading at the 6 percent December 15, 2000 notification limit CR 01009034 Integrated results of the Maintenance January 9, 2001 Rule recovery project for the reactor protection system CR 01018035 1-NTI-22 did not return to normal due to January 18, 2001 faulty test injection switch (1-PS-456Q)

CR 01018038 1-NTI-42 did not return to normal due to January 18, 2001 faulty test injection switch CR 01040013 During replacement of the Unit 1 Train B February 8, 2001 logic power supply, the 15 V power supply failed and caused the B train reactor trip breaker to open CR 01140002 2-FFC-241 #4 S/G flow control May 20, 2001 transmitter Channel 2 partially failed

CR 01196010 Train A solid state protection system July 14, 2001 PS2 breaker tripped unexpectedly during fuse removal for replacement of 48 volt power supply PS1 causing a loss of all Train A 15 volt power CR 01212017 During replacement of power supply 1 in July 31, 2001 Unit 1 Train A SSPS, status lights and annunciators flashed unexpectedly when the input error inhibit switch was placed in inhibit CR 01220032 During a historical review of preventative August 8, 2001 maintenance items, it was determined that four PMs were completed with out of specification conditions and a new ESAT was not initiated.

CR 01236037 There have been a significant number of August 24, 2001 electronic DC power supply failures in the past 24 months CR 01282031 2-MPP-212 was found out of tolerance September 19, 2001 during as found calibration check CR 01296002 2-NTI-12 (Loop 1 overtemperature delta October 23, 2001 T) indicator became erratic CR 01341105 NRC identified that MR evaluation for a December 7, 2001 failure of 2-FFC-241 failed to consider functions associated with reactor protection system and RG 1.97 CR 01341104 NRC identified that there was no MR December 7, 2001 evaluation for out of calibration condition for 1-BLP-140.

.3 Emergency Diesel Generators Maintenance Rule Scoping Document - Revision 2 Emergency Diesel Generators Emergency Diesel Generator Performance Monitoring Plan System Health Report - Emergency July 1, 2001 through Diesel Generators September 30, 2001

TS 3.8.1 AC Sources - Operating Amendment 183 (Unit 1)

Amendment 168 (Unit 2)

Regulatory Guide 1.9 Selection, Design, Qualification, and Revision 3 Testing of Emergency Diesel Generator Units Used as Class 1E Onsite Electric Power Systems at Nuclear Power Plants RG 1.155 Station Blackout Revision 0 UFSAR Section 8.4 Emergency Power System Revision 17 PMI 6080 Emergency Diesel Generator (EDG) Revision 3 Reliability Monitoring Program 12-MHP 4030.032.046 Emergency Diesel Generator System 18 Revision 2 Month Inspection CR 01136042 Presentation to Maintenance Rule May 16, 2001 Expert Panel for Unit 1 emergency diesel generators to be considered for (a)(1)

CR 01257072 When running STP.027 (under full load), September 14, 2001 the output of the diesel generator was fluctuating CR 01258009 Attempted start of DG2CD failed when September 15, 2001 DG2CD Stop/Run control switch was taken to RUN

.4 Compressed Air System Maintenance Rule Scoping Document - Revision 1 Compressed Air System System Health Report - Compressed Air July 1, 2001 through September 30, 2001 1R13 Maintenance and Emergent Work (71111.13)

NUMARC 93-01 Industry Guidelines for Monitoring the Revision 2 Effectiveness of Maintenance at Nuclear Power Plants Operations Night Orders November 20, 2001

PMP 2291.OLR.001 On-Line Risk Management, Work November 16, 2001 Data Sheet 1 Schedule Review and Approval Form, Cycle 39, Week 5 1R15 Operability Evaluations Unit 1 Control Room Logs November 27 -28, 2001 12-IHP-4030-082-003 AB, CD and N-Train Battery Discharge Test and 18-Month Surveillance Requirements 12 QHP.SP.001 Determination of Accumulator Water Revision 0 Level Utilizing Ultrasonic Measurement 01-OHP 4030.STP.030 Daily and Shiftly Surveillance Checks Revision 34 Technical Data Book Accumulator Level Conversion May 18, 1992 Figure 12- Figure 18.6 ECP 12-I1-02 Accumulator Tank Level and Pressure Revision 9 Transmitter Calibration VTD-CDBA-0001 Vendor Technical Data - C&D Charter Power Systems Standby Battery Vented Cell Installation and Operating Instructions EPRI TR-100248-R1 EPRI - Stationary Battery Guide Design, Application, and Maintenance JO R0221335 Job Order - Perform 2-BATT-AB, 92-day surveillance CR 01332066 1-ILA-111 Unit 1, Accumulator 1 level is November 28, 2001 oscillating between 934 and 940 cubic feet CR 01347067 Internal Degradation found on cells of December 13, 2001 Unit 2 Battery 2-BATT-AB during performance of surveillance R221335-01, 92 day surveillance of 2-BATT-AB CR 01353053 The accumulator volume calculations December 19, 2001 may not have accounted for cladding thickness. This could result in non-conservative results for ultrasonic level measurement

1R16 Operator Workarounds (71111.16)

Unit 1 Operations Daily Status Report December 18, 2001 Unit 1 Control Room Deficiency Report November 28, 2001 Unit 1 Caution Tag and Abnormal November 28, 2001 Position Logs CR 01264048 Unit aggregate operability determination September 21, 2001 for restart 1R17 Permanent Plant Modifications

.1 Emergency Diesel Generator High Pressure Fuel Injection Lines 12-EHP 5040.DES.001 Control of Design Input Revision 1 12-EHP 5040.MOD.006 Design Change Packages Revision 5a 12-MHP 5021.032.018 Emergency Diesel Engine Fuel Injection Revision 5a Maintenance 12-MHP 5021.032.051 Nova Swiss Fuel Injector Line Revision 0 Maintenance MPR-2011 Root Cause Investigation of Diesel Revision 0 Engine High Pressure Fuel Injection February, 1999 Line Failures 1-DCP-744 Upgrade of EDG High Pressure Fuel Injection Lines 2-DCP-526 Upgrade of EDG High Pressure Fuel Injection Lines Drawing INT-1025-040-01 Worthington SWB-12 High Pressure Revision A Fuel Injection Lines JO 01046018 Install 2-DCP-526 on 2 CD emergency September 14, 2001 diesel generator CR 98-6950 In house and third party reviews of EDG November 13, 1998 fuel line failure root cause analysis have identified weaknesses in the analysis CR 01200015 DRB review of 2-DCP-526 noted July 19, 2001 inadequate supporting calculation

.2 Provide Essential Service Water Flow Path via the Containment Spray Heat Exchangers for Units 1 and 2 2-DCP-5174 Design Change Package - Unit 2 November 2, 2001 Provide Essential Service Water Minimum Flow Path via Containment Spray Heat Exchanger 1-DCP-5173 Design Change Package - Unit 1 November 2, 2001 Provide Essential Service Water Minimum Flow Path via Containment Spray Heat Exchanger 12-OHP-4021-019-001 Operation of the Essential Service Revision 24 Water System 01-DCP-5173-TP1 Functional Test of 1-WMO-713 and 1- Revision 0 WMO-717 DIT-B-00011-06 Accident Analysis Input Assumptions for Containment Sump Water Level Analysis DIT-B-02219-00 Evaluation of the Effect of Open Containment Spray Heat Exchanger Essential Service Water Shutoff Valves (WMO-713, -717, -714, -718) on the Hydrogen Sub-compartment Analyses for DBA LOCA DIT-B-00069-08 Design Input for D.C. Cook Offsite and Control Room Dose Analyses Unit 1 UFSAR Chapter 14 Unit 1 Updated Final Safety Analysis Report - Accident Analysis Unit 2 UFSAR Chapter 14 Unit 2 Updated Final Safety Analysis Report - Accident Analysis NRC Safety Evaluation Report for March 19, 2001 Amendment No. 252 to DPR-58 RG 1.187 NRC Regulatory Guide - Guidance for November 2000 Implementation of 10 CFR 50.59, Changes, Tests and Experiments CR 01263055 Condition Report - Review of September 20, 2001 Westinghouse Letter AEP-01-119 identifies issues requiring at least tracking attention

CR 01353051 Condition Report - Questions to the EQ December 19, 2001 Checklist for 2-DCP-5174 and 1-DCP-5173 were incorrectly answered leading to the conclusion that further EQ review was not necessary CR 01354092 Condition Report - Need to define December 20, 2001 approach to UFSAR updating for LOCA peak clad temperature changes and associated evaluations CR 01355076 NRC identified that DCP-5173/5174 December 21, 2001 (Attachment 5) indicates the maximum combined CCW and CTS HX flow should not exceed 5000 gpm - the normal operating procedure does not reflect this limit 1R19 Post Maintenance Testing

.1 Unit 1 Accumulator Level Alarm Temporary Modification CR 01296004 2-ILA-111 indicated level fluctuations of October 23, 2001 10 cubic feet in #1 accumulator which brought in the low level alarm JO 01320005 2-ILA-111, Install 2-TM-00-54-R1 November 17, 2001 2-TM-00-54-R1 Alleviate unstable indication and Revision 1 spurious alarms from 2-ILA-111. November 16, 2001

.2 Unit 1 A Train Battery Charger Repair 01-OHP 4021.082.006 Operation of 1AB and 1CD Battery Revision 9 Chargers JO 01341004 1-BC-CD2, Replace K301 relay December 7, 2001

.3 Unit 2 Containment Spray Heat Exchangers Essential Service Water Outlet Valves JO 01296060 Implement 2-DCP-5174, Alternate Flow November 30, 2001 Path for Essential Service Water 02-DCP-5174-TP1 Completed Functional Tests of 2-WMO- Revision 0 714 and 2-WMO-718 CR 01333071 Condition Report - 2-WMO-714 Did Not November 29, 2001 Meet Acceptance Criteria for 02-DCP-5174-TP1

2-FCN-5174-R0-01 Field Change Notice - Revise Step 7.2.2 November 29, 2001 of Procedure 02-DCP-5174-TP1 2-FCN-5174-R0-02 Field Change Notice - Valve Control November 29, 2001 Circuits were not Designed to Support Referenced Test Statement in Acceptance Criteria for 02-DCP-5174-TP1 2-DCP-5174 Design Change Package - Unit 2 November 2, 2001 Provide Essential Service Water Minimum Flow Path via Containment Spray Heat Exchanger DB-12ESW Design Basis Document - Essential Revision 0 Service Water System

.4 Unit 1 A Train Emergency Diesel Generator Control Air Regulating Valve TS 3.8.1 AC Power Sources - Operating Amendment 183 01-OHP 4030.STP.027CD CD Diesel Generator Operability Test Revision 17 (Train A)

JO 01355003 Remove and replace 1-XRV-237 December 21, 2001 1R22 Surveillance Testing

.1 Steam Generator Stop Valve Dump Valve Surveillance Test 01-OHP 4024.113 Annunciator #113 Response: Steam Revision 6 Generator 1 and 2 01-OHP 4030.STP.018 Steam Generator Stop Valve Dump Revision 14 Valve Surveillance Test 01-OHP 4030.STP.019F Steam Generator Stop Valve Operability Revision 3 Test Technical Data Book Stroke Times by Valve Revision 60 Figure 19.1-1 UFSAR Section Pipe Break Blowdown Spectra and Revision 17.1 14.3.4.4.2.1 Assumptions UFSAR Table 14.2.5-2 Time Sequence of Events Double Ended Revision 16.4 Rupture Inside Containment With Offsite Power Available JO R0071578 Perform **12-EHP 4030.STP.257, December 16, 2000 Steam Generator Stop Valve ESF Test

.2 Unit 2 Daily and Shiftly Surveillances D. C. Cook Nuclear Plant Unit 1 and Unit 2 Technical Specifications 02-OHP 4030.STP.030 Daily and Shiftly Surveillance Checks Revision 38

.3 Unit 1 Nuclear Instrumentation Functional Checks TS 3.3.1.1 Reactor Trip System Instrumentation Amendment 202 01-IHP 4030.SMP.131 Power Range Nuclear Instrumentation Revision 0 Functional Test and Calibration

.4 Unit 1 Ice Condenser Tour TS 3.6.5.3 Ice Condenser Doors Amendment 144 PMP 4010.CAC.001 Containment Access Control Revision 1 02-OHP 4030.STP.030 Ice Condenser Tour Data Sheet Revision 38 Data Sheet 19 20S1 Access Control to Radiologically Significant Areas Condition Reports CR 01003029 Declining Trend in High Radiation Area January 3, 2001 Controls CR 01009041 Exposure of Personnel to Unanticipated January 5, 2001 High Radiation Area CR 01147002 Posting for High Radiation Area Found May 5, 2001 Missing CR 1278044 High Radiation Area Found During October 5, 2001 Surveillance Procedures and Surveillance Records PMI 4090 Criteria for Conducting Infrequently Revision 6 Performed Tests or Evolutions PMI 6010 Radiation Protection Plan Revision 11b PM -6010. ALA.001 ALARA Program - Review of Plant Work Revision 11 Activities PM -601.RPP.-003 High, Locked High, and Very High Revision 10 Radiation Area access

RP-014-01 Total Effective Dose Equivalents, Revision 0, C1 Calculation Data Sheet, 2-FTPL-Upender Re-work THG.015 RP Job Coverage Coordinator (JCC) Revision 1 Expectations 12-THP 6010.RPP.006, Radiation Work Permit (RWP) Revision 17 Data Sheet 1 Processing, Task 01 and 02, Pre-job ALARA Briefing Checklist 12-THP 6010.RPP.018 Controls for Radiological Risk Significant Revision 0 Work Activities 12-THP-6010.RPP.018, Radiological Risk Significant Work Brief Revision 0 Data Sheet 1 Checklist 12-THP 6010.RPP.018, ALARA Plan Template, Dive Repair of Revision 0 Data Sheet 3 U-2 Upender Clevis 12-THP 6010.RPP.018, Pre-Dive Checklist Revision 3 Data Sheet 5 12-THP 6010.RPP.413 Radiological Controls for Nuclear Diving Revision 3a Operations 12-THP 6010.RPP.413, Radiological Controls for Nuclear Diving Revision 3a Data Sheet 1 Operations, Pre-Dive Planning and Setup Checklist 12-THP 6010.RPP.413, Radiological Controls for Nuclear Diving Revision 3 Data Sheet 1 Operations, RP Pre-Dive Checklist 12-THP 6010.RPP.703 Monitor Alarm Response and Personnel Revision 10 Decontamination, Log Sheets for CY 2001 12-THP 6020.CSP.203 BORAL Surveillance Program Revision 1 RWP 01-1047 Perform Dive Activities in the Fuel Revision 1 Transfer Canal Radiation Protection ALARA Plan, Fuel Revision 0 Transfer Canal Dive, Re-work Upender Cables/Clips Miscellaneous Data TS 6.12 High Radiation Area Amendment 245 BORAL Coupon Tree Sampling, IPTE November 14, 2001 Briefing Guide

Operations Night Orders November 14, 2001 Radiation Protection Department Key November 15, 2001 Logs, Previous Twelve Month Records (December 2001 to November 2001)

Spent Fuel Pool Surveys (Pre-job, During, and upon Completion of Dive)

Self-Assessments PA-01-14 Radiation Protection March 16, 2001 Field Observation Logs January through October 2001 2OS3 Radiation Monitoring Instrumentation Condition Reports CR P-99-25781 Errors in USAR/Tech Specs October 21, 1999 Documentation CR P-99-29165 USAR Contains Inconsistent Alarm December 15, 1999 Values CR 01143016 Inaccurate Test Results from PASS May 23, 2001 Hydrogen Analyzer Procedures CH-O-706A PAS Sampling (PH, 02,Count., ATM) November 14, 2001 Training Qualification Matrix CH-O-706B PAS Sampling (H2, TG, B) Training November 14, 2001 Qualification Matrix CH-O-706C PAS Sampling (Back-up PAS Sampling) November 14, 2001 Training Qualification Matrix 12-THP 6010.RPC.552 Calibration of the DMC-2000 Electronic Revision 1 Dosimeter 12-THP 6010.RPC.552, Calibration of the DMC-2000 Electronic Revision 1 Data sheet 1 Dosimeter, EDs #165618 and #162674 12-THP 6020.PASS.612 PASS Dilute Liquid Sampling Revision 0 Miscellaneous Data TS 6.12 High Radiation Area Amendment 245 TS 6.8.3 PASS Requirements Amendment 210

UFSAR Section 7.8 Post-Accident Monitoring July 1992 Instrumentation UFSAR Section 11.3.3 Radiation Monitoring, PASS July 1997 Instrumentation TS 3/4.3.3 Monitoring Instrumentation Amendment 60 2PS3 Radiological Environmental Monitoring and Radioactive Material Control Programs Condition Reports CR 00243086 Vendor Having Limited Capability to August 29, 2000 Analyze REMP Samples CR01110029 Vendor for Analyzing REMP Samples April 20, 2001 Still Having Limited Capability to Analyze Samples CR 01235021 REMP Air Sampler Exhaust Needs to Be Re-routed CR 01312052 Vegetation Around REMP Air Sampling Location Affecting Sample Results CR01136059 Potentially Contaminated "Out of May 8, 2001 Calibration Period" Gauge, Sent to Vendor Procedures and Surveillance Records PMP 6010 OSD .001 Off-site Dose Calculation Manual Revision 16 PMP-6010-RPP-301 Control of Material in a Restricted Area Revision 14 RP-TB-001 Evaluation of the Use of the Bicron NE Revision 0 Small Article Monitor (SAM-11) for Unconditional Release of Material from a Restricted Area 12IHP6030.IMP.333 Meteorological Instrumentation Revision 3 CS-1 Calibration 12-THP-6010-RPP-301 Radiation Protection Actions for Revision 0 Restricted Area Material Control 12-THP-6010-RPP-514 Calibration of the AVS-28A with the Revision 2 AVT-100 Air Volume Totalizer 12-THP-6010-RPP-630 Collection of REMP Surface Water Revision 2b Samples

12-THP-6010-RPP-632 Collection of Environmental Samples Revision 4a 12-THP-6010-RPP-642 Collection of Drinking Water Samples Revision 2 Miscellaneous Data D.C. Cook Nuclear Plant REMP Air Sample Pump Calibrations CY 2001 Sample collection data sheets 12IHP6030.IMP.333, data Meteorological Instrumentation July 17, 2000 to sheets Calibration, Primary/Backup October 10, 2001 Instrumentation D.C. Technical Radiological Environmental Monitoring Amendment 245 Specifications, Program Administrative controls Paragraph 6.0 Self-Assessments and Field Observations PA-99-06/NSDRC #266 Radiological Environmental Monitoring June 2, 1999 Program (REMP)/Off-site Dose Calculation Manual PA-00-07/NSDRC 277 Radiological Environmental Monitoring May 26, 2000 Program(REMP)/Off-site Dose Calculation Manual (ODCM)

3PP4 Security Plan Changes Revision 1 Cook Nuclear Plant Security Training October 31, 2001 and Qualification Plan 4OA1 Performance Indicator Verification

.1 Unit 2 Turbine Driven Auxiliary Feedwater Pump Fault Exposure 12-MHP 5021.056.007 Turbine Driven Auxiliary Feed Pump Revision 2, CS 4 Trip and Throttle Valve Linkage Revision 2, CS 5 AR 0107471 Adjust trip and throttle valve on Unit 2 January 8, 1997 TDAFP JO C0052930 2-DCP-617, Rework TDAFP Turbine June 14, 2000 Governor CR 01222001 Unit 2 TDAFP failed to start on two August 10, 2001 consecutive start attempts

CR 01354104 Document prompt operability December 20, 2001 determination for Unit 1 and 2 TDAFWP trip throttle valve latch faces CR 01362027 NRC identified that a condition report December 28, 2001 was not written to document the June 2000 failure of the Unit 2 TDAFWP trip throttle valve VTD-SKIN-0001 Schutte and Koerting Installation and Operating Instructions for Motor Operated Trip Throttle Valve Unit 2 Control Room Logs EPRI TR 105874 Terry Turbine Maintenance and Troubleshooting Guide

.2 Safety System Unavailability D. C. Cook Nuclear Plant Unit 1 and Unit 2 Technical Specifications NEI [Nuclear Energy Regulatory Assessment Performance Revision 1 Institute] 99-02 Indicator Guideline Plant Managers Regulatory Oversight Program Revision 1 Procedure 7110.PIP.001 Performance Indicators D. C. Cook Maintenance Rule December 7, 2001 Database Two-Year Unavailability Report for the Emergency Diesel Generators System D. C. Cook Maintenance Rule December 7, 2001 Database Two-Year Unavailability Report for the Emergency Core Cooling and Residual Heat Removal Systems D. C. Cook Maintenance Rule December 7, 2001 Database Two-Year Unavailability Report for the Auxiliary Feedwater System Daily Shift Managers Logs October 1, 2000 through September 1, 2001

Condition Report (CR) Action Request Generated to January 29, 2001 01029040 Document Basis for Not Counting Unavailability Time When Rolling an Engine Over to Check for Moisture in the Cylinders CR 01355058 NRC Identified Inconsistent Reporting December 21, 2001 of Unavailable Hours for the Maintenance Rule and the Reactor Oversight Process for the Same Conditions CR 01355064 NRC Identified Emergency Diesel December 21, 2001 Generator Unavailable Hours Are Not Being Reported During Carbon Dioxide Fire Suppression Testing CR 01355071 NRC Identified Safety System December 21, 2001 Unavailable Hours Reported in the Reactor Oversight Process for the 4th Quarter 2000 and 1st Quarter 2001 Were Reported for the Wrong Train CR 01355072 NRC Identified Hours Reported in the December 21, 2001 Reactor Oversight Process for the Auxiliary Feedwater System Did Not Account for the Appendix R Safety Function When the Opposite Unit Was in Mode 3 or Above

.3 Occupational Exposure Control Effectiveness and Radiological Effluent Technical Specification (RETS)/ODCM Radiological Effluent Occurrence PIs PMP 7110.PIP.001 Regulatory Oversight Program Revision 1 Performance Indicators PMP 7110.PIP.001, Data Regulatory Oversight Program Revision 0 sheet 14 Performance Indicators, "Occupational Exposure Control Effectiveness Documentation Packets, CY 2000, 4th Quarter, CY 2001, 1st , 2nd , and 3 rd Quarter(s),

PMP 7110.PIP.001, Data Regulatory Oversight Program Revision 0 sheet 15 Performance Indicators, "RETS/ODCM Radiological Effluent Occurrences Exposure Control Effectiveness Documentation packets, CY 2000, 4th Quarter

Performance Indicator Verification November 11, 2001 Summary Sheets, "Occupational Exposure Control Effectiveness, Effluent Water dose-Mixed Fission Products, and Effluent Airborne Dose-Total Body" 4OA3 Event Follow-up 50-315/2000-007; 50- Licensee event reports: SF Ventilation October 19, 2000; 315/2000-007-01 System Inoperable Due To Technical August 2, 2001 Specification Surveillance Test Methodology.

P-00-11175 OE11256 - Control Room emergency August 10, 2000 Filtration Inoperable due to Testing Methodology 4OA7 Licensee Identified Violations CR 01323024 Technical Specification 3.9.7 violation November 19, 2001 due to movement of rod control cluster assembly handling tool CR 01343015 Discovered emergency diesel generator December 9, 2001 Unit 1 "B" Train voltage potentiometer settings incorrect 61

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