Text

IR 05000315-02-003(DRP), IR 05000316-02-003(DRP), on 04/01/2002 - 06/30/2002, Indiana Michigan Power Company, D.C. Cook, Units 1 and 2. Maintenance Risk Assessments and Emergent Work Evaluation, Personnel Performance During Non-routine Plan
	ML022110520
Person / Time
Site:	Cook
Issue date:	07/30/2002
From:	Passehl D; NRC/RGN-III/DRP/RPB6
To:	Bakken A; American Electric Power Co
References
	IR-02-003
	Download: ML022110520 (90)
	v • d • e

uly 30, 2002

SUBJECT:

D. C. COOK NUCLEAR POWER PLANT, UNITS 1 AND 2 NRC INSPECTION REPORT 50-315/02-03(DRP); 50-316/02-03(DRP)

Dear Mr. Bakken:

On June 30, 2002, 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 July 9, 2002, with Mr. J. 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, eight issues of very low safety significance (Green) were identified which involved 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. 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, D.C.

20555-0001; with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the D. C. Cook facility.

The NRC has increased security requirements at D.C. Cook in response to terrorist acts on September 11, 2001. Although the NRC is not aware of any specific threat against nuclear facilities, the NRC issued an Order and several threat advisories to commercial power reactors to strengthen licensees capabilities and readiness to respond to a potential attack. The NRC continues to monitor overall security controls and will issue temporary instructions in the near future to verify by inspection the licensees compliance with the Order and current security regulations.

A. In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter and its enclosures will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

We will gladly discuss any questions you have concerning this inspection.

Sincerely,

/RA/

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

Enclosure:

Inspection Report 50-315/02-03(DRP);

50-316/02-03(DRP)

REGION III==

Docket Nos: 50-315; 50-316 License Nos: DPR-58; DPR-74 Report No: 50-315/02-03(DRP); 50-316/02-03(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: April 1, 2002, through June 30, 2002 Inspectors: B. Kemker, Senior Resident Inspector K. Coyne, Resident Inspector R. Krsek, Resident Inspector, Palisades J. Belanger, Senior Physical Security Inspector R. Gattone, Radiation Specialist D. Jones, Reactor Engineer D. Passehl, Senior Project Engineer W. Slawinski, Senior Radiation Specialist Approved by: D. Passehl, Acting Chief Branch 6 Division of Reactor Projects

Table of Contents SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Summary of Plant Status: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 1. REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 1R01 Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 1R04 Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 1R06 Flood Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 1R07 Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 1R08 Inservice Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 1R12 Maintenance Rule Implementation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 1R13 Maintenance Risk Assessments and Emergent Work Evaluation . . . . . . . . . . 14 1R14 Personnel Performance During Non-routine Plant Evolutions . . . . . . . . . . . . . 16 1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 1R19 Post Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 1R20 Refueling and Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 1R23 Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 2. RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 2OS1 Access Controls to Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . . 28 2OS2 ALARA Planning and Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 2PS2 Radioactive Waste (Radwaste) Processing and Transportation . . . . . . . . . . . . 34 3. SAFEGUARDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 3PP1 Access Authorization Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 3PP2 Access Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 4. OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 4OA3 Event Follow-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 4OA6 Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 4OA7 Licensee Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 LIST OF ACRONYMS USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

SUMMARY OF FINDINGS IR 05000315-02-03(DRP), IR 05000316-02-03(DRP), on 04/01/2002-06/30/2002, Indiana Michigan Power Company, D. C. Cook Nuclear Power Plant, Units 1 and 2. Maintenance Risk Assessments and Emergent Work Evaluation, Personnel Performance During Non-routine Plant Evolutions, Event Follow-up.

This report covers a 12-week period of inspection by resident and region based 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 in NUREG 1649, Reactor Oversight Process, Revision 3, dated July 2000.

A. Inspector Identified Findings Cornerstone: Barrier Integrity C Green. A Non-Cited Violation of Unit 2 Technical Specification (TS) 3.9.4.c was self-revealed for the licensee's failure to have the nitrogen to pressurizer relief tank containment penetration isolated prior to commencing core alterations. An operator incorrectly opened the instrument root shutoff containment isolation valve and removed the "Do Not Operate" tag from the valve without verifying the required position of the valve for local leak rate testing. This resulted in an inoperable containment penetration during refueling and resulted in the plant being in a higher risk configuration than that planned by the licensee.

The inspectors determined that this issue had a credible impact on safety because the licensee failed to have the containment penetration isolated as required by the TSs and the valve was not in the correct position to fulfill its design safety function. The inspectors utilized the event information in conjunction with Appendix G, Shutdown Operations Significance Determination Process, of Manual Chapter 0609, Table T-1, Pressurized Water Reactor (PWR) Refueling Operation Reactor Coolant System (RCS) Level > 23' OR PWR Shutdown Operation with Time to Boil > 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months AND Inventory in the Pressurizer. This self-revealed issue was determined to be of very low significance (Green) by the significance determination process because (1) the issue did not increase the likelihood of a loss of primary coolant system inventory; (2) the issue did not degrade the licensees ability to terminate a leak path or add RCS inventory when needed; and (3) the issue did not degrade the licensees ability to recover decay heat removal once lost. Although this issue affected the integrity of the reactor containment during core alterations, the inspectors concluded that because the small diameter penetration would be a very small leakage path, this issue was of very low safety significance.

(Section 1R14.1)

C Green. A Non-Cited Violation of Unit 1 TS 3.4.11.c was self-revealed. An operator incorrectly positioned the control switches for pressurizer power operated relief valves (PORVs) 1-NRV-152 and 1-NRV-153, rendering the valves

unavailable for automatic pressure control. With Unit 1 in Mode 1 and two PORVs inoperable due to causes other than excessive seat leakage, the licensee failed to restore at least one of the inoperable PORVs to operable status within the following 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in Hot Standby within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in Hot Shutdown within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

The inspectors assessed this event using the Significance Determination Process (SDP). The inspectors determined that this issue had a credible impact on safety because the two PORVs were not capable of automatically controlling reactor coolant system (RCS) pressure below the setting of the pressurizer code safety valves, thereby reducing challenges to these valves. At the time of this event, the third pressurizer PORV (1-NRV-151) was already unavailable (automatic function only) with its manual isolation valve closed due to excessive seat leakage. Therefore the automatic function of all three PORVs was disabled.

Although all three PORVs were not capable of automatic operation, the valves were still capable of manual operation to mitigate a steam generator tube rupture accident or as an alternate means of decay heat removal during plant shutdown.

The inspectors concluded that this issue affected the operability of the pressurizer PORVs, which are barrier integrity components under the SDP designed to maintain the integrity of the RCS. The inspectors performed a Phase 2 SDP analysis for this finding using the following assumptions:

(1) manual operation of the PORVs for primary heat removal using the feed and bleed safety function was not affected; therefore, the inspectors only evaluated the Anticipated Transients Without Scram (ATWS) initiator which considered the primary relief safety function; (2) the duration of the performance deficiency was 13 days; and (3) operator action to manually actuate the failed automatic function of the PORVs was credited. Results of the Phase 2 ATWS worksheet determined that only one accident sequence was affected and resulted in this issue being characterized as having very low safety significance. In accordance with NRC Inspection Manual Chapter 0609, Appendix A, Attachment 1, Step 2.6, the SDP results were not evaluated for potential risk contribution due to Large Early Release Frequency because the accident sequence result was less than 1E-7 per year. (Section 1R14.2)

C Green. A Non-Cited Violation of Unit 2 TS 3.6.1.3 was self-revealed for the licensees failure to have at least one containment airlock door closed while the airlock was inoperable with Unit 2 in Mode 3. The mechanical interlock on the lower containment personnel airlock malfunctioned and personnel opening the inner airlock door challenged the interlock by not verifying the outer door was closed prior to opening the inner door. This created a direct access path from the containment atmosphere to the outside atmosphere.

The inspectors assessed this event using the Significance Determination Process (SDP). The inspectors determined that this issue had a credible impact on safety because the licensee failed to have at least one airlock door closed while the containment airlock was inoperable as required by the TSs and the resultant rapid containment pressure change also affected the operability of the ice condenser. The inspectors reviewed the guidance in NRC Inspection Manual Chapter 0609, Appendix H, "Containment Integrity SDP," and determined the

finding was a Type "B" finding. Type "B" findings have no impact on the determination of Core Damage Frequency (CDF) and therefore they are not processed through the CDF based SDP. These findings, however, are potentially important to Large Early Release Frequency (LERF) determinations.

The initial screening of the finding determined that the issue was potentially risk significant based on containment and ice condenser integrity which can be affected by the finding. The issue was therefore referred to the regional Senior Reactor Analyst (SRA) for further review. The analyst evaluated the circumstances of the issue to determine the actual duration of the finding. It was determined that the T/2 approach for fault exposure was not appropriate as the containment airlock doors were not discovered in the open position. In addition, the T/2 approach is generally used to estimate when a condition first occurred.

The analyst therefore used the 5 second duration of time that the doors were actually opened, as each entry through the containment airlock is a deliberate, monitored activity (rather than a random event) and the licensee would be expected to identify the problem (both containment airlock doors opened simultaneously) as soon as it occurs. In determining the actual risk significance the SRA with the assistance of the headquarters containment risk analyst, utilized the LERF methodology identified in Appendix H for Type "B" findings.

Utilizing this approach with actual plant specific probabilistic risk assessment values, the issue was determined to be of very low safety significance.

(Section 1R14.3)

C Green. A Non-Cited Violation of Unit 2 TS 3.9.4.c was self-revealed for the licensees failure to maintain refueling integrity configuration control of containment penetration CPN-74 during core alterations when containment isolation valve 2-XCR-101 was stroked open for testing. Opening this valve created a direct access path from the containment atmosphere to the outside atmosphere.

The inspectors determined that this issue had a credible impact on safety because the licensee failed to have the containment penetration isolated as required by the TSs. The inspectors utilized the event information in conjunction with Appendix G, Shutdown Operations Significance Determination Process, of Manual Chapter 0609, Table T-1, Pressurized Water Reactor (PWR) Refueling Operation Reactor Coolant System (RCS) Level > 23' OR PWR Shutdown Operation with Time to Boil > 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months AND Inventory in the Pressurizer. This issue was determined to be of very low significance (Green) by the significance determination process because (1) the issue did not increase the likelihood of a loss of primary coolant system inventory; (2) the issue did not degrade the licensees ability to terminate a leak path or add RCS inventory when needed; and (3) the issue did not degrade the licensees ability to recover decay heat removal once lost. Although this issue affected the integrity of the reactor containment during core alterations, the inspectors concluded that because 2-XCR-101 was open for a short period of time and the small diameter penetration would be a very small leakage path, this issue was of very low safety significance. (Section 4OA3.3)

C Green. The inspectors identified a Non-Cited Violation of Unit 1 Technical Specification 4.6.5.3.1.b.3, 4.6.5.3.1.b.4, and 4.6.5.3.1.b.5 requirements associated with testing of the ice condenser lower inlet doors.

Contrary to the TS requirements, previous TS 4.6.5.3.1.b surveillance testing performed in Unit 1 on November 21, 2000, failed to adequately measure the door opening torque and the door closing torque in accordance with the TS requirements. Specifically, the methodology used by the licensee to perform TS 4.6.5.3.1.b.3 and 4.6.5.3.1.b.4 testing resulted in door closing torques that were greater in magnitude than the door opening torques, contrary to the TS description of these torque values. The inspectors identified that the measured opening torque values for 36 of 48 Unit 1 lower inlet doors were less than the associated door closing torque values. Because calculation of the door frictional torque required accurate measurement of the door opening and closing torques, the licensee was unable to demonstrate compliance with the requirements of TS 4.6.5.3.1.b.5.

The inspectors assessed this finding using the Significance Determination Process. The inspectors determined that the failure to adequately implement TS 4.5.6.3.b requirements for testing of the Unit 1 lower inlet doors had a credible impact on safety and was more than a minor concern. As stated in the TS 3.6.5 bases, operability of the ice condenser doors ensures that reactor coolant fluid released during a loss of coolant accident (LOCA) will be diverted through the ice condenser bays for heat removal. The ice condenser also augments the containment recirculation sump water inventory in the event of certain small break LOCAs and limits ice maldistributions within the ice condenser. Because the proper functioning of the ice condenser lower inlet doors was primarily associated with the heat removal function of the ice condenser, the inspectors determined that this issue was associated with the barrier integrity cornerstone. Based on a review of additional testing results for the Unit 1 lower inlet doors performed in May 2002, the inspectors concluded that there was no actual reduction in the atmospheric pressure control function of the reactor containment nor a loss of capability to provide additional recirculation sump inventory during certain small break LOCAs. Therefore, this issue was determined to be of very low safety significance. (Section 4OA3.5)

Cornerstone: Mitigating Systems C Green. A Non-Cited Violation of 10 CFR 50, Appendix B, Criterion V,

"Instructions, Procedures, and Drawings," was self-revealed following the identification of foreign material in the Unit 1 West essential service water (ESW)

pump. On June 24, 2002, the licensee identified a rapid degradation in the performance of the Unit 1 West ESW pump. Subsequent investigation identified that plastic barrier tape, a foreign material, had been ingested by the pump and had become wound tightly around the pumps impeller. The inspectors concluded that the licensee failed to establish appropriate work controls to control foreign material in areas adjacent to the Unit 1 West ESW pump in accordance with the requirements of PMI-2220, "Foreign Material Exclusion."

The inspectors evaluated this failure to establish appropriate foreign material controls in the vicinity of the Unit 1 West ESW pump using the Significance Determination Process. The inspectors determined that this issue had a credible impact on safety and was more than a minor concern. Specifically, ingestion of foreign material by the Unit 1 West ESW pump degraded pump performance and rendered the pump inoperable, which affected the reliability and capability of the ESW system. The safety function of the ESW system is to provide sufficient cooling capacity for continued operation of safety-related equipment during normal and accident conditions. Consequently, the inspectors determined that this issue affected the objectives of the mitigating systems cornerstone. The inspectors concluded that this issue did not result in an actual loss of the safety function of a single train of ESW for greater than the TS allowed outage time.

Additionally, because of the continued availability of ESW capability from both of the Unit 2 ESW trains and the Unit 1 East ESW train, the inspectors concluded that the foreign material ingestion did not result in an actual loss of the ESW system safety function. Consequently, the inspectors concluded that this issue was of very low safety significance. (Section 1R13)

C Green. A Non-Cited Violation of 10 CFR 50, Appendix B, Criterion V,

"Instructions, Procedures, and Drawings," for maintenance procedures inappropriate to the circumstances, was self-revealed following gas binding of the Unit 2 West centrifugal charging pump. On February 16, 2002, the running charging pump became gas bound following attempts to switch the suction source from the volume control tank to the refueling water storage tank.

Follow-up investigation revealed that valve 2-CS-369 (reactor coolant pump seal water heat exchanger to volume control tank shutoff valve) was partially open, allowing transfer of volume control tank cover gas directly to the suction of the Unit 2 charging pumps. The licensee later determined that the position of the 2-CS-369 stem stop nut prevented full closure of the valve. Approximately two weeks prior to this event, the licensee replaced the diaphragm in 2-CS-369 using instructions provided in maintenance procedure 12 MHP-5021-001-023.

However, the instructions contained in 12 MHP-5021-001-023 were inconsistent with vendor recommendations for stem stop nut adjustment and contributed to the failure to maintain proper positioning of the stem stop nut. The inspectors determined that the failure to provide procedures appropriate to the circumstances for the adjustment of the 2-CS-369 stem stop nut was a violation of NRC requirements.

The inspectors assessed this finding using the Significance Determination Process (SDP). The inspectors concluded that this issue had a credible impact on safety and was therefore more than a minor concern. In particular, the gas intrusion into the suction of the running Unit 2 West centrifugal charging pump while aligned to the refueling water storage tank, a potential common cause failure mechanism for both of the Unit 2 charging pumps, impacted the capability of the high head injection system to provide the inventory and reactivity control safety functions. Therefore, the inspectors determined that this issue was associated with the mitigating systems cornerstone. During the Phase 1 SDP review, the inspectors concluded that this issue degraded the licensees ability to add inventory to the reactor coolant system and therefore a Phase 2 SDP

analysis was required. The Phase 2 shutdown risk SDP analysis, performed with the assistance of the Region III Senior Reactor Analyst and headquarters probabilistic risk assessment staff, determined that the total change in Core Damage Frequency associated with this condition was estimated to be approximately 3E-7 per year. The risk analysts reviewed several shutdown accident scenarios and determined that drain down to mid-loop operation after refueling to support vacuum refill of the reactor coolant system was the most limiting scenario. Based on the overall change in Core Damage Frequency, this issue was determined to be of very low safety significance. (Section 4OA3.7)

Cornerstone: Occupational Radiation Safety C Green. A Non-Cited Violation of 10 CFR 20.1701 was identified for the licensees failure to utilize all intended radiological engineering controls to limit the concentration of radioactive material in air during steam generator eddy current testing, resulting in intakes to four workers.

This finding was determined to be of very low safety significance since radiation exposures to involved workers were low relative to regulatory limits, and because radiological conditions were not of a magnitude sufficient to create a substantial potential for an overexposure. (Section 2OS2.7)

B. Licensee Identified Violations Violations of very low safety significance which were identified by the licensee have been reviewed by the inspectors. Corrective actions taken or planned by the licensee appear reasonable. These violations are listed in Section 40A7 of this report.

Report Details Summary of Plant Status:

Unit 1 operated at or near full power during this inspection period with the following exceptions:

C On April 25, 2002, the licensee reduced power to approximately 8 percent of rated thermal power and took the main generator off-line to secure components of a 345 kilo-volt line disconnect that were damaged during switchyard maintenance activities the previous day. The licensee synchronized the unit to the grid on April 26, 2002.

C On May 3, 2002, the licensee conducted a reactor shutdown for the Cycle 18 refueling outage (U1C18). Following completion of the refueling outage, the licensee synchronized the unit to the grid on June 9, 2002.

C On June 12, 2002, a loss of the preferred reserve offsite power source to Unit 1 occurred when a 345 kilo-volt breaker exploded and a fire ensued in the 345 kilo-volt switchyard. Unit 1 was maintained at 70 percent power during the event. Power ascension to full power resumed on June 13, 2002.

C On June 14, 2002, operators manually tripped Unit 1 in response to a main feedwater pump trip. The feedwater pump condenser became clogged with zebra mussels and lost vacuum when a circulating water pump was started. The licensee performed a reactor startup and synchronized the unit to the grid on June 18, 2002.

Unit 2 operated at or near full power during this inspection period with the following exceptions:

C On April 4, 2002, the licensee initiated a reactor shutdown as required by Technical Specification (TS) 3.8.2.3.b due to an inoperable safety-related 250 volt battery. The licensee reduced power to approximately 41 percent of rated thermal power prior to receiving approval of a Notice of Enforcement Discretion (NOED). The licensee returned the unit to full power on April 5, 2002.

C On May 12, 2002, Unit 2 experienced an automatic reactor trip due to a power supply failure that caused the number 21 steam generator feedwater regulating valve to fail closed. The power supply failure also affected the operation of the steam dumps, causing the loss of the normal heat sink. Following the replacement of failed power supply drawers, the licensee synchronized the unit to the grid on May 15, 2002.

C On May 25, 2002, the licensee performed a reactor shutdown to isolate a steam leak and replace one of the main turbine reheat stop valves due to a failed weld. The main steam stop valves were shut after the trip to isolate the steam leak, causing the loss of the normal heat sink. Following the valve replacement, the licensee synchronized the unit to the grid on June 2, 2002.

C On June 12, 2002, a loss of the preferred reserve offsite power source to Unit 2 occurred when a 345 kilo-volt breaker exploded and a fire ensued in the 345 kilo-volt switchyard. Unit 2 was maintained at full power during the event. The licensee received

an NOED to extend the 2-hour allowed action time of TS 3.0.5 to preclude shutting down the unit until an operable train of essential service water (ESW) was restored.

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

a. Inspection Scope The inspectors reviewed the licensees procedures and preparations for high temperature, high wind, and flooding conditions. The inspectors reviewed severe weather procedures, emergency plan implementing procedures related to severe weather, annunciator response procedures, and performed general area walkdowns.

During the walkdowns, the inspectors observed housekeeping conditions and verified that material capable of becoming an airborne missile hazard during high wind conditions or severe weather was appropriately restrained. Additionally, the inspectors reviewed condition reports (CRs) and the identification and resolution of equipment deficiencies associated with adverse weather mitigation.

b. Findings No findings of significance were identified.

1R04 Equipment Alignment (71111.04)

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

Mitigating Systems Cornerstone C Unit 2 Train AB and CD Station Batteries C Unit 2 Turbine Driven and East Motor Driven Auxiliary Feedwater (AFW) Pump Trains The inspectors selected these systems based on their risk significance relative to the mitigating systems cornerstone. The inspectors reviewed operating procedures, 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 the system incapable of performing its intended functions. In addition, the inspectors walked down accessible portions of the system to verify system components were aligned correctly.

b. Findings No findings of significance were identified.

.2 Complete System Walkdown a. Inspection Scope The inspectors performed a complete system walkdown of the following risk-significant system:

Initiating Events Cornerstone C Unit 2 Circulating Water System The inspectors reviewed ongoing system maintenance, open job orders, and design issues for potential effects on the ability of the Unit 2 circulating water system to perform its design functions. The inspectors ensured that the configuration of the system was in accordance with applicable operating checklists. The inspectors verified acceptable material condition of system components, availability of electrical power to system components, and that ancillary equipment or debris did not interfere with system performance.

b. Findings No findings of significance were identified.

1R05 Fire Protection (71111.05)

.1 Routine Resident Inspector Tours a. Inspection Scope The inspectors performed fire protection walkdowns of the following risk-significant plant areas:

Mitigating Systems Cornerstone C Unit 1 Lower Containment Building C Unit 2 Auxiliary Cable Vault (Zone 59)

C Unit 2 Switchgear Room Cable Vault (Zone 60)

C Unit 2 East and West ESW Pump Rooms and Adjacent Screenhouse Areas (Zones 29C, 29D, and 142)

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.

.2 Annual Fire Drill Observation a. Inspection Scope The inspectors assessed fire brigade performance and the drill evaluators critique during a fire brigade drill conducted in the Auxiliary Building entry/exit area on April 10, 2002. The drill simulated a trash receptacle fire in the center room of the radiological protection (RP) offices. The inspectors focused on command and control of fire brigade activities, fire fighting and communication practices, material condition and use of fire fighting equipment, and implementation of pre-fire plan strategies.

b. Findings No findings of significance were identified.

1R06 Flood Protection Measures (71111.06)

a. Inspection Scope The inspectors evaluated whether the licensee took appropriate precautions to mitigate the risk from external flooding events. Specifically, the inspectors performed the following:

C reviewed the Updated Final Safety Analysis Report (UFSAR) and other selected design basis documents to identify those areas susceptible to external flooding; C performed a walkdown of the 569 foot elevation of the Turbine Building, the Lake Screen House (including the ESW pump rooms), and general plant yard to evaluate whether appropriate flood protection controls were being maintained; C reviewed selected station operating procedures used to identify and mitigate flooding events; and C interviewed selected operating and engineering staff regarding external flooding protection controls.

In addition, the inspectors reviewed the issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance. The inspectors also reviewed the licensees corrective actions for flood protection related issues documented in selected CRs.

b. Findings No findings of significance were identified.

1R07 Heat Sink Performance (71111.07)

a. Inspection Scope The inspectors observed the licensee perform an inspection of the following heat exchanger:

C 1-HE-15E Unit 1 East Component Cooling Water Heat Exchanger The inspectors selected this heat exchanger to inspect because the component cooling water system was identified as risk significant in the licensees risk assessment and the heat exchanger is required to support the operability of other risk significant safety-related equipment. During this inspection, the inspectors observed the as-found condition of the cooler and verified that no deficiencies existed that would mask degraded performance. In addition, the inspectors observed that no conditions were present that would indicate a potential for common cause problems. The inspectors discussed the as-found condition as well as the historical performance of the cooler with engineering department personnel and reviewed applicable documents and procedures.

In addition, the inspectors reviewed the issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance. The inspectors also reviewed the licensees corrective actions for heat sink performance related issues documented in selected CRs.

b. Findings No findings of significance were identified.

1R08 Inservice Inspection Activities (71111.08)

a. Inspection Scope The inspector conducted a review of the licensees inservice inspection program for monitoring degradation of the reactor coolant system (RCS) boundary and risk significant piping system boundaries. Specifically, the inspectors conducted a record review of the following examinations:

NON-DESTRUCTIVE WELD NUMBER CONFIGURATION EXAMINATION TYPE 1-RH-27-05S Pipe to Elbow UT & PT 1-CTS-2-13S Pipe to Elbow UT & PT 1-SI-23-17F Pipe to Valve UT & PT 1-FW-13-09S Elbow to Pipe UT & MT These examinations were evaluated for compliance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code requirements. The inspector also reviewed inservice inspection procedures, equipment certifications, personnel certifications, and NIS-2 forms for Code repairs performed during the last

outage to confirm that ASME Code requirements were met. The inspector also conducted a review of the radiographs of 1-RC-131 (Job Order 1180005-09) 3/4-inch pipe replacement.

A sample of inservice inspection related problems documented in the licensees corrective action program was also reviewed to assess conformance with 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action" requirements. In addition, the inspector determined that operating experience was correctly assessed for applicability by the inservice inspection group.

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 system:

Mitigating Systems Cornerstone C Diesel Generator Ventilation System In addition, the inspectors reviewed the issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance. The inspectors also reviewed the licensees corrective actions for Maintenance Rule related issues that were documented in selected CRs.

b. Findings No findings of significance were identified.

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

a. Inspection Scope The inspectors reviewed the licensees evaluation and management of plant risk for maintenance activities on the following equipment:

Initiating Events Cornerstone C Unit 1 Main Generator Output Breaker 1-52-K1 Replacement Mitigating Systems Cornerstone C Unit 2 West Motor Driven AFW Pump C Unit 1 Turbine Driven AFW Pump C Unit 2 East and Unit 1 West ESW Pump Replacements 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 The inspectors identified one finding of very low safety significance (Green) associated with a self-revealed failure of the Unit 1 West ESW pump. This finding was associated with foreign material exclusion controls. The finding was determined to be a violation of NRC requirements and was dispositioned as a Non-Cited Violation.

Description On June 24, 2002, the Unit 1 control room operators noted that the performance of the Unit 1 West ESW pump had significantly decreased. Specifically, the control room operators noted that at 5:30 p.m. the Unit 1 West ESW pump header pressure dropped from approximately 64 pounds-per-square-inch gauge (psig) to 50 psig, resulting in actuation of the associated low ESW header pressure alarm. The operators also noted that total pump flow decreased from approximately 8200 gallons-per-minute (gpm) to 7200 gpm. Based on these indications, the operators declared the Unit 1 West ESW pump inoperable and initiated CR 02175037. During follow-up testing, the licensee determined that the pump developed head at the reference inservice testing flowrate was 55.6 pounds-per-square-inch differential (psid), which was significantly less than the low action limit of 63.8 psid. The Unit 1 West ESW pump had just been replaced and satisfactorily tested 3 days prior to this event. Following the event, the licensee replaced the ESW pump and returned the train to an operable status on June 26, 2002. During pump replacement activities, the licensee discovered that plastic barrier tape had been ingested by the pump and had become tightly wound around the impeller. The barrier tape was of a type used in the screenhouse to cordon off hazardous areas. The inspectors determined that the loss of foreign material controls that resulted in the Unit 1 West ESW pump ingesting a significant quantity of plastic barrier tape was a violation of NRC requirements.

Analysis The inspectors evaluated this failure to establish appropriate foreign material controls in the vicinity of the Unit 1 West ESW pump using the Significance Determination Process (SDP). The inspectors determined that this issue had a credible impact on safety and was more than a minor concern. Specifically, ingestion of foreign material by the Unit 1 West ESW pump degraded pump performance and rendered the pump inoperable, which affected the reliability and capability of the ESW system. The safety function of the ESW system is to provide sufficient cooling capacity for continued operation of safety-related equipment during normal and accident conditions. Consequently, the inspectors determined that this issue affected the objectives of the mitigating systems cornerstone. The inspectors concluded that this issue did not result in an actual loss of the safety function of a single train of ESW for greater than the TS allowed outage time.

Additionally, because of the continued availability of ESW capability from both of the Unit 2 ESW trains and the Unit 1 East ESW train, the inspectors concluded that the foreign material ingestion did not result in an actual loss of the ESW system safety function. Consequently, the inspectors concluded that this issue was of very low safety significance.

Enforcement 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.

Section 4.1.1. of Plant Managers Instruction (PMI) 2220, "Foreign Material Exclusion," a procedure prescribing activities affecting quality, stated, in part, that appropriate work controls shall be established for areas adjacent to open systems or components to control foreign material which may be generated from any facet of plant work. Contrary to the above, the licensee failed to establish appropriate work controls to control foreign material for areas adjacent to the Unit 1 West ESW pump in accordance with the requirements of PMI-2220, Section 4.1.1. Specifically, appropriate work controls were not established to prevent the intrusion of the foreign material that was discovered in the impeller of the Unit 1 West ESW pump on June 25, 2002. The foreign material significantly degraded pump performance and resulted in the inoperability of the pump.

This is a violation of 10 CFR 50, Appendix B, Criterion V. Because of the very low safety significance, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the NRC Enforcement Policy (NCV 50-315-02-03-01(DRP)). The licensee entered this violation into its corrective action program as CR 02176058 and CR 02175037.

1R14 Personnel Performance During Non-routine Plant Evolutions (71111.14)

.1 Containment Isolation Valve Alignment Error During Local Leak Rate Testing a. Inspection Scope On January 26, 2002, during reactor core offload for refueling outage U2C13, an operator performing a valve lineup for local leak rate testing on the nitrogen to

pressurizer relief tank containment isolation valve (2-N-159) incorrectly opened the instrument root shutoff containment isolation valve (2-GPX-301-V1) and removed the

"Do Not Operate" tag from the valve without verifying the required position of the valve for testing. This created a direct access path from the containment atmosphere to the outside atmosphere and violated the TS requirement for refueling integrity. This event was selected for review to evaluate the operator human performance errors that caused the event. The inspectors interviewed operations and licensing department personnel and reviewed the licensees apparent cause evaluation, licensee event report, applicable procedures, and the CR to understand the details of the event. The licensee event report is discussed in Section 4OA3.1 of this report.

b. Findings A finding of very low safety significance (Green) was self-revealed and is tied to human performance. An operator incorrectly opened an instrument root shutoff containment isolation valve and removed the "Do Not Operate" tag from the valve without verifying the required position of the valve for local leak rate testing. This resulted in an inoperable containment penetration during refueling and resulted in the plant being in a higher risk configuration than that planned by the licensee. This finding was dispositioned as a Non-Cited Violation.

Description On January 26, 2002, while performing a valve lineup for local leak rate testing on the nitrogen to pressurizer relief tank containment penetration, an operator incorrectly opened 2-GPX-301-V1 and removed the "Do Not Operate" tag from the valve without verifying the required position of the valve for testing. The operator who had been involved with previous testing that required the lifting of similar tags from instrument root valves failed to self check and verify the required position for this valve in the test procedure. As a result, the licensee failed to have the containment penetration isolated for approximately 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months during core alterations. A different operator who performed the restoration for the valve lineup identified that 2-GPX-301-V1 was open and notified the control room. The licensee suspended core alterations and closed 2-GPX-301-V1.

The licensees original outage risk evaluation reflected a "yellow" risk configuration (i.e., acceptable but reduced level of defense) by maintaining all of the containment penetrations closed for refueling integrity. By not maintaining 2-GPX-301-V1 closed, the licensee inadvertently entered a higher "red" risk configuration (i.e., less than minimum acceptable level of defense). The licensees plant shutdown safety and risk management procedure, Plant Managers Procedure (PMP) 4100-SDR-001, "Plant Shutdown Safety and Risk Management," did not permit voluntary entry into a "red" risk configuration and required the implementation of additional risk management actions to maintain an adequate level of defense for an emergent entry into a "red" risk configuration.

Analysis The inspectors determined that this issue had a credible impact on safety because the licensee failed to have the containment penetration isolated as required by the TSs and the valve was not in the correct position to fulfill its design safety function. The inspectors utilized the event information in conjunction with Appendix G, Shutdown Operations Significance Determination Process, of Manual Chapter 0609, Table T-1, Pressurized Water Reactor (PWR) Refueling Operation Reactor Coolant System (RCS)

Level > 23' OR PWR Shutdown Operation with Time to Boil > 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months AND Inventory in the Pressurizer. This self-revealed issue was determined to be of very low significance (Green) by the significance determination process because (1) the issue did not increase the likelihood of a loss of primary coolant system inventory; (2) the issue did not degrade the licensees ability to terminate a leak path or add RCS inventory when needed; and (3) the issue did not degrade the licensees ability to recover decay heat removal once lost. Although this issue affected the integrity of the reactor containment during core alterations, the inspectors concluded that because the small diameter penetration would be a very small leakage path, this issue was of very low safety significance.

Enforcement Technical Specification 3.9.4.c, states, in part, that each containment penetration providing direct access from the containment atmosphere to the outside atmosphere shall be closed by either an isolation valve, blind flange, manual valve, or equivalent during core alterations or movement of irradiated fuel within the containment. With the above requirement not satisfied, the TS requires that the licensee immediately suspend all operations involving core alterations or movement of irradiated fuel in the Containment Building. Contrary to the above, on January 26, 2002, the licensee failed to have containment isolation valve 2-GPX-301-V1 closed to isolate the nitrogen to pressurizer relief tank containment penetration during core alterations. How long did this condition exist? This is a violation of TS 3.9.4.c. Because of the very low safety significance, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the NRC Enforcement Policy (NCV 50-316-02-03-02(DRP)). The licensee entered this violation into its corrective action program as CR 02027006.

.2 Pressurizer Power Operated Relief Valves (PORVs) Inoperable Due to Mis-positioned Control Switches a. Inspection Scope On February 19, 2002, during stroke time testing of the Unit 1 pressurizer PORV block valves, an operator noticed that the control switches for pressurizer PORVs 1-NRV-152 and 1-NRV-153 were not correctly positioned to the "auto" position. This rendered the two PORVs inoperable. Subsequent investigation identified that the control switches had been mis-positioned since February 6, 2002. This event was selected for review to evaluate the operator human performance errors that caused the event. The inspectors interviewed operations and licensing department personnel and reviewed the licensee's apparent cause evaluation, licensee event report, applicable procedures, and the CR to

understand the details of the event. The licensee event report is discussed in Section 4OA3.2 of this report.

b. Findings A finding of very low safety significance (Green) was self-revealed and is tied to human performance. An operator incorrectly positioned the control switches for pressurizer PORVs 1-NRV-152 and 1-NRV-153, rendering the valves unavailable for automatic pressure control. This finding was dispositioned as a Non-Cited Violation.

Description On February 19, 2002, during stroke time testing of Unit 1 pressurizer PORV block valves 1-NMO-152 and 1-NMO-153, an operator noticed that the control switches for 1-NRV-152 and 1-NRV-153 were positioned slightly to the left of the "auto" position.

Upon completion of the testing, the PORV control switches were restored to the "auto" position and the PORVs declared operable. The licensees apparent cause evaluation concluded that operators failed to verify that the control switches were fully engaged in the "auto" position after previous testing on February 6, 2002. The inspectors also noted that this was not an isolated occurrence. During the licensees extent of condition review, the licensee identified the same condition with Unit 2 pressurizer PORVs 2-NRV-152 and 2-NRV-153. However, that condition was identified while the valves were out-of-service during a refueling outage, and the valves were not being relied on for low temperature over-pressure protection of the RCS.

Analysis The inspectors assessed this event using the SDP. The inspectors determined that this issue had a credible impact on safety because the two PORVs were not capable of automatically controlling RCS pressure below the setting of the pressurizer code safety valves, thereby reducing challenges to these valves. At the time of this event, the third pressurizer PORV (1-NRV-151) was already unavailable (automatic function only) with its manual isolation valve closed due to excessive seat leakage. Therefore the automatic function of all three PORVs was disabled. Although all three PORVs were not capable of automatic operation, the valves were still capable of manual operation to mitigate a steam generator tube rupture accident or as an alternate means of decay heat removal during plant shutdown. The inspectors concluded that this issue affected the operability of the pressurizer PORVs, which are barrier integrity components under the SDP designed to maintain the integrity of the RCS. The inspectors performed a Phase 2 SDP analysis for this finding using the following assumptions: (1) manual operation of the PORVs for primary heat removal using the feed and bleed safety function was not affected; therefore, the inspectors only evaluated the Anticipated Transients Without Scram (ATWS) initiator which considered the primary relief safety function; (2) the duration of the performance deficiency was 13 days; and (3) operator action to manually actuate the failed automatic function of the PORVs was credited.

Results of the Phase 2 ATWS worksheet determined that only one accident sequence was affected and resulted in this issue being characterized as having very low safety significance. In accordance with IMC 0609, Appendix A, Attachment 1, Step 2.6, the SDP results were not evaluated for potential risk contribution due to Large Early

Release Frequency (LERF) because the accident sequence result was less than 1E-7 per year.

Enforcement Technical Specification 3.4.11 states that three PORVs and their associated block valves shall be operable in Modes 1, 2, and 3. Technical Specification 3.4.11.c states that with two PORVs inoperable due to causes other than excessive seat leakage, within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months either restore the PORVs to operable status or close the associated block valves and remove power from the block valves; restore at least one of the inoperable PORVs to operable status within the following 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in Hot Standby within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in Hot Shutdown within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . Contrary to the above, on February 19, 2002, with Unit 1 in Mode 1 and two PORVs inoperable due to causes other than excessive seat leakage, the licensee failed to restore at least one of the inoperable PORVs to operable status within the following 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in Hot Standby within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in Hot Shutdown within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . This is a violation of TS 3.4.11.c. Because of the very low safety significance, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the NRC Enforcement Policy (NCV 50-315-02-03-03(DRP)). The licensee entered this violation into its corrective action program as CR 02050022.

.3 Failure of Lower Containment Airlock Door Interlock and Failure to Follow Instructions Resulted in Inadvertent Opening of Both Airlock Doors a. Inspection Scope During the removal of plant equipment from the Unit 2 Containment Building on January 23, 2001, the mechanical interlock on the personnel airlock, which is designed to prevent opening both inner and outer lower containment airlock doors at the same time, malfunctioned and personnel opening the inner airlock door challenged the interlock by not verifying the outer door was closed prior to opening the inner door. This event was selected for review to evaluate the human performance errors that caused the event. The inspectors interviewed licensing department personnel and reviewed the licensees root cause evaluation, licensee event report, applicable procedures, and the CR to understand the details of the event. The licensee event report is discussed in Section 4OA3.4 of this report.

b. Findings A finding of very low safety significance (Green) was self-revealed. The mechanical interlock on the Unit 2 lower containment personnel airlock malfunctioned and personnel opening the inner airlock door challenged the interlock by not verifying the outer door was closed prior to opening the inner door. This created a direct access path from the containment atmosphere to the outside atmosphere. This finding was dispositioned as a Non-Cited Violation.

Description

On January 23, 2001, the mechanical interlock on the Unit 2 lower containment personnel airlock malfunctioned as personnel were transferring equipment out of the Containment Building. Unit 2 had just entered Mode 3 to resolve a problem with the rod control system and two work crews were exiting the Containment Building. Personnel opening the inner airlock door failed to follow posted instructions to verify the outer door was closed prior to opening the inner door. The mechanical interlock was challenged and failed allowing both airlock doors to be open at the same time. The licensee had posted instructions on the outer airlock door security gate for proper operation of the airlock. Personnel using the airlock were expected to verify the readiness of the airlock doors for opening by using the door position indicator lights. In this event, personnel failed to verify that the outer doors indicating light was illuminated prior to opening the inner door. Because the interlock malfunctioned, both airlock doors were able to be opened at the same time. A rapid containment pressure change caused 10 lower ice condenser doors to go open, resulting in an inoperable ice condenser for a brief period of time. The lower ice condenser doors were subsequently reseated and the overall impact on the ice condenser was minimal.

A review of interlock maintenance history back to the late 1980s found interlock failures to be recurring. The licensee identified this adverse trend in 1999 and documented it in its corrective action program. The licensee had accepted the interlock failure rate as meeting standards and expectations for that time period. The root cause for the recurring interlock failures is that the interlock mechanism was vulnerable to slipping out of adjustment with door use. The specific failure involved gradual loosening of the setscrews that held the interlock gears in place on the interlock gear shafts. The frequency of airlock door use was greater than originally expected when the plant was designed. Preventive maintenance was not effective to maintain the interlock in good working order. Past corrective actions and oversight had not improved the interlock failure rate. The licensee noted in its root cause evaluation that other plants have upgraded their containment airlock interlocks, including installation of gears that use keyways rather than setscrews, and have not had significant interlock problems after the upgrades.

Analysis The inspectors determined that this issue had a credible impact on safety because the licensee failed to have at least one airlock door closed while the containment airlock was inoperable as required by the TSs and the resultant rapid containment pressure change affected the operability of the ice condenser. The inspectors reviewed the guidance in IMC 0609, Appendix H, "Containment Integrity SDP," and determined the finding was a Type "B" finding. Type "B" findings have no impact on the determination of Core Damage Frequency (CDF) and therefore they are not processed through the CDF based SDP. These findings, however, are potentially important to LERF determinations.

The initial screening of the finding determined that the issue was potentially risk significant based on the affect on containment and ice condenser integrity. The issue was referred to the regional Senior Reactor Analyst (SRA) for further review. The analyst determined that the T/2 approach for fault exposure was not appropriate as the containment airlock doors were not discovered in the open position. The analyst therefore used the 5 seconds duration of time that the doors were actually opened, as each entry through the containment airlock is a deliberate, monitored activity (rather

than a random event), and the licensee would be expected to identify the problem (both containment airlock doors opened simultaneously) as soon as it occurs. In determining the actual risk significance the SRA, with the assistance of the headquarters containment risk analyst, utilized the LERF methodology identified in Appendix H for Type "B" findings. Utilizing this approach with actual plant specific probabilistic risk assessment values, the issue was determined to be of very low safety significance.

Enforcement Technical Specification 3.6.1.3 requires, in part, that each containment air lock shall be operable with both containment airlock doors closed, except when the airlock is being used for normal transit entry and exit through containment, then at least one airlock door shall be closed. With an air lock inoperable, the TS requires that at least one door be maintained closed. This TS requirement is applicable with Unit 2 in Modes 1, 2, 3 and 4.

Contrary to the above, on January 23, 2001, the licensee failed to have at least one airlock door closed while the containment airlock was inoperable with Unit 2 in Mode 3.

This is a violation of TS 3.6.1.3. Because of the very low safety significance, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the NRC Enforcement Policy (NCV 50-316-02-03-04(DRP)). The licensee entered this violation into its corrective action program as CR 01023054.

.4 Unit 1 Power Reduction to Support Repairs to the Unit 1 Main Generator K1 Breaker Disconnect a. Inspection Scope On April 25, 2002, during maintenance activities on Unit 1 main generator output breaker K1, maintenance workers damaged the breaker disconnects. At the time, the breaker disconnects were opened to provide electrical safety isolation for maintenance on the K1 breaker. In order to facilitate repairs to the disconnect, the licensee reduced Unit 1 power from 100 percent to approximately 8 percent to allow removal of the main generator from service. The inspectors observed portions of the power reduction and assessed the operator response to this event.

b. Findings No findings of significance were identified.

.5 Unit 1 Reactor Trip and Restart Following Loss of Main Feedwater Pump Vacuum a. Inspection Scope On June 14, 2002, control room operators manually tripped Unit 1 in response to a low vacuum automatic trip of the East main feedwater pump. Immediately prior to the main feedwater pump trip, the operators started circulating water pump13, which had been idled since October 2001. The licensee determined that an influx of zebra mussel shells and debris following the circulating water pump start caused blockage of the main feedwater pump condensers. The licensee restarted Unit 1 on June 17, 2002, after cleaning out the main feedwater pump condenser water boxes. The inspectors

assessed control room operator performance immediately following the reactor trip, reviewed the post trip report, and observed portions of the reactor restart activities.

b. Findings No findings of significance were identified.

.6 Unit 2 Station Battery AB Cell Cracking Operator Response a. Inspection Scope On April 23, 2002, operations personnel identified indications of cracking on battery cell 31 of the 2AB station battery. The licensee declared the 2AB battery inoperable and entered the action statement for TS 3.8.2.3, which required the battery to be returned to an operable status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or the plant to be placed in at least Hot Standby within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The licensee replaced the cracked cell and returned the battery to an operable status within the allowed outage time. On April 4, 2002, the licensee had requested and was granted an NOED for similar cell case cracking on the 2AB battery.

(Refer to Section 4OA3.6 for the inspectors review the NOED.) Because of the repetitive occurrence of this issue and the short allowed outage time for an inoperable station battery, the inspectors assessed the licensees response to this issue.

b. Findings No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope The inspectors reviewed the following CRs to ensure that either: (1) the condition did not render the involved equipment inoperable or result in an unrecognized increase in plant risk, or (2) the licensee appropriately applied TS limitations and appropriately returned the affected equipment to an operable status.

Barrier Integrity Cornerstone C CR 02115002 Unit 1 Ice Basket 24-1-7 As-found Weight Below TS Requirements Mitigating Systems Cornerstone C CR 02136014 2-FW-160, West Motor Driven AFW Pump Emergency Leakoff Check Valve Leaked By During the Performance of Test 02-OHP-4030.STP.017E C CR 02109003 Non-seismic Scaffolding Built in the Vicinity of 2AB DG

[Diesel Generator] and 2CD DG Components

C CR 02134021 Check Valves 1-CS-328-L1, 1-CS-328-L4, 1-CS-329-L1, and 1-CS-329-L4 Were Found Open During Radiographic Nonintrusive Testing C CR 02137063 Unit 2 Steam Stop Valve 2-MRV-220 Detent Bar/Guide Rod Bushing Has Fallen Out The inspectors also reviewed the licensees justification for not correcting existing degraded and nonconforming conditions during refueling outage U1C18 consistent with the timeliness guidance contained in Generic Letter 91-18, "Information to Licensees Regarding NRC Inspection Manual Section on Resolution of Degraded and Nonconforming Conditions," Revision 1.

In addition, the inspectors reviewed the issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance. The inspectors also reviewed the licensees corrective actions for issues potentially affecting the operability of structures, systems, and components that were documented in selected CRs.

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 C Job Order C0051164, "Replace 1-BATT-CD During Year 2002 Outage" C 1-DCP [Design Change Procedure] 4504, "Replace Reserve Auxiliary Transformers 101AB and 102CD with Load Tap Changing Transformers" C 1-DCP 4504, "Install New Undervoltage Protection Relays" C Job Order 02093039, "Unit 2AB Station Battery Cell 46 Replacement" C Unit 1 Turbine Driven AFW Pump Maintenance (Multiple Job 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.

1R20 Refueling and Outage Activities (71111.20)

.1 Unit 1 Refueling Outage (U1C18)

a. Inspection Scope The inspectors evaluated the licensees conduct of Unit 1 refueling outage activities to assess the licensees control of plant configuration and management of shutdown risk.

The inspectors reviewed configuration management to verify that the licensee maintained defense-in-depth commensurate with the shutdown risk plan; reviewed major outage work activities to ensure that correct system lineups were maintained for key mitigating systems; and observed refueling activities to verify that fuel handling operations were performed in accordance with the TSs and approved procedures.

Other major outage activities evaluated included the licensees control of the following:

C Containment penetrations in accordance with the TSs C Systems, structures, and components (SSCs) which could cause unexpected reactivity changes C Flow paths, configurations, and alternate means for RCS inventory addition and control of SSCs which could cause a loss of inventory C RCS pressure, level, and temperature instrumentation C Spent fuel pool cooling during and after core offload C Switchyard activities and the configuration of electrical power systems in accordance with the TSs and shutdown risk plan C SSCs required for decay heat removal The inspectors observed portions of the plant cooldown, including the transition to shutdown cooling, to verify that the licensee controlled the plant cooldown in accordance with the TSs. The inspectors also observed portions of the restart activities to verify that TS requirements and administrative procedure requirements were met prior to changing operational modes or plant configurations. Major restart inspection activities performed included:

C Verification that RCS boundary leakage requirements were met prior to entry into Mode 4 (Cold Shutdown) and subsequent operational mode changes C Verification that containment integrity was established prior to entry into Mode 4 C Inspection of the Containment Building to assess material condition and search for loose debris, which if present could be transported to the containment recirculation sumps and cause restriction of flow to the emergency core cooling system (ECCS) pump suctions during loss-of-coolant accident conditions C Verification that the material condition of the Containment Building ECCS recirculation sumps met the requirements of the TSs and was consistent with the design basis C Observation and review of reactor physics testing to verify that core operating limit parameters were consistent with the core design so that the fuel cladding barrier would not be challenged

The inspectors interviewed operations, engineering, work control, radiological protection, and maintenance department personnel and reviewed selected procedures and documents.

In addition, the inspectors reviewed the issues that the licensee entered into the corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance. The inspectors also reviewed the licensees corrective actions for refueling outage issues documented in selected CRs.

b. Findings No findings of significance were identified.

.2 Unit 2 Forced Outage a. Inspection Scope On May 25, 2002, the licensee performed a reactor shutdown to isolate a steam leak and replace one of the main turbine reheat stop valves. The steam leak on the "C" low pressure turbine was due to a cracked weld (approximately 90 degrees around the circumference) on a flange to the right reheat stop valve (2-OME-92). The unit was ramped down at 20 percent per hour and the reactor was tripped at 7:51 p.m. from 15 percent power. The main steam stop valves were shut after the trip to isolate the steam leak, causing a loss of the normal heat sink. Operators maintained temperature using feed and bleed with steam generator blowdown and cycling the steam generator PORVs. Following the reheat stop valve replacement, the licensee synchronized the unit to the grid on June 2, 2002.

The inspectors evaluated the licensees conduct of forced outage activities to assess the licensees control of plant configuration and risk management actions. The inspectors reviewed the cause for the weld failure as well as the extent of condition of other reheat stop valve welds. The inspectors observed portions of the restart activities to verify that requirements of the TSs and administrative procedure requirements were met prior to changing operational modes or plant configurations.

b. Findings No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope For the surveillance test procedures listed below, the inspectors observed selected portions of the surveillance test and/or 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:

Barrier Integrity Cornerstone C 12 MHP 4030-10-03, "Ice Condenser Lower Inlet Door Surveillance" Mitigating Systems Cornerstone C 01 OHP 4030-108-008R, Attachment 8, "Accumulator Check Valve Test" C 01 OHP 4030-STP-017R, "Auxiliary Feedwater Pump Time Response Test" C 02 OHP 4030-214-029, Attachment 1, "PPC [Plant Process Computer] Derived Reactor Thermal Power Evaluation" C 02 OHP 4030-214-029, Attachment 4," Power Range NI [Nuclear Instruments]

Adjustments" C PMI 5070, "Inservice Testing," [Valve Stroke Testing of 1-MCM-221]

C 12 IHP 4030-082-003, "AB, CD and N Train Battery Discharge Test and 18 Month Surveillance Requirements" C 01 OHP 4030.001.002, "Containment Inspection Tours" 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 CRs concerning surveillance testing activities to verify that identified problems were appropriately characterized.

b. Findings No findings of significance were identified.

1R23 Temporary Plant Modifications (71111.23)

a. Inspection Scope The inspectors reviewed the temporary modification listed below to verify that the installation was consistent with design modification documents and that the modification did not adversely impact system operability or availability:

C 12-TM-01-23-R0, "Install Splash Shield on the Unit 1 and Unit 2 AFW Pumps" The temporary modification installed a bearing housing port shield and shaft flinger to prevent water intrusion from water spray and shaft packing leakage. The inspectors verified that configuration control of the modification was correct by reviewing design modification documents and confirmed that appropriate post-installation testing was accomplished. The inspectors reviewed the design modification documents and the 10 CFR 50.59 evaluation against the applicable portions of the UFSAR.

b. Findings No findings of significance were identified.

1EP6 Drill Evaluation (71114.06)

a. Inspection Scope The inspectors observed the conduct of the licensees second quarter unannounced emergency planning drill that was conducted in the licensees control room simulator and emergency response facilities on April 16, 2002. The inspection effort was focused on evaluation of the licensees classifications, notifications, and protective action recommendations for the simulated event. The inspectors also evaluated the licensees conduct of the training evolution, including the licensees critique of performance to identify weaknesses and deficiencies.

b. Findings No findings of significance were identified.

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

.1 Plant Walkdowns and Radiological Boundary Verifications a. Inspection Scope The inspector conducted walkdowns of selected radiologically controlled areas to verify the adequacy of radiological boundaries and postings. The inspector reviewed both the administrative controls specified in radiation work permits (RWPs) and the physical controls (radiological postings and boundaries) for access to these areas, and assessed worker adherence to these controls through direct observation. Specifically, the inspector walked down several radiologically significant work area boundaries (high and locked high radiation areas) in the Unit 1 and Unit 2 Auxiliary Building and in the Unit 1 Containment Building, and performed confirmatory radiation measurements in the Auxiliary Building to verify that these areas and selected radiation areas were properly posted and controlled in accordance with 10 CFR Part 20 and the licensees TSs.

Additionally, the inspector reviewed two incidents that involved locked high radiation area access control problems that occurred in April and May 2002, assessed performance indicator applicability for the incidents and the adequacy of the licensees problem identification, extent of condition evaluation and corrective actions for each event. (Refer to Section 4OA7).

b. Findings No findings of significance were identified.

2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls (71121.02)

.1 Radiation Dose Goals and Trending a. Inspection Scope The inspector reviewed the licensees outage exposure data for the last several refueling outages to establish its prior performance relative to the industry. Job specific and cumulative exposure data and exposure trends for the first three weeks of the scheduled four week Unit 1 Spring 2002 refueling outage (U1C18) were reviewed to assess the licensees current dose performance compared to pre-outage exposure goals and projections. The inspector also reviewed the licensees dose forecasting practices for selected radiologically significant jobs (those with dose expenditure projected greater than approximately 3.5 rem) which were being performed during the outage. The review was performed to determine if adequate technical bases for outage dose estimates existed, and to determine if prior outage experiences and job scope and resource estimates were accurate and used properly to establish reasonable dose projections. Additionally, the inspector reviewed the effectiveness of the RP organizations exposure tracking for the outage to verify that the licensee could timely identify problems with its exposure performance and take actions to address identified deficiencies.

b. Findings No findings of significance were identified.

.2 Radiological Work Planning a. Inspection Scope The inspector reviewed the licensees ALARA program procedures which included a recently implemented ALARA control procedure for radiological risk significant work.

Also, several U1C18 ALARA plans were evaluated to verify consistency with the procedures and to assess their overall adequacy relative to prior licensee practices and industry standards. Specifically, the inspector selected the following outage jobs that were projected to accrue in excess of 5 rem, and assessed the adequacy of the radiological controls and the work planning developed for each:

C Scaffold Erection/Removal in Containment (RWP 021136)

C Steam Generator Manway and Diaphragm Activities (RWP 021140)

C Valve Maintenance and Repair Activities in Containment (RWP 021139)

C Insulation Removal, Reinstallation and Modification in Containment (RWP 021134)

C Steam Generator Primary Work - Platform Activities (RWP 021141)

The inspector reviewed the RWP and the ALARA plan developed for each job, and assessed the radiological engineering controls and other dose mitigation techniques specified in these documents to verify that the plans were completed in compliance with procedures, included appropriate controls to reduce dose, and were sufficiently

comprehensive. These documents were also reviewed to determine if job history files, lessons the licensee learned from its recent Unit 2 outage, and industry operating experiences were adequately integrated into each work package. Additionally, the inspector discussed ALARA planning with several RP staff to verify that adequate interface between contractors, station work groups, and RP ALARA staff occurred during job planning.

b. Findings No findings of significance were identified.

.3 Implementation of ALARA Controls and Radiological Oversight of Work a. Inspection Scope The inspector selected the following high exposure or high radiation area jobs conducted during the outage and reviewed the execution of the ALARA program:

C Reactor Head Die Penetrant Testing (RWP 021152)

C Steam Generator Platform/Manway Activities (RWP 021140 and RWP 021141)

C Installation of Temporary Shielding in Containment (RWP 021119)

C Valve Activities in Containment (RWP 021139)

C Scaffold Erection in Containment (RWP 021136)

The inspector discussed the radiological performance for each activity with RP ALARA staff and reactor head die penetrant testing and various steam generator platform activities were observed. Also, total effective dose equivalent (TEDE) ALARA evaluations completed for these activities and for other outage work activities were assessed for technical adequacy. Work in progress reports and radiological survey data for these and other selected jobs, as applicable, were also reviewed to assess their adequacy and consistency with the licensees procedures. The pre-job briefings for head die penetrant testing and for steam generator manway installation were attended to verify that the work activities were adequately planned and that radiological information was exchanged effectively. The inspector evaluated the licensees radiological engineering controls utilized at selected work locations to determine if the controls were consistent with those specified in the ALARA plans. Additionally, the inspector reviewed a radiological intake incident that occurred during steam generator eddy current testing, and assessed the licensees response to the incident and the adequacy of the RP staffs evaluation of the problem and its corrective actions. (Refer to Section 20S2.7)

b. Findings No findings of significance were identified.

.4 Verification of Exposure Estimates and Exposure Tracking Systems a. Inspection Scope The inspector reviewed the methodology and specific assumptions used by the ALARA group to develop U1C18 dose estimates, and compared collective outage and individual job dose performance for the first three weeks of the outage to assess dose performance and determine the accuracy of pre-outage projections. The inspector selectively reviewed job dose history files and dose reduction techniques applied to selected jobs to verify that previous problems had been adequately addressed. In particular, the inspector reviewed those jobs which accrued greater than 5 rem and which the dose expenditure significantly differed from original dose projections, to determine whether revised dose estimates were justified and could not reasonably have been accurately projected initially. The inspector also reviewed the process used to revise dose estimates and capture lessons learned to verify compliance with the licensees ALARA procedure. As of May 24, 2002, the licensee had recorded an outage exposure of approximately 95 rem compared to its estimate of about 105 rem for that stage of the outage, and projected that its revised outage dose estimate of approximately 130 rem would be met. Selected work in progress reports were examined to evaluate the licensees ability to assess the effectiveness of a job, to execute its ALARA plan, and to institute changes in work plans, if warranted. The licensees exposure tracking system was also reviewed to determine if the level of exposure tracking detail, exposure report timeliness, and report distribution were sufficient to support the control of outage exposures.

b. Findings No findings of significance were identified.

.5 Source Term Reduction and Control b. Inspection Scope The inspector reviewed some of the exposure reduction initiatives taken for the outage such as flushing and installation of temporary shielding. Also, the licensees water chemistry control program implemented during the Unit 1 shutdown was selectively evaluated to determine its impact on outage source term reduction. The evaluation was conducted to determine whether the shutdown chemistry program was implemented consistent with station procedures and industry practices. In particular, the effectiveness of a new CRUD burst chemistry initiative that involved the use of a deborating demineralizer loaded with powdered resins to supplement the mixed bed demineralizer system was reviewed by the inspector.

b. Findings No findings of significance were identified.

.6 Identification and Resolution of Problems a. Inspection Scope The inspector reviewed the results of an ALARA group root cause analysis which assessed work planning and work execution problems experienced during the licensees previous outage in February 2002. The inspector also reviewed outage related Performance Assurance Department field observations, RP program related CRs generated during the outage and rapid event response and apparent cause evaluation reports related to the access control problems discussed in Section 4OA7 and the intake incident described in Section 2OS2.7. This review was performed to verify that the licensee adequately identified individual problems and trends, determined contributing causes and extent of condition, and developed appropriate corrective actions.

b. Findings No findings of significance were identified.

.7 Review of a Radiological Intake Incident During Steam Generator Eddy Current Testing a. Inspection Scope The inspector reviewed the circumstances associated with a radiological intake incident that occurred during the Unit 1 refueling outage on May 18, 2002, associated with steam generator tube eddy current testing. Specifically, the inspector reviewed the licensees preliminary rapid event response report, the ALARA plan and RWP that governed the work activity, and discussed the incident with RP staff. The inspector also independently calculated the committed effective dose equivalent (CEDE) assigned to the workers to verify the accuracy of the licensees assessments. Additionally, the inspector independently evaluated the potential for an exposure in excess of regulatory limits based on the radiological conditions present.

b. Findings A Green finding and an associated Non-Cited Violation were identified for the failure to use all intended radiological engineering controls during steam generator eddy current testing to control contamination and airborne radioactivity. In addition, the finding is tied to human performance.

On May 18, 2002, two contract workers involved in positioning steam generator eddy current test equipment in the number 11 steam generator were contaminated while performing the task. Shortly thereafter and prior to recognizing the problem, two other contract workers were contaminated as they cleaned-up the steam generator platform areas that were just vacated by the first two workers.

The two workers positioning eddy current equipment relocated a robotic device (termed ROGER) from the generators hot leg to the cold leg. The ROGER was used to position and maneuver eddy current test probes within the steam generators. The equipment was highly contaminated (1Rad/hour of removable contamination/100 square

centimeters or about 20 million disintegrations per minute) and necessitated proper radiological engineering controls to prevent airborne radioactivity. The ALARA staffs evaluation showed that respiratory protection equipment was not warranted for the work activity provided the necessary radiological controls were in-place, so the workers wore only face shields to reduce the potential for facial contamination. The radiological engineering controls to be used for the work included a high efficiency particulate air (HEPA) filtered ventilation system installed on the opposite generator manway leg and the spraying/wiping-down of all items removed from the generator. While the latter controls were not specified in either the RWP or the ALARA plan due to an oversight, these specific controls were communicated to the work crews during pre-job briefings and had also been a standard industry practice for any equipment removed from the generators. Despite these instructions, the ROGER was not wiped-down or wetted as it was removed from the generator hot leg. The licensees event response found that the workers reasoned that since the ROGER was being relocated from one leg of the generator to another, it was not necessary to wipe or spray the equipment down. The problem compounded because the radiation protection technician assigned to cover the work activity was providing assistance on another generator platform at the time the ROGER was removed from the hot leg. Since the relocation and positioning of the equipment was physically intensive and the equipment was handled roughly, the licensee concluded that contamination dried-out and was jarred loose and became airborne. Once airborne, contaminated dust-like particles became an ingestion and inhalation hazard unbeknownst to the two workers.

Installation of the ROGER in the cold leg was completed near the end of the work shift on May 18 and the two workers left the platform without recognizing the radiological hazard that was created. The workers alarmed the personnel contamination monitors as they attempted to leave the Containment Building. The two other workers that subsequently cleaned the platforms also alarmed the monitors as they left the work area. Positive nasal smears and/or facial contamination prompted whole body count analyses of all four workers and each showed small intakes of radioactive material.

Further evaluation by the licensee disclosed intakes through both inhalation and ingestion pathways with the maximum dose calculated at about 60 mrem CEDE.

This issue had an actual impact on radiological safety and if not corrected would become a more significant concern should other radiological engineering controls not be implemented as intended. Also, the issue involved unintended dose (from intakes)

which resulted from the failure to implement the radiological controls required by regulatory requirements and those that were intended by the RWP/ALARA plan for the work activity. Therefore, the issue represents a finding which was evaluated using the SDP for the occupational radiation safety cornerstone. Since radiation exposures to involved workers were low relative to regulatory limits and because radiological conditions (removable contamination levels) were not of a magnitude sufficient to create a substantial potential for an overexposure (as evaluated by the inspector), the issue was determined to be of very low safety significance.

10 CFR 20.1701 requires that the licensee use, to the extent practical, process or engineering controls to control the concentration of radioactive material in air. The failure to implement all intended radiological engineering controls communicated to the work crew is a violation of that regulatory requirement. However, because the

licensee documented this issue in its corrective action program (CR 02139007) and because the violation is of very low safety significance, it is being treated as a Non-Cited Violation (NCV 50-315-02-03-05(DRS)).

Cornerstone: Public Radiation Safety 2PS2 Radioactive Waste (Radwaste) Processing and Transportation (71122.02)

.1 Walkdowns of Radwaste Systems a. Inspection Scope The inspector reviewed the liquid and solid radioactive waste system descriptions in the UFSAR and the annual radiological effluent release reports for calendar years 2000 and 2001, for information on the types and amounts of radwaste disposed. The inspector walked down the liquid and solid radwaste processing systems located in the Auxiliary Building, including the abandoned in-place radwaste evaporator system, to verify that the systems that remained in-use and operable were consistent with the descriptions in the UFSAR and the Process Control Program (PCP) and to assess their material condition. These walkdowns were also performed to determine if radiological postings were proper and if radiological access was controlled into these areas in accordance with the requirements in 10 CFR Part 20 and the licensees TSs. The inspector reviewed the current processes for transferring radwaste resins and sludge into shipping containers to determine if appropriate waste stream mixing and sampling methods were utilized and to verify that representative samples were obtained of the waste product.

b. Findings No findings of significance were identified.

.2 Waste Characterization and Classification a. Inspection Scope The inspector reviewed the licensees methods and procedures for determining the classification of radwaste shipments, including the use of scaling factors to quantify difficult to measure" radio-nuclides (e.g., pure alpha and low energy beta emitting materials). Specifically, the inspector reviewed the licensee's 2000 and 2001 radio-chemical analysis results for the plant's waste streams which consisted of primary and secondary (radwaste) system resins, sludge, filter media and cartridges, and dry active waste (DAW). The inspector reviewed these analyses to ensure that the scaling factors were accurately determined to allow waste shipments to be classified in accordance with the requirements of 10 CFR Part 61, consistent with the licensee's procedure. The inspector also reviewed the licensee's practices to ensure that changes in reactor operating parameters that could produce changes to the waste stream radio-nuclide composition were identified between annual scaling factor reevaluation.

Additionally, the inspector performed independent calculations to verify proper scaling factor application and to determine if the activities of certain difficult to detect

radio-nuclides were accurate and if waste streams were classified in accordance with 10 CFR Part 61. An inspector identified deficiency with the recent application of the scaling factor for carbon-14 activity determinations were assessed to verify that it did not result in mis-classified waste streams.

b. Findings No findings of significance were identified.

.3 Shipment Preparation and Observation of Radwaste Processing Activities a. Inspection Scope The inspector observed two pre-job briefs and evaluated the preparations, including the operations department interface, associated with the sluice of primary system resins from the spent resin storage tank into a high integrity container. The evaluation was conducted to assess the overall adequacy of the work planning and to verify that work preparations were completed consistent with the resin transfer procedure. The inspector witnessed the sluice operation and discussed its performance with involved staff to verify that the work was executed in accordance with station procedure, to determine if supervisory oversight was adequate, and to assess the adequacy of the radiological controls for the work activity. Since there were no radioactive material shipments during the inspection, the inspector reviewed training and qualification records for those staff involved in radwaste processing and shipment activities.

Specifically, the inspector reviewed training certificates for the licensees four authorized shippers and training lesson plans and qualification records for environmental technicians involved in the processing and shipment of radwaste and radioactive material. The documents were reviewed to verify that the licensees program provided hazardous material training to those personnel responsible for radioactive material shipments and shipment preparation, as required by Subpart H of 49 CFR Part 172.

b. Findings No findings of significance were identified.

.4 Shipment Records a. Inspection Scope The inspector reviewed radioactive material and radwaste shipment manifests and associated records for eight non-excepted shipments (Low Specific Activity II, Surface Contaminated Object II and a Type B package shipment) completed between September 1999 and February 2002. The review was performed to verify compliance with NRC requirements contained in 10 CFR Parts 20, 61 and 71, and the Department of Transportation (DOT) requirements of 49 CFR Parts 172 and 173. Specifically, records were reviewed and those staff involved in shipment activities were interviewed to verify that packages were labeled and marked properly, that package and transport vehicle surveys satisfied DOT requirements, that cask certificate of compliance requirements were satisfied, and that shipment manifests were completed in

accordance with the regulations and included appropriate emergency response information.

b. Findings No findings of significance were identified.

.5 Identification and Resolution of Problems a. Inspection Scope The inspector reviewed a self-assessment, Performance Assurance Department audits and field observations, and CRs completed since January 2001, which addressed the areas of radwaste processing and radioactive material/radwaste shipping. The inspector reviewed these documents to assess compliance with the quality assurance program audit requirements of 10 CFR Part 71 and Appendix G of 10 CFR Part 20 and to evaluate the licensees ability to identify problems, to determine contributing causes and extent of condition, and to implement corrective actions to prevent recurrence. The inspector also discussed the licensees audit and field observation program with Performance Assurance staff including the scope of their recent activities and plans to enhance the program.

b. Findings No findings of significance were identified.

3. SAFEGUARDS Cornerstone: Physical Protection 3PP1 Access Authorization (AA) Program (Behavior Observation Only) (71130.01)

a. Inspection Scope The inspectors interviewed five supervisors and five non-supervisors (both licensee and contractor employees) to determine their knowledge level and practice of implementing the licensees behavior observation program responsibilities. Selected procedures pertaining to the Behavior Observation Program and associated training activities were also reviewed. Also licensee fitness-for-duty semi-annual test results were reviewed. In addition, the inspectors reviewed a sample of licensee self-assessments, audits, and security logged events. The inspectors also interviewed security managers to evaluate their knowledge and use of the licensees corrective action system.

b. Findings No findings of significance were identified.

3PP2 Access Control (Identification, Authorization and Search of Personnel, Packages, and Vehicles) (71130.02)

a. Inspection Scope The inspectors reviewed the licensees protected area access control testing and maintenance procedures. The inspectors observed licensee testing of all access control equipment to determine if testing and maintenance practices were performance based.

On two occasions, during peak ingress periods, the inspectors observed in-processing search of personnel, packages, and vehicles to determine if search practices were conducted in accordance with regulatory requirements. Interviews were conducted and records were reviewed to verify that security staffing levels were consistently and appropriately implemented. Also the inspectors reviewed the licensees process for limiting access to only authorized personnel to the protected area and vital equipment by a sample review of quarterly access authorization reviews performed by managers. The inspectors reviewed the licensees program to control hard-keys and computer input of security-related personnel data.

The inspectors reviewed a sample of licensee self-assessments, audits, maintenance request records, and security logged events for identification and resolution of problems.

In addition, the inspectors interviewed security managers to evaluate their knowledge and use of the licensees corrective action system.

b. Findings No findings of significance were identified.

4. OTHER ACTIVITIES (OA)

4OA1 Performance Indicator Verification (71151)

a. Inspection Scope The inspectors verified the data for the Physical Protection performance indicators pertaining to Fitness-For-Duty Personnel Reliability, Personnel Screening Program, and Protected Area Security Equipment. Specifically, a sample of plant reports related to security events, security shift activity logs, fitness-for-duty reports, and other applicable security records were reviewed for the period between October 1, 2001 and April 1, 2002.

b. Findings No findings of significance were identified.

4OA3 Event Follow-up (71153)

.1 (Closed) Licensee Event Report (LER) 50-316-2002-001-00: Containment Isolation Valve Alignment Error During Local Leak Rate Testing." This event is discussed in Section 1R14.1 of this report. In addition, this issue was identified as an input to a significant cross-cutting issue as discussed in Section 4OA4 of this report. This LER is closed.

.2 (Closed) LER 50-315-2002-002-00: Pressurizer Power Operated Relief Valves Inoperable Due to Control Switch Position." This event is discussed in Section 1R14.2 of this report. In addition, this issue was identified as an input to a significant cross-cutting issue as discussed in Section 4OA4 of this report. This LER is closed.

.3 (Closed) LER 50-316-2002-002-00: "Technical Specification 3.9.4.c Was Violated During Core Alterations." The licensee failed to maintain refueling integrity configuration control of containment penetration CPN-74 during core alterations when containment isolation valve (2-XCR-101) was stroked open for testing. Opening this valve created a direct access path from the containment atmosphere to the outside atmosphere. The licensee reported this event as a condition prohibited by the plant's TSs in accordance with 10 CFR 50.73(a)(2)(i)(B). The inspectors determined that this issue had a credible impact on safety because the licensee failed to have the containment penetration isolated as required by the TSs.

The inspectors utilized the event information in conjunction with Appendix G, Shutdown Operations Significance Determination Process, of Manual Chapter 0609, Table T-1, Pressurized Water Reactor (PWR) Refueling Operation Reactor Coolant System (RCS)

Level > 23' OR PWR Shutdown Operation with Time to Boil > 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months AND Inventory in the Pressurizer. This issue was determined to be of very low significance (Green) by the significance determination process because (1) the issue did not increase the likelihood of a loss of primary coolant system inventory; (2) the issue did not degrade the licensees ability to terminate a leak path or add RCS inventory when needed; and (3) the issue did not degrade the licensees ability to recover decay heat removal once lost. Although this issue affected the integrity of the reactor containment during core alterations, the inspectors concluded that because 2-XCR-101 was open for a short period of time and the small diameter penetration would be a very small leakage path, this issue was of very low safety significance (Green).

Technical Specification 3.9.4.c, states, in part, that each containment penetration providing direct access from the containment atmosphere to the outside atmosphere shall be either closed by an isolation valve, blind flange, manual valve, or equivalent during core alterations or movement of irradiated fuel within the containment. With the above requirement not satisfied, immediately suspend all operations involving core alterations or movement of irradiated fuel in the Containment Building. Contrary to the above, on February 12, 2002, the licensee failed to maintain containment isolation valve 2-XCR-101 closed to isolate containment penetration 2-CPN-74 during core alterations.

This is a violation of TS 3.9.4.c. Because of the very low safety significance, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the NRC Enforcement Policy (NCV 50-316-02-03-06(DRP)). The licensee entered this violation into its corrective action program as CR 02043026. This LER is closed.

.4 (Closed) LER 316-2001-002-00 and LER 316-2001-002-01: Failure of Lower Containment Airlock Door Interlock Results in Inadvertent Opening of Both Doors".

Supplement 1 of this LER was submitted to provide revised information from the completed root cause evaluation and replaced the original LER in its entirety. This event is discussed in Section 1R14.3 of this report. In addition, this issue was identified as an input to a significant cross-cutting issue as discussed in Section 4OA4 of this report. This LER and its supplement are closed.

.5 Ice Condenser Lower Inlet Door Testing a. Inspection Scope As discussed in Section 1R22.b.3 of NRC Inspection Report 50-315/316-01-20(DRP),

the inspectors previously identified that the licensees ice condenser lower inlet door testing methodology had not been capable of demonstrating compliance with the requirements of TS 4.6.5.3.1.b. The licensee subsequently revised its lower inlet door testing methodology in February 2002. At the time this condition was discovered, Unit 2 was in a shutdown mode and the licensee was able to retest the Unit 2 lower inlet doors using the revised test methods and demonstrate compliance with TS 4.6.5.3.1.b. Based on the results on the Unit 2 door retests, the inspectors were able to assess the safety significance of this issue and identified NCV 50-316-01-20-07(DRP).

Because lower inlet door testing requires the associated unit to be in at least Mode 5 (Cold Shutdown), the licensee was unable to retest the Unit 1 lower inlet doors in February 2002. Instead, the licensee requested, and was granted, Emergency TS Amendment 265 to defer Unit 1 lower inlet door testing until Unit 1 entered the Cycle 18 refueling outage or a Mode 5 entry of sufficient duration. Because as found door testing data had not been obtained for Unit 1, the inspectors were unable to assess the significance of this issue for Unit 1 and identified Unresolved Item (URI)

50-315-01-20-08(DRP) pending completion of a final significance determination. During the Unit 1 Cycle 18 refueling outage, the licensee tested the Unit 1 lower inlet doors using the revised test methodology. The inspectors reviewed the testing results and assessed the safety significance of the previously identified finding using the as-found results of this testing. The inspectors also reviewed two LERs that were issued as a result of this finding.

b. Findings The inspectors identified a finding of very low safety significance (Green) associated with the licensee's failure to establish an ice condenser lower inlet door testing methodology capable of demonstrating compliance with Unit 1 TS surveillance requirements. This finding was dispositioned as a Non-Cited Violation.

b.1 (Closed) URI 50-315-01-20-08(DRP): "Failure to Adequately Measure the Ice Condenser Lower Inlet Door Opening Torque and Closing Torque in Accordance with TS Requirements."

Description As discussed in NRC Inspection Report 50-315/316-01-20(DRP), the inspectors previously determined that the licensees ice condenser lower inlet door testing methodology was inadequate. Specifically, the methodology used to perform previous ice condenser lower inlet door testing on November 21, 2000 under Job Order R0087658 did not accurately determine door opening and closing torques in accordance with TS 4.6.5.3.1.b.3 and TS 4.6.5.3.1.b.4. Consequently, the licensee was unable to adequately calculate inlet door friction in accordance with TS 4.6.5.1.b.5. During a review of the door testing data obtained under Job Order R0087658, the inspectors noted that the door opening torques for 36 of the 48 inlet doors were less than the associated door closing torques. Based on the inlet door design and configuration, the inspectors concluded that door opening torque must be greater than door closing torque. Based on these previous testing results, the inspectors concluded that the licensees failure to adequately demonstrate compliance with the requirements of TS 4.6.5.3.1.b.3, TS 4.6.5.3.1.b.4, and TS 4.6.5.3.1.b.5 was a violation of NRC requirements.

In accordance with Unit 1 Licensee Amendment 265, the licensee measured the as-found lower inlet door torque and friction using the revised methodology under Job Order R0210872 in May 2002. During this testing, all friction and closing torque measurements were found to be within the TS allowable values. However, the licensee determined that the opening torque for one lower inlet door (bay 15 right) failed to meet the TS allowable opening torque. Specifically, the as-found opening torque for door 15 right was 212.6 inch-pounds, or approximately 18 inch-pounds greater than the TS 4.6.5.3.1.b.3 requirement of less than 195 inch-pounds.

Analysis The inspectors evaluated this failure to adequately perform testing required by TS 4.6.5.3.1.b using the SDP. The inspectors determined that the failure to adequately implement TS 4.5.6.3.1.b testing requirements for the Unit 1 ice condenser lower inlet doors had a credible impact on safety and was more than a minor concern. Specifically, failing to adequately execute surveillance test requirements could credibly result in the failure to identify and correct degraded or inoperable equipment. As stated in the TS 3.6.5 bases, operability of the ice condenser doors ensures that reactor coolant fluid released during a loss of coolant accident (LOCA) will be diverted through the ice condenser bays for heat removal. The ice condenser also augments the containment recirculation sump water inventory in the event of certain small break LOCAs and limits ice maldistributions within the ice condenser. Because the proper functioning of the ice condenser lower inlet doors was primarily associated with the heat removal function of the ice condenser, the inspectors determined that this issue was associated with the barrier integrity cornerstone. Based on a review of the as-found Unit 1 lower inlet door testing performed in May 2002, the inspectors concluded that there was no reduction in the atmospheric pressure control function of the reactor containment nor a loss of capability to provide additional recirculation sump inventory during certain small break LOCAs. Specifically, all inlet doors, except for door 15 right, met TS 4.5.6.3.1.b requirements during as-found testing. Although the door 15 right opening torque exceeded the TS maximum allowable opening torque, the as-found opening torque of

212.6 inch-pounds was bounded by the 252 inch-pound upper design limit described in the NRC staffs safety evaluation associated with Unit 1 License Amendment 265.

Consequently, the inspectors concluded that this issue was of very low safety significance.

Enforcement Technical Specifications 4.6.5.3.1.b.3, 4.6.5.3.1.b.4, and 4.6.5.3.1.b.5 require testing of the ice condenser lower inlet doors at least once per 18 months in order to measure the torque required to open the door, the torque required to keep the door from closing, and the door frictional torque. Technical Specification 4.6.5.3.1.b.3 stated that the door opening torque was equal to the nominal door torque plus a frictional torque component.

Technical Specification 4.6.5.3.1.b.4 stated that the door closing torque was equal to the nominal door torque minus a frictional torque component. Contrary to the above, previous TS 4.6.5.3.1.b surveillance testing performed in Unit 1 on November 21, 2000, failed to adequately measure the door opening torque and the door closing torque in accordance with TS requirements. Specifically, the methodology used by the licensee to perform TS 4.6.5.3.1.b.3 and TS 4.6.5.3.1.b.4 resulted in door closing torques that were greater in magnitude than the door opening torques, contrary to the TS description of these torque values. The inspectors identified that the measured opening torque values for 36 Unit 1 lower inlet doors were less than the associated door closing torque.

Because calculation of the door frictional torque required accurate measurement of the door opening and closing torques, the licensee was unable to demonstrate compliance with the requirements of TS 4.6.5.3.1.b.5. Consequently, Unit 1 was operated in a Mode requiring operability of the lower ice condenser inlet doors for approximately 16 months between December 2000 and May 2002 without meeting the requirements of TS 4.6.5.3.1.b. During subsequent testing conducted on May 12, 2002, the licensee identified that lower inlet door 15 right had an opening torque in excess of the requirements of TS 4.6.5.3.1.b.3. Because of the very low safety significance, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the NRC Enforcement Policy (NCV 50-315-02-03-07(DRP)). The licensee entered this violation into its corrective action program as CR 02032016. This URI is closed.

b.2 (Closed) LER 50-315-2002-004-00: "Unit 1 Ice Condenser Lower Inlet Door Test Failure." The licensee issued LER 50-315-2002-004-00 to document the failure of ice condenser lower inlet door 15 right to meet TS 4.6.5.3.1.b.3 requirements. The licensee stated that the cause of the excessive door opening torque failure was incorrect door closing spring adjustment following refurbishment during the 1997-2000 extended dual unit shutdown. Consequently, lower inlet door 15 right failed to meet TS requirements for door opening torque for approximately 15 months. Although the licensee tested door 15 right following these previous refurbishment activities, the inspectors determined that the licensees failure to identify the incorrect door closing spring adjustment was due to the use of an inadequate testing methodology. The inspectors have already concluded that the licensees use of an inadequate door testing methodology was a violation of NRC requirements (refer to Section 4OA3.5.b.1 of this report) and, therefore, no additional enforcement action is warranted. The inspectors identified no other issues of significance during this review. This LER is closed.

b.3 (Closed) Licensee Event Report (LER) 50-315-2002-001-00: "Failure to Perform Ice Condenser Door Testing In Accordance With TSs." The inspectors reviewed this event and issued NCV 50-316-01-20-07(DRP) and NCV 50-315-02-03-07(DRP) for the licensees failure to adequately test ice condenser lower inlet doors as required by TS 4.6.5.3.1.b.3. The inspectors determined that the information provided in LER 50-315-2002-001-00 did not raise any new issues or change the conclusions of the initial reviews, which were documented in NRC Inspection Report 50-315/316-01-20(DRP) and in Section 4OA3.5.b.1 of this report. This LER is closed.

.6 Cell Cracking Rendered the Unit 2 AB 250 Volt Station Battery Inoperable and Review of Associated NOED a. Inspection Scope On April 3, 2002, a licensee maintenance electrician identified cracks on the top covers of two battery cells in the 2AB battery. Although the cracking indicated abnormal deterioration of the battery as described in TS 4.8.2.3.2.c.1, the licensee did not declare the battery inoperable until April 4, 2002, and enter the appropriate TS action statement until approximately 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months after the initial identification of the cell deterioration. During follow-up investigations, the licensee identified that a third cell on the 2AB battery also exhibited abnormal cracking. The licensee requested, and was granted, an NOED to extend the TS 3.8.2.3 allowable outage time of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months in order to support repair and testing activities necessary to return the 2AB station battery to an operable status. As required by TS 3.8.2.3, the licensee had initiated a shutdown of Unit 2, but terminated the shutdown at approximately 40 percent power when NOED-02-3-01 was issued. The licensee returned the 2AB battery to an operable status within the extended allowable outage time and returned the unit to full power on April 7, 2002. On May 29, 2002, the licensee issued LER 50-316-2002-003-00, which reported this issue as an operational NOED condition prohibited by the TSs because the battery was inoperable for longer than allowed by TS 3.8.2.3. The inspectors reviewed the cause of the licensee's delayed entry into the TS 3.8.2.3 Limiting Condition for Operation on April 4, 2002, the basis for the licensee's NOED request, and the licensee's compliance with the compensatory actions of the NOED.

b. Findings b.1 (Closed) LER 50-316-2002-003-00: "2AB 250 D.C. [Direct Current] Volt Battery Inoperable For Longer Than Allowed By Plant's TSs."

The action statement for TS 3.8.2.3.2, "D.C. Distribution - Operating," required that an inoperable battery be restored to operable status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or the plant be placed in Hot Standby within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The inspectors previously documented a review of this issue in NRC Inspection Report 50-315/316-02-004(DRP), Section 4OA2.1.2. The inspectors determined that the failure to take prompt action to address abnormal deterioration of the safety-related battery constituted a violation of NRC requirements and issued NCV 50-316-02-04-01(DRP) for this condition. The licensees corrective actions for this condition were reviewed and considered adequate. The inspectors reviewed the associated LER and did not identify any additional significant issues. This LER is closed.

b.2 (Closed) URI 50-316-02-03-08 (DRP): "Review of NOED-02-3-01 Regarding D.C. Cook, Unit 2, Compliance With TS 3.8.2.3."

The inspectors opened URI 50-316-02-03-08(DRP) to track documentation of the root cause for the NOED request, review of the NOED approval basis, and verification of licensee activities associated with NOED implementation. As discussed in NRC Inspection Report 50-315/316-02-04(DRP), the inspectors reviewed the performance history of the station batteries to determine if the licensee had prior opportunities to identify and correct the battery cell cracking prior to requesting an NOED. The inspectors determined that the licensees actions to address the condition prior to April 3, 2002, did not constitute a violation of NRC requirements. The inspectors concluded that the licensee provided a reasonable basis for the NOED and appropriately implemented compensatory measures. This URI is closed.

.7 Significance Determination Process Review for Gas Binding of Unit 2 Centrifugal Charging Pump (CCP) Due to Inadequate Valve Maintenance Activity a. Inspection Scope On February 16, 2002, the Unit 2 West CCP exhibited indications of gas binding following swap over of the suction source from the volume control tank to the refueling water storage tank. The inspectors concluded that the cause of the CCP gas binding was the licensee's failure to ensure that valve 2-CS-369 (reactor coolant pump seal water heat exchanger to volume control tank shutoff valve) was fully closed, resulting in transfer of volume control tank cover gas directly to the suction of the Unit 2 CCPs. This issue was identified as URI 50-316-02-02-01(DRP) pending completion of the safety significance determination for the gas binding event. The inspectors, with the assistance of the Region III Senior Reactor Analysts, performed additional safety significance reviews of this issue and reviewed the licensee's completed apparent cause evaluation for this event.

b. Findings (Closed) URI 50-316-02-02-01(DRP): "Failure to Perform Adequate Maintenance and Testing on Valve 2-CS-369 Resulted in Gas Binding the Unit 2 West Centrifugal Charging Pump."

A self-revealed finding of very low safety significance (Green) was identified for the licensee's failure to provide instructions of a type appropriate to the circumstances for maintenance on valve 2-CS-369. The inspectors determined that this issue constituted a violation of 10 CFR 50 Appendix B, Criterion V, "Instructions, Procedures, and Drawings," and therefore dispositioned this issue as a Non-Cited Violation.

Description Following the February 16, 2002, CCP gas binding event, the licensee determined that the position of the valve stem stop nut prevented full closure of 2-CS-369 and allowed gas to vent from the volume control tank directly to the CCP suction line. Approximately two weeks before this event, on February 1, 2002, the licensee performed preventative

maintenance activities on 2-CS-369 in accordance with Job Order 01094018 and procedure 12 MHP 5021.001.023, "Manual Diaphragm Valve Maintenance," Revision 6.

Steps 6.6.3, 6.6.4, and 6.6.5 of 12 MHP 5021.001.023, which positioned the stop nut after valve reassembly, required that the stem stop nut be positioned in contact with the valve handwheel after the valve was turned clockwise 1/8 of a turn beyond the closed seat contact point by tightening the stem lock nut. The stem lock nut was then tightened into the stem stop nut to lock the stop nut into position. The purpose of these steps was to lock the stop nut in a position that would allow full closure of 2-CS-369 without applying excessive compressive force on the valve diaphragm.

The licensees apparent cause evaluation for this condition, which was documented in CR 02047050, concluded that the 12 MHP 5021.001.023 stem stop nut adjustment instructions were inconsistent with vendor recommendations and left the valve susceptible to stop nut loosening if the valve was tightly closed. Specifically, the licensee determined that tightly closing the valve with the stop nut positioned per this guidance resulted in high contact forces between the handwheel and stem stop nut.

Binding between the stem stop nut and handwheel during subsequent opening operations could then cause the stop nut to loosen, preventing full valve closure. The licensee determined that use of the vendor recommended procedure for stem stop nut adjustment left a gap between the handwheel and stem stop nut and therefore prevented binding that could loosen the stem stop nut. Consequently, the inspectors determined that the failure to provide stem stop nut adjustment instructions in 12 MHP 5021.001.023 of a type appropriate to the circumstances constituted a violation of NRC requirements.

Analysis The inspectors assessed this issue using the SDP. The inspectors concluded that this issue had a credible impact on safety and was therefore more than a minor concern.

Specifically, gas intrusion into the common suction lines of both Unit 2 CCPs with the suction source aligned to the refueling water storage tank impacted the capability of the high head injection system to provide the inventory and reactivity control safety functions. Furthermore, the inspectors determined that this issue was associated with the mitigating systems cornerstone. The inspectors concluded that 2-CS-369 was in a degraded condition from February 1, 2002, when the valve diaphragm was replaced, to February 16, 2002, when the condition was identified and corrected. Because Unit 2 was in a shutdown mode during this period, the inspectors performed a Phase 1 SDP review of this issue using the guidance provided in IMC 0609, Appendix G, "Shutdown Operations Significance Determination Process." During this Phase 1 review, the inspectors concluded that this issue degraded the licensees ability to add inventory to the RCS and therefore a Phase 2 SDP analysis was required. A modified Phase 2 shutdown risk SDP analysis was performed with the assistance of the Region III Senior Reactor Analyst and headquarters probabilistic risk assessment staff. The following factors were considered during this shut down risk assessment:

C Shutdown initiating event frequencies were obtained from NUREG/CR-6144,

"Evaluation of Potential Severe Accidents During Low Power and Shutdown Operations at Surry, Unit 1."

C A loss of the operating train of residual heat removal caused by gas intrusion was not considered to be credible due to the torturous path the gas would have to follow in order to bind the residual heat removal system. Although the safety injection (SI) pumps share a common suction with the CCPs from the refueling water storage tank, check valve 2-SI-185 would prevent migration of gas to the suction of the SI pumps. The licensee seat leak tested 2-SI-185 on February 8, 2002, and measured a seat leakage rate of 0 gpm. Consequently, the estimation of risk significance assumed that only the charging system was affected by the performance deficiency.

C This deficiency does not increase the likelihood or severity of a loss of offsite power event, so this initiating event is not considered.

C The risk assessment considered the following plant configuration states:

(1) 5 days in Mode 6 (Refueling) with the refueling cavity full and SI pumps available, (2) 2.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months in Mode 6 with the refueling cavity full and SI pumps unavailable, (3) draining to mid-loop operations after refueling to support RCS vacuum refill, (4) 1 day of mid-loop operations after refueling, and (5) a reactivity accident during mid-loop operations.

C Because recovery of the charging system would require identifying the performance deficiency and implementation of appropriate corrective actions, no recovery credit was applied.

C The use of the opposite units high head injection via a unit cross tie was credited in the analysis. Although procedures did not specifically address use of the charging system cross tie for loss of shutdown cooling events, the cross-connect valves were regularly tested and the operators were trained on the cross-connection procedures.

C The 2-CS-369 diaphragm was replaced on February 1, 2002, with Unit 2 defueled. Unit 2 entered Mode 6 on February 10, 2002, and completed core reload on February 12, 2002. Because the degraded condition of 2-CS-369 was identified and corrected on February 16, 2002, the safety function provided by the CCPs was degraded for approximately 6 days with fuel in the reactor vessel.

C Based on the observed Unit 2 West CCP performance during the gas intrusion event on February 16, 2002, (decreased pump amperage and near 0 gpm flowrate), the inspectors concluded that the degraded condition of 2-CS-369 would render the CCPs unavailable when aligned to the refueling water storage tank.

Based on a consideration of the above factors, the total change in Core Damage Frequency associated with this issue was estimated to be 3E-7 per year. Therefore, this issue was considered to be of very low safety significance.

Enforcement 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above, the licensee failed to provide procedures of a type appropriate to the circumstances for the adjustment of the stem stop nut on 2-CS-369, which is an activity affecting quality. Specifically, the instructions for stem stop nut adjustment contained in 12 MHP 5021.001.023, "Manual Diaphragm Valve Maintenance," Section 6.6, Revision 6 were inconsistent with vendor recommendations and rendered the valve susceptible to loosening of the stem stop nut. The stem stop nut for 2-CS-369 was adjusted in accordance with these instructions on February 1, 2002. This issue was self-revealed on February 16, 2002, when the Unit 2 West CCP became gas bound due to leakage of volume control tank cover gas through the partially opened valve 2-CS-369 into the common suction header for the Unit 2 CCPs. Subsequent investigation identified that the 2-CS-369 stem stop nut was loose and in a position that prevented full closure of the valve. Because of the very low safety significance, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the NRC Enforcement Policy (NCV 50-316-02-03-09(DRP)). The licensee entered this violation into its corrective action program as CR 02047050. This URI is closed.

.8 (Closed) URI 50-316-00-19-02; 50-316-00-19-02: "Potentially Non-Conservative Engineered Ventilation TS 3.7.6.1." During a review of an operability determination for the component cooling pump ventilation fans documented in CR 00-6947, the inspectors noted an inconsistency between the Auxiliary Building ventilation calculation assumptions and TS 3.7.6.1, "ESF [Engineered Safety Features] Ventilation System,"

operability requirements. Specifically, the Auxiliary Building ventilation calculation of record, MD-12-HV-002-N, credited airflow from the ESF ventilation unit in the non-accident unit during a design basis accident. Because TS 3.7.6.1 was applicable only in Modes 1 through 4, TS 3.7.6.1 was non-conservative relative to the lowest ESF ventilation functional capability assumed in MD-12-HV-002-N with one unit in Mode 5 (Cold Shutdown) or Mode 6 (Refueling). On August 12, 2000, the licensee initiated CR 00-11265 to investigate this issue and determine the lowest functional capability required from the ESF ventilation system to mitigate a design basis event.

The licensee included resolution of this issue within the scope of the revised Auxiliary Building ventilation system calculation, TH-01-05, which was completed on January 18, 2002. The licensee concluded that, although several ECCS pump room temperatures were increased if the ESF ventilation in the non-accident unit was removed from service in accordance with TS 3.7.6.1, the mitigating equipment remained operable. The inspectors reviewed the results of this calculation and the resolution of CR 00-11265 and CR 00-6947 and determined that the licensees evaluation and conclusions were reasonable. Consequently, the inspectors concluded that the licensee has developed an adequate basis to justify the lowest functional capability of the ESF ventilation system as currently defined in TS 3.7.6.1. Although the licensee had been unable to adequately justify the lowest ESF ventilation system functional capability as defined in TS 3.7.6.1 prior to the issuance of TH-01-05, this issue is considered to be of minor safety

significance and is not subject to formal enforcement action in accordance with Section IV of the NRCs Enforcement Policy. This URI is closed.

4OA5 Other

.1 Institute of Nuclear Power Operations (INPO) Mid-Cycle Report The inspectors reviewed the INPO Mid-Cycle Report for the D. C. Cook Plant conducted in April 2002. During this review, the inspectors did not identify any safety significant issues.

.2 Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles (Temporary Instruction 2515/145)

a. Inspection Scope The inspector performed a review of the licensee's activities in response to NRC Bulletin 2001-01, "Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles," to verify compliance with applicable regulatory requirements. In accordance with the guidance of NRC Bulletin 2001-01, D. C. Cook Unit 1 was characterized as belonging to the sub-population of plants (Bin 4) that were considered to have a low susceptibility to primary water stress corrosion cracking (PWSCC).

Although the anticipated low likelihood of PWSCC degradation at the Bin 4 facilities indicates that enhanced examination beyond the present requirements is not currently necessary, the licensee responded to NRC Bulletin 2001-01 by performing a remote visual examination of the reactor vessel head and a qualified volumetric (ultrasonic and eddy current) examination of the 79 vessel head penetrations and head vent. Full volumetric coverage was achieved on 77 vessel head penetrations. Liquid penetrant examination was performed on penetrations 70 and 73 J-welds due to the inability to perform 100 percent volumetric coverage of these welds.

The inspector interviewed inspection personnel, reviewed procedures and inspection reports, including photographic documentation, to assess the licensee's efforts in conducting an "effective" visual and volumetric examination of the reactor vessel head.

The inspector reviewed the qualifications and certification of personnel performing the volumetric examinations to ensure that they were in accordance with approved procedures and techniques (ultrasonic and eddy current) demonstrated for the NRC at the Electric Power Research Institute (EPRI). The inspector reviewed the inspection procedures, equipment certifications, and personnel certifications.

Evaluation of Visual Head Inspection Requirements 1. Were the licensees examinations performed by qualified and knowledgeable personnel?

The inspector determined that the examinations were performed by individuals certified as Level II and Level III in the VT-2 Method. The specific guidelines described in the EPRI, "Visual Examination for Leakage of PWR [Pressurized Water Reactor] Reactor Head Penetrations," were also used for the inspections.

2. Were the licensees examinations performed in accordance with approved and adequate procedures?

The inspector verified that the examinations were conducted in accordance with an approved plant procedure, "Reactor Vessel Head Penetration Remote Visual Inspections for Cook Unit 1", MRS-SSP-1319, and the guidelines established in EPRI Document 1006296, "Visual Examination for Leakage of PWR Reactor Head Penetrations." The inspector determined that the procedure and supplemental guidance was appropriate for the examinations.

3. Were the licensees examinations adequately able to identify, disposition, and resolve deficiencies?

The inspector determined through a review of post-examination records, discussions with the personnel that conducted the examinations, and a review of the procedure, that the examinations were sufficient to identify any deficiencies. The licensees examinations identified two deficiencies that were documented in CR 021360423 and CR 02135066. The inspector assessed the licensees efforts to disposition and resolve the deficiencies.

4. Were the licensees examinations capable of identifying the primary stress corrosion cracking phenomenon described in the Bulletin?

The inspector determined through interviews with inspection personnel, and reviews of procedures and inspection reports, including photographic documentation of the examinations, that the licensees efforts were capable of identifying the phenomenon described in the Bulletin. The inspector determined that the inspection personnel had 360 degree access to all 80 vessel head penetrations, with no obstructions or interferences.

5. What was the condition of the reactor vessel head (debris, insulation, dirt, boron from other sources, physical layout, viewing obstructions)?

The vessel head had block contoured vessel head insulation, consisting of mirror panels fabricated of 3-inch thick Type 304 stainless steel insulation. The inspector determined that the licensee had complete viewable coverage. The inspector also determined through discussions with the inspection personnel and review of the inspection photographs that the as-found pressure vessel head condition showed evidence of boric acid residues from known canopy seal and thermocouple column conoseal leakage.

Foreign material (CR 02135066) in the form of 2 screws, 1 bolt, several pieces of wire, dust/dirt, paint chips and metal filings were found during the video inspection. These items were removed by vacuuming and cleaning of the reactor vessel head.

6. Could small boron deposits, as described in the bulletin, be identified and characterized?

The inspector verified, through interviews with inspection personnel and review of the photographic record of the examination, that small boron deposits, as described in the Bulletin, could be identified; given the accessibility of the pressure vessel head

penetrations. However, no evidence of boric acid deposits characteristic of active leakage were found during the inspection.

7. What materiel deficiencies (associated with the concerns identified in the bulletin) were identified that required repair?

Through a review of the examination records, the inspector determined the inspection personnel did not identify any materiel deficiencies. No wastage or corrosion was noted other than very minor inactive surface rusting.

8. What, if any, significant items that could impede effective examinations and/or ALARA issues were encountered?

The inspector verified that there were no impediments to the examinations. Collective radiation doses received as a part of the examinations were 3.958 rem.

b. Findings No findings of significance were identified.

4OA6 Meetings

.1 Interim Exits The results of the Public Radiation Safety - Radwaste Processing and Transportation Inspection were presented to Mr. J. Pollock and other members of licensee management at the conclusion of the inspection on April 12, 2002. The licensee acknowledged the findings presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified. The inspector subsequently discussed changes to the original characterization of the findings by telephone with Mr. J. Long on April 17, 2002.

The results of the Safeguards Access Authorization Program/Access Control Inspection were presented to Mr. J. McMahon and other members of the licensee management at the conclusion of the inspection on April 26, 2002. The licensee acknowledged the findings presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

The results of the Unit 1 Biennial Inservice Inspection and TI-145 Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles (NRC Bulletin 2001-01)

Inspection were presented to Mr. J. Pollock and other members of licensee management at the conclusion of the inspection on May 23, 2002. The licensee acknowledged the findings presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

The results of the Occupational Radiation Safety - Access Controls for Radiologically Significant Areas and ALARA Planning/Controls Inspection were presented to Mr. C.

Bakken and other members of licensee management at the conclusion of the inspection on May 24, 2002. The licensee acknowledged the findings presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified. The inspector subsequently discussed changes to the original characterization of the findings by telephone with Mr. D. Noble on June 6, 2002.

.2 Resident Inspectors Exit The inspectors presented the inspection results to Mr. J. Pollock and other members of licensee management at the conclusion of the inspection on July 9, 2002. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. Proprietary information was examined during this inspection but is not specifically discussed in this report.

.3 Annual Assessment Meeting On April 12, 2002, the NRC presented the results of its annual assessment of D. C.

Cook Plants performance to Mr. and other members of licensee management during a public meeting held at the Hampton Inn in Stevensville, Michigan.

The results of the annual assessment were previously documented in a letter to the licensee dated March 4, 2002. The slides presented by the NRC are available in ADAMS (accession number ML021120165).

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 VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a Non-Cited Violations (NCVs).

If the licensee contests these NCVs, the licensee should provide a response within 30 days of the date of this inspection report, with the basis for the denial, to the U.S. Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region III; Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the D. C. Cook facility.

NCV Tracking Number Requirement Licensee Failed to Meet NCV 50-315/316-02-03-10 Technical Specification 6.12 requires that high radiation areas accessible to personnel with radiation levels greater than 1000 mrem/hour be provided with locked doors to prevent unauthorized entry and be conspicuously posted.

Doors shall remain locked except during periods of access by personnel under an approved RWP.

Contrary to the above, for an approximate 20 hour2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months period beginning the afternoon of April 10, 2002, the licensee failed to maintain the door leading into the 587 foot elevation radioactive waste drumming room in the Auxiliary Building (an area that had radiation levels up to 2500 mrem/hour) locked or under direct surveillance to prevent unauthorized entry. This is a violation of TS 6.12. During the 20 hour2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months period, one unauthorized entry into the drumming room occurred but without dose consequence.

The problem was identified during a routine RP surveillance. The licensee entered this violation into its corrective action program as CR 02101048.

NCV 50-315/316-02-03-11 Technical Specification 6.12 requires that high radiation areas accessible to personnel with radiation levels greater than 1000 mrem/hour be provided with locked doors to prevent unauthorized entry and be conspicuously posted.

Doors shall remain locked except during periods of access by personnel under an approved RWP.

Contrary to the above, for an approximate 6-8 hour period beginning the evening of May 5, 2002, during the Unit 1 CRUD burst cleanup of the RCS, the licensee failed to properly post and maintain the door leading into the 617 foot elevation demineralizer valve gallery in the Auxiliary Building (an area that had radiation levels up to 3000 mrem/hour) locked or under direct surveillance to prevent unauthorized entry. This is a violation of TS 6.12. No unauthorized entry was made into the area while it was not properly posted or controlled. The problem was identified during follow-up CRUD burst surveys by the RP staff. The licensee entered this violation into its corrective action program as CR 02126020.

The inspector concluded that the maximum radiation levels in both the drumming room and valve gallery coupled with the limited accessibility of the high radiation area in the drumming room precluded a substantial potential for an overexposure. Both incidents were therefore determined to be of very low safety significance. The licensee correctly concluded that the events described in NCV 50-315/316-02-03-10 and NCV 50-315/316-02-03-11 each represented a high radiation area occurrence under the Occupational Exposure Control Effectiveness performance indicator, both of which the licensee planned to report in its second quarter 2002 performance indicator submittal to the NRC.

KEY POINTS OF CONTACT Licensee M. Allen, Assistant Maintenance Director G. Arent, Regulatory Affairs Manger C. Bakken, Senior Vice President, Nuclear Generation G. Borlodan, Plant Programs Manager J. Bradshaw, Security/Support Services Performance Supervisor K. Burkett, Security/Support Services Access Control Supervisor P. Cowan, Regulatory Affairs Licensing Supervisor R. Gaston, Regulatory Affairs Compliance Supervisor J. Gebbie, System Engineering Manager G. Gibson, Site Protective Services Manager S. Greenlee, Nuclear Technical Services Director R. Hall, Inservice Inspection Program Specialist G. Harland, Work Control/Maintenance Director N. Jackiw, Regulatory Affairs Specialist E. Lamoureut, Westinghouse Project Manager C. Lane, Inservice Inspection Supervisor E. Larson, Operations Director J. Long, Environmental Compliance General Supervisor R. Meister, Regulatory Affairs Specialist D. Moul, Operations Shift Technical Advisor Supervisor D. Noble, Radiation Protection Technical Support T. Noonan, Performance Assurance Director J. Pollock, Site Vice President A. Rodriguez, Security/Support Services Manager M. Schaefer, Nuclear Specialist L. Smead, Security Operations Analyst R. Smith, Plant Engineering Assistant Director C. Vanderniet, Project Manager L. Weber, Performance Oversite Manager D. Wood, RadChem Environmental Manager T. Woods, Regulatory Affairs Specialist NRC D. Passehl, Acting Chief, Reactor Projects Branch 6 S. Burgess, Senior Reactor Analyst, Division of Reactor Safety M. Parker, Senior Reactor Analyst, Division of Reactor Safety

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-315-02-03-01 NCV Failure to implement adequate foreign material exclusion controls resulted in degradation of Unit 1 West ESW pump 50-316-02-03-02 NCV Containment isolation valve alignment error during local leak rate testing resulted in inoperable containment penetration during refueling and violation of TS 3.9.4.c 50-315-02-03-03 NCV Pressurizer power operated relief valves inoperable due to mis-positioned control switches 50-316-02-03-04 NCV Failure of lower containment airlock door interlock and failure to follow instructions resulted in inadvertent opening of both airlock doors 50-315-02-03-05 NCV Failure to implement all intended radiological engineering controls during steam generator eddy current testing, as required by 10 CFR 20.1701 50-316-02-03-06 NCV TS 3.9.4.c was violated during core alterations when containment isolation valve (2-XCR-101) was stroked open for testing 50-315-02-03-07 NCV Failure to measure Unit 1 lower ice condenser inlet door opening torque and closing torque in accordance TS requirements 50-316-02-03-08 URI Review of NOED-02-3-01 regarding D.C. Cook, Unit 2, compliance with TS 3.8.2.3 50-316-02-03-09 NCV Failure to provide work instructions appropriate to the circumstances for adjustment of stem lock nut on 2-CS-369 50-315/316-02-03-10 NCV Failure to adequately control access to a locked high radiation area for the radioactive waste drumming room 50-315/316-02-03-11 NCV Failure to adequately control access to a locked high radiation area for the demineralizer valve gallery

Closed 50-315-02-03-01 NCV Failure to implement adequate foreign material exclusion controls resulted in degradation of Unit 1 West ESW pump 50-316-02-03-02 NCV Containment isolation valve alignment error during local leak rate testing resulted in inoperable containment penetration during refueling and violation of TS 3.9.4.c 50-315-02-03-03 NCV Pressurizer power operated relief valves inoperable due to mis-positioned control switches 50-316-02-03-04 NCV Failure of lower containment airlock door interlock and failure to follow instructions resulted in inadvertent opening of both airlock doors 50-315-02-03-05 NCV Failure to implement all intended radiological engineering controls during steam generator eddy current testing, as required by 10 CFR 20.1701 50-316-2002-001-00 LER Containment Isolation valve alignment error during local leak rate testing 50-315-2002-002-00 LER Pressurizer power operated relief valves inoperable due to control switch position 50-316-2002-002-00 LER TS 3.9.4.c was violated during core alterations 50-316-02-03-06 NCV TS 3.9.4.c was violated during core alterations when containment isolation valve (2-XCR-101) was stroked open for testing 50-316-2001-002-00 LER Failure of lower containment airlock door interlock results in inadvertent opening of both doors 50-316-2001-002-01 LER Failure of lower containment airlock door interlock results in inadvertent opening of both doors 50-315-01-20-08-00 URI Failure to adequately measure the ice condenser lower inlet door opening torque and closing torque in accordance with TS requirements 50-315-02-03-07 NCV Failure to measure Unit 1 lower ice condenser inlet door opening torque and closing torque in accordance TS requirements 50-315-2002-004-00 LER Unit 1 ice condenser lower inlet door test failure 50-315-2002-001-00 LER Failure to perform ice condenser door testing in accordance with TS

Closed 50-316-2002-003-00 LER 2AB 250 volt D.C. battery inoperable for longer than allowed by plants TS 50-316-02-03-08 URI Review of NOED-02-3-01 regarding D.C. Cook, Unit 2, compliance with TS 3.8.2.3 50-316-02-02-01 URI Failure to perform adequate maintenance and testing on valve 2-CS-369 resulted in gas binding the Unit 2 West centrifugal charging pump 50-316-02-03-09 NCV Failure to provide work instructions appropriate to the circumstances for adjustment of stem lock nut on 2-CS-369 50-315/316-00-19-02 URI Potentially non-conservative engineered ventilation TS 3.7.6.1 50-315/316-02-03-10 NCV Failure to adequately control access to a locked high radiation area for the radioactive waste drumming room 50-315/316-02-03-11 NCV Failure to adequately control access to a locked high radiation area for the demineralizer valve gallery Discussed 50-316-01-20-07 NCV Failure to adequately measure the ice condenser lower inlet door opening torque and closing torque in accordance with TS requirements

LIST OF ACRONYMS USED ADAMS Agency-wide Documents and Management System AEP American Electric Power AFW Auxiliary Feedwater ALARA As Low As Is Reasonably Achievable ANSI American National Standards Institute ATR Administrative Technical Requirement ATWS Anticipated Transients Without Scram ASME American Society of Mechanical Engineers CCP Centrifugal Charging Pump CDF Core Damage Frequency CEDE Committed Effective Dose Equivalent CFR Code of Federal Regulations CR Condition Report DAC Derived Air Concentration DAW Dry Active Waste D. C. Direct Current DCP Design Change Procedure DG Diesel Generator DIT Design Information Transmittal DOT Department of Transportation DRP Division of Reactor Projects DRS Division of Reactor Safety ECCS Emergency Core Cooling System EHP Electrical Maintenance Head Procedure EPRI Electric Power Research Institute ESF Engineered Safety Feature ESW Essential Service Water FFD Fitness-for-Duty FME Foreign Material Exclusion gpm gallons-per-minute IEEE Institute of Electrical and Electronics Engineers IHP Instrument Maintenance Head Procedure IMC Inspection Manual Chapter INPO Institute of Nuclear Power Operations ISI Inservice Inspection LER Licensee Event Report LERF Large Early Release Frequency LOCA Loss-of-Coolant Accident LOP Loss-of-Off-site Power MHP Maintenance Head Procedure MT Magnetic Particle Examination MVAR Megavolt-Amperes Reactive NCV Non-Cited Violation NI Nuclear Instrument NOED Notice of Enforcement Discretion NRC Nuclear Regulatory Commission OA Other Activities

OHP Operations Head Procedure PADS Personnel Access Data System PARS Publically Available Records PCP Process Control Program PI Performance Indicator psid pounds-per-square-inch differential psig pounds-per-square-inch gauge PMI Plant Managers Instruction PMP Plant Managers Procedure PORV Power Operated Relief Valve PPC Plant Process Computer PT Die Penetrant Examination PWR Pressurized Water Reactor PWSCC Primary Water Stress Corrosion Cracking Radwaste Radioactive Waste RCA Radiologically Controlled Area RCS Reactor Coolant System RP Radiation Protection RWP Radiation Work Permit SDP Significance Determination Process SI Safety Injection SPP Special Plant Procedure SRA Senior Reactor Analyst SSC Structures, Systems, and Components STP Surveillance Test Procedure TEDE Total Effective Dose Equivalent TS Technical Specification U1C18 D. C. Cook Unit 1, 18th Refueling Outage U2C13 D. C. Cook Unit 2, 13th Refueling Outage UFSAR Updated Final Safety Analysis Report URI Unresolved Item UT Ultrasonic Examination

LIST OF DOCUMENTS REVIEWED The following is a list of licensee documents reviewed during the inspection, including documents prepared by others for the licensee. Inclusion on this list does not imply the NRC inspectors reviewed the documents in their entirety, but rather, that selected sections or portions of the documents were evaluated as part of the overall inspection effort. Inclusion of a document in this list does not imply NRC acceptance of the document, unless specifically stated in the inspection report.

1R01 Adverse Weather Plant Managers Severe Weather Guidelines Revision 0 Procedure (PMP)

2080 SWM.001 12-OHP 4022.001.010 Severe Weather Revision 0 12-OHP 4022.001.009 Seiche Revision 0 Calculation Screen House Internal Flood Levels Revision 0 MD-12-SCRN-001-N Condition Report NRC Identified That Entry Conditions for August 9, 2001 (CR) 00-11073 Severe Weather Procedure Could Be Overly Restrictive CR 01194005 1-HV-CIR-3 Is Not Maintaining July 13, 2001 Instrument Room Temperature CR 01213055 East ESW [Essential Service Water] August 1, 2001 Pump Room Temperature Alarm Is Standing on a Normal Summer Day CR 01297117 Control Rooms Were Not Notified That a October 24, 2001 Tornado Watch and Warning Had Been Issued CR 02152042 Evaluate West ESW Pump Room June 1, 2002 Ventilation and High Temperature Alarm CR 02174006 NRC Identified That Unit 1 Switchgear June 21, 2002 Drain Cover Is Broken CR 02174008 NRC Identified Fouling of Unit 2 June 21, 2002 Switchgear Ventilation Inlet Screens and Questioned Timeliness of Installation of Switchgear Vent Hood Proposed Modification

1R04 Equipment Alignment Unit 2 Turbine Driven and East Motor Driven Auxiliary Feedwater (AFW) Pumps D. C. Cook Nuclear Plant Updated Final Safety Analysis Report (UFSAR)

PMP 5020.RTM.001 Restraint of Transient Material Revision 1 12-MHP-5021.SCF.001 Scaffolding Guidelines Revision 0b 01-OHP-5030.001.001 Operations Plant Tours Revision 19b 02-OHP-4030.STP.017E East Motor Driven Auxiliary Feedwater Revision 10 System Test 02-OHP-5030-001-001 Operations Plant Tours Revision 19a DB-12-AFWS Auxiliary Feedwater System Design Basis Revision 0 Document Flow Diagram Auxiliary Feedwater Revision 45 OP-2-5106-45 Unit 2 Train AB and CD Station Batteries Technical Specification D.C. Distribution - Operating Amendment 249 (TS) 3.8.2.3 UFSAR Section 8.0 Electrical Systems Revision 17.2 CR 02116008 NRC Identified Minor Discrepancies in April 25, 2002 the Unit 2 Station Battery Rooms CR 02116010 NRC Identified That the Gaitronics April 25, 2002 Speaker in the Unit 2 CD Battery Room Is Not Functioning Properly Unit 2 Circulating Water System Flow Diagram Circulating Water, Priming System and Revision 51 02-12-5119-51 Screenwash Units 1 and 2 02-OHP-4021-057-001 Circulating Water System Operation Revision 20 02-OHP-4021-057-002 Placing In/Removing from Service the Revision 8a Circulating Water Deice System 02-OHP-4024-223 Annunciator 223 Response: Circulating Revision 7 Water

CR 01271065 Circulating Water Pump PP-21 Discharge September 28, 2001 Shutoff Valve 2-WMO-21 Is Not Consistently Staying in Manual Operation CR 02113041 Unit 2 Operations Does Not Appear to April 23, 2002 Have the Seal Injection Filters Valved in Correctly CR 02114035 Configuration Control Issue Related to April 24, 2002 Misalignment of Unit 2 Seal Water Injection Filters Following Unit 2 Refueling CR 02120087 The Incorrect Main Condenser Waterbox April 29, 2001 Was Removed for Service Due to Improper Sample Collection 1R05 Fire Protection 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 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 Plant Managers Fire Protection Revision 26 Instruction (PMI) 2270 Fire Training Exercise 21 Radiological Control Area [RCA] Access April 10, 2002 609 Foot Elevation Auxiliary Entry/Exit Area CR 02131015 During Troubleshooting of ERS-2300, May 11, 2002 VRA-2310 Was Rendered Inoperable Without the Control Rooms Knowledge and Without Entering the Appropriate TS 1R06 Flood Protection D. C. Cook Nuclear Plant UFSAR

Calculation Screen House Internal Flood Levels Revision 0 MD-12-SCRN-001-N April 30, 2000 12-OHP 4022.001.009 Seiche Revision 0 NRC Information Notice Submerged Safety-related Electrical March 21, 2002 2002-12 Cables CR P-99-07656 ESW Strainer Backwash Outlet Shutoff April 6, 1999 Valves Are Below the Flood Protected Level of 595 Feet CR 01323022 Program Controls for Protection Against November 19, 2001 Plant Flooding Need to Be Reviewed for Adequacy and Understanding by Plant Personnel CR 02088011 Tracking CR for Development of a March 29, 2002 Design Basis Document for Flood Protection 1R07 Heat Sink Performance 12-MHP-5021-005-009 Heat Exchanger Tube Plugging Revision 2 12-MHP-5030-016-001 Component Cooling Water Heat Revision 4 Exchanger Inspection, Cleaning and Tube Plugging AEP-BOP-208-ET D. C. Cook Component Cooling Water Revision 0 Heat Exchanger Eddy Current Testing Generic Letter 89-13 Service Water System Problems July 18, 1989 Affecting Safety-Related Equipment Job Order R0221325 1-HE-15E, Inspect and Clean Heat May 26, 2002 Exchanger as Required Job Order C0178129 Perform Eddy Current Testing for May 23, 2002 Component Cooling Water Heat Exchanger 1-HE-15E CR 02126069 ESW Lines to 1-HV-AFP-T1AC May 6, 2002 CR 02138028 Found the Divider Plate in 1-HE-15E May 18, 2002 Bowed Approximately 1/2 Inch From Inlet to Outlet and 3/8 Inch When Measured From Tubesheet to Cover Plate

CR 02138031 While Performing a Generic Letter 89-13 May 18, 2002 Inspection, Found Sea Grass and Sand Fouling the Return End of the 1-HE-15E Tubesheet CR 02143053 Two Additional Tubes Require Plugging May 23, 2002 in the East Component Cooling Water Heat Exchanger CR 02143088 Eddy Current Testing Was Performed on May 23, 2002 100 Percent of the Tubes in 1-HE-15E.

As a Result of this Testing, 27 Tubes Were Plugged 1R08 Inservice Inspection 1278909A BWI Replacement Steam Generator January 28, 2002 Secondary Side Inspection Procedure 51-5004764-03 D. C. Cook Units 1 and 2 Appendix H April 17, 2002 Review MDS-609 Steam Generator Tube Plugging May 16, 2002 01-EHP-5037-SGP-003 Steam Generator Primary Side May 1, 2002 Inspections Site Specific Eddy Current Data Analysis May 13, 2002 Guidelines D. C. Cook Nuclear Plant Unit 1 SGP-DA-U1-C18 Steam Generator Degradation May 10, 2002 Assessment - Unit 1 Cycle 18 83A6218 Ultrasonic Examination Procedure for August 30, 2001 Ferritic Piping Welds and Vessels (Less Than or Equal) 2 Inches Thickness for Cook Nuclear Plant 83A6118 Magnetic Particle Examination for D. C. March 18, 2002 Cook Nuclear Plant 83A6228 Ultrasonic Examination Procedure for March 18, 2002 Austenitic Piping and Vessels (Less than or Equal) 2 Inches Thickness 83A6108 Liquid Penetrant Examination for D. C. August 30, 2001 Cook Nuclear Plant 80A9055 Thermometer Check Record April 18, 2002

AR 02115006 Identified Discrepant Conditions During April 25, 2002 ISI [Inservice Inspection] Examinations on 1-GRH-V-14 AR 02115008 Identified Discrepant Conditions During April 25, 2002 ISI Examinations on 1-GSI-R-50 AR 02115016 Identified Discrepant Conditions During April 25, 2002 ISI Examinations on 2-GCCW-S-843 1R12 Maintenance Rule Implementation PMP 4030-001-001 Impact of Safety Related Ventilation on Revision 4 the Operability of Technical Specification Equipment Maintenance Rule (a)(1) Action Plan Revision 1 Diesel Generator Ventilation System January 24, 2002 Maintenance Rule Scoping Document Revision 2 Diesel Generator Room Ventilation February 28, 2002 System (VDG)

CR 01152061 Apparent Failure of 2-HV-SGR-MD-2 June 1, 2001 Damper to Open Created a High Temperature Condition in the CRID and Control Rod Drive Equipment Rooms CR 01191011 Diesel Generator Tempering Damper July 10, 2001 1-HV-DDP-CD-1 Does Not Function Properly CR 01194022 Maintenance Rule Review for Diesel July 13, 2001 Generator Ventilation System Was Not Adequate CR 01194029 Maintenance Rule Review for Diesel July 13, 2001 Generator Ventilation System Was Not Adequate CR 01199073 Unit 1 CD Diesel Generator Supply Fan July 18, 2001 Tempering Damper 30 Percent Open with Outside Air Temperature Approximately 90 Degrees CR 01207001 2-HV-SGRS-9 Smells Hot/no Air Flow July 26, 2001 Due to Damper Not Opening CR 01289032 Diesel Generator Tempering Dampers October 16, 2001 Have No Preventative Maintenance

CR 01329018 2AB Diesel Generator Exhaust November 25, 2001 Tampering Damper, 2-HV-DDP-AB1, Was Discovered with One Louver Detached CR 01331035 Diesel Generator Ventilation System November 27, 2001 Unavailability Exceeds Maintenance Rule Performance Criteria CR 01341132 Inlet Damper to Unit 2 CRID Fans December 7, 2001 2-HV-SGRS-1A and 2-HV-SGRS-4A Appears to Have Failed CR 99-12474 Lack of Preventative Maintenance May 19, 1999 Program for the Diesel Generator Ventilation Motor Operated Dampers 1R13 Maintenance and Emergent Work Control PMP-2291-OLR-001 On-Line Risk Management Revision 2 NUMARC 93-01 Industry Guideline for Monitoring the Revision 2 Effectiveness of Maintenance at Nuclear Power Plants, Section 11, "Assessment of Risk Resulting From Performance of Maintenance Activities" Unit 1 Main Generator Output Breaker 1-52-K1 Replacement PMI-4090 Criteria for Conducting Infrequently April 5, 2002 Performed Tests or Evolutions, Attachment 1, "Briefing Guide for Removal of Unit 1 345 Kilovolt Output Breaker K1 from Service for Replacement with the Unit On Line" CR 02120049 Unit 1 in an Orange Risk Status on Large April 30, 2002 Early Release Frequency, With Unit 2 in a Very High Yellow Status Due to Predicted Severe Weather Expected in the Area Unit 2 West Motor Driven AFW Pump CR 020134025 Failed to Have Quality Control Verify May 14, 2002 Freedom of Movement of Check Valve

PMP-2291-OLR-001 On-Line Risk Management Work May 12-18, 2002 Data Sheet 1 Schedule Review and Approval Form Cycle 41, Week 6 Unit 2 Control Room Logs May 15-17, 2002 Unit 2 Supervisors Turnover Logs May 15-17, 2002 Unit 2 Abnormal Position Log May 15-17, 2002 Unit 1 Turbine Driven AFW Pump PMP-2291-OLR-001 On-Line Risk Management Work April 7-13, 2002 Data Sheet 1 Schedule Review and Approval Form Cycle 41, Week 1 Replacement of the Unit 2 East and Unit 1 West Essential Service Water Pumps PMI-2220 Foreign Material Exclusion Revision 11 PMP 2220-001-001 Foreign Material Exclusion (FME) Revision 2a PMP 2291-OLR.001 Work Schedule Review and Approval Data Sheet 1 Form Cycle 41, Week 10 and Cycle 41, Week 11 12 MHP 5021.DIV.002 Divers Safety Net Installation and Revision 2 Restoration CR 01048011 An 8 Foot Piece of Herculite Was February 16, 2001 Dropped in the Unit 1 Forebay While Work Was Being Performed in the 1-WMO-13 Pit.

CR 01093002 Herculite Found Between the Inlet and April 3, 2001 Grating Inside the Unit 2 East Main Feed Pump Condenser Water Box CR 02175037 Step Change in Unit 1 West ESW Pump June 24, 2002 Performance with No Associated Flow Change CR 02176058 FME - Red Danger Barrier Tape Was June 25, 2002 Found in the Suction Bell of the Unit 1 West ESW Pump

1R14 Personnel Performance During Nonroutine Evolutions 1R14.1 Containment Isolation Valve Alignment Error During Local Leak Rate Testing Licensee Event Report Containment Isolation Valve Alignment March 28, 2002 (LER) Error During Local Leak Rate Testing 50-316-2002-001-00 CR 02027006 Valve 2-GPX-301-V1 Was Misaligned January 27, 2001 During the Performance of Step 53 of 02-EHP-4030-234-203, Unit 2 B&C Leak Rate Testing that Violated Containment and Refueling Integrity While Fuel Movement Was in Progress 1R14.2 Pressurizer Power Operated Relief Valves (PORVs) Inoperable Due to Mis-Positioned Control Switches LER 50-315-2002-002-00 Pressurizer Power Operated Relief April 19, 2002 Valves Inoperable Due to Control Switch Position 01-OHP-4023.FR-S.1 Response to Nuclear Power Generation Revision 7 ATWS [Anticipated Transient Without Scram]

CR 02050022 The Automatic Function of All Three February 19, 2002 Unit 1 PORVs Was Defeated 1R14.3 Failure of Lower Containment Airlock Door Interlock and Failure to Follow Instructions Resulted in Inadvertent Opening of Both Airlock Doors LER 50-316-2001-002-00 Failure of Lower Containment Airlock March 16, 2001 Door Interlock Results in Inadvertent Opening of Both Doors LER 50-316-2001-002-01 Failure of Lower Containment Airlock October 26, 2001 Door Interlock Results in Inadvertent Opening of Both Doors PMP 4010.CAC.001 Containment Access and Cleanliness Revision 0 Job Order R0202758 Perform Preventive Maintenance Task October 31, 2000 24, Steps 1.0 thru 1.11.8 Job Order R0210015 Perform 6-Month Airlock Preventive April 17, 2001 Maintenance Task

CR 01023054 While Leaving Unit 2 Lower Containment January 23, 2001 Through the Lower Containment Airlock, the Inner Airlock Door Was Able to Be Opened While the Outer Airlock Door Was Also Opened CR 01023055 Lower Containment Airlock Interlock Did January 23, 2001 Not Prevent Opening the Inner Door While the Outer Door Was Open 1R14.4 Unit 1 Power Reduction to Support Repairs to Unit 1 Main Generator Breaker K1 Disconnect CR 02115039 Insulator for Disconnect for K1 Breaker April 25, 2002 Damaged During Maintenance CR 02115030 Rod Control Non-urgent Failure Alarm April 25, 2002 Received in Unit 1 During Down Power Operation 1R14.5 Unit 1 Reactor Trip and Restart Following Loss of Main Feed Pump Vacuum NRC Event Notification Manual Reactor Trip from 88 Percent June 14, 2002 38993 Power PMP 4010.TRP.001 Unit One Reactor Trip Review Report June 15, 2002 Data Sheet 1 (June 14, 2002)

CR 02165064 Manual Reactor Trip Due to Loss of East June 14, 2002 Main Feedwater Pump CR 02166009 Unit 1 Reactor Trip Resulted in Excessive June 14, 2002 Cooldown CR 02166016 Thermal Overload Tripped on 1-MRV-230 June 15, 2002 Hydraulic Actuator CR 02165063 Turbine Driven AFW Pump Speed June 14, 2002 Oscillates Approximately 200 Revolutions-per-Minute While Running 1R14.6 Unit 2 Station Battery 2AB Cell Cracking Operator Response Unit 2 Control Room Logs April 23, 2002 CR 02113067 Crack Found on Unit 2 AB Battery Cell 31 April 23, 2002

1R14.7 Unit 2 Reactor Trip, May 13, 2002 CR 02133031 2-RU-27 Failed Low After Unit 2 Reactor May 13, 2002 Trip CR 02133034 2-MRV-240 Started to Drift Closed After May 13, 2002 Reactor Trip CR 02133048 2-DRV-250 the Bleed Steam Drain Valve May 13, 2002 for the 5A Heater Failed to Open Automatically During a Turbine Trip 1R15 Operability Evaluations Unit 1 Ice Basket 24-1-7 As-Found Weight Below TS Requirements 12-EHP-4030-010-262 Ice Condenser Surveillance and May 14, 2002 Data Sheet 6 Operability Evaluation - Expanded Ice Weighing Results for Basket 24-1-7 CR 02134066 As-found Ice Basket Weighing May 14, 2002 Surveillance - the As-found Weighing Results for Ice Basket 24-1-7 Is below the TS Minimum Required Amount CR 02115002 Unit 1 Ice Basket 24-1-7 As-found April 25, 2002 Weight Was below the TS Limit and Structural Analysis Limit Calculation Ice Condenser Ice Basket Design Revision 0 SD-990826-003 2-FW-160, West Motor Driven AFW Pump Emergency Leakoff Check Valve Leaked by During the Performance of Test 02-OHP-4030.STP.017E CR 02136014 2-FW-160, West Motor Driven AFW Pump Emergency Leakoff Check Valve Leaked by During the Performance of Test 02-OHP-4030.STP.017E 02-OHP-4030.STP.017E East Motor Driven Auxiliary Feedwater Revision 10 System Test Non-Seismic Scaffolding Built in the Vicinity of 2AB DG [Diesel Generator] and 2CD DG Components CR 02109003 Non-Seismic Scaffolding Built in the April 19, 2002 Vicinity of 2AB DG and 2CD DG Components

Check Valves 1-CS-328-L1, 1-CS-328-L4, 1-CS-329-L1, and 1-CS-329-L4 Were Found Open During Radiographic Nonintrusive Testing Velan Valve Corporation 10 CFR Part 21 Notification for Potential January 18, 1991 Letter to the NRC Safety Related Problem With 21/2-Inch, 3-Inch, and 4-Inch Forged Swing Check Valves CR 96-0094 Assess the Applicability, Significance, January 24, 1996 and Probability for an Event Similar to Operating Experience 7640 Occurring at Cook Nuclear Plant CR 02132050 Disc on Valve 1-CS-329-L1 Was Found May 12, 2002 in the Open Position CR 02134021 Check Valves 1-CS-328-L1, 1-CS-328- May 14, 2002 L4, 1-CS-329-L1, and 1-CS-329-L4 Were Found Open During Radiographic Nonintrusive Testing CR 02138029 The Extent of Condition Which Was May 18, 2002 Originally Identified Under CR 02134021 Against Four Unit 2 Charging Line Check Valve Failures Is Considered to Extend to All 3-Inch Velan Valves of Model B10-3114B-13M Unit 2 Steam Stop Valve 2-MRV-220 Detent Bar/guide Rod Bushing Has Fallen Out CR 02137063 Steam Stop Valve 2-MRV-220 Detent Bar May 17, 2002 Guide Has Fallen out CR 02172042 NRC Identified That a Work Request Is June 21, 2002 Needed to Replace 2-MRV-220 Bushing During the Next Refueling Outage Degraded and Nonconforming Conditions Remaining After Refueling Outage U1C18 D. C. Cook Nuclear Plant Unit 2 Technical Specifications D. C. Cook Nuclear Plant Updated Final Safety Analysis Report Generic Letter 91-18 Information to Licensees Regarding NRC Revision 1 Inspection Manual Section on Resolution of Degraded and Nonconforming Conditions

PMP-7030-ORP-001 Operability Determinations Revision 9 Calculation Residual Heat Removal Shutdown Revision 0 EVAL-MD-12-RHR-905-N Cooling Line Vibration Fatigue Evaluation Safety Evaluation Unit 1 Residual Heat Removal System August 23, 2000 2000-1534-00 Restart Assessment CR P-99-02455 Residual Heat Removal Pumps May Be February 11, 1999 Experiencing Cavitation CR 02108069 Design Change 1-DCP-720 Has Been April 18, 2002 Removed From the Scope of U1C18.

This Will Delay Resolution of the Operability Issue Documented in CR 99-2455 CR 02123015 This CR Is Written to Document an May 3, 2002 Aggregate Operability Determination to Support Unit 1 Restart Following the U1C18 Refueling Outage Miscellaneous Condition Reports Reviewed CR 02124008 While Performing 01-OHP 4030-102-060 May 4, 2002 (Pressurizer Relief Valve Testing) for 1-NRV-152 on Step 4.26.2 the Acceptance Criteria Was Not Met CR 02126093 Starting Air Check Valve Sealing Surface May 6, 2002 Defect on the 6R Cylinder Head 1R19 Post Maintenance Testing Job Order C0051164, Replace 1-BATT-CD During Year 2002 Outage UFSAR Chapter 8 Electrical Systems Revision 17.2 VTD-CDBA-001 C&D Technologies Standby Battery Revision 2 Vented Cell Installation and Operating Instructions Purchase Order C&D Technologies Certificate of May 9, 2002 NU04-0000020621 Compliance Institute of Electrical and IEEE Recommended Practice for May 31, 1995 Electronics Engineers Maintenance, Testing, and Replacement (IEEE) Standard of Vented Lead-Acid Batteries for 450-1995 Stationary Applications

American National IEEE Recommended Practice for May 18, 1987 Standards Institute Installation Design and Installation of (ANSI)/IEEE Large Lead Storage Batteries for Standard 484-1987 Generating Stations and Substations 12-IHP 5021-EMP-006 Battery Cell Replacement Revision 2 CR 02143005 Electro Alarm for Annunciator Panel 120, May 23, 2002 Drop 101 Did Not Work Correctly During Battery Draw Down Testing 12-IHP-4030-082-003 AB, CD, and N-Train Battery Discharge Revision 2 Test and 18 Month Surveillance Requirements Job Order C0051164 Replace 1-BATT-CD During Year 2002 Outage Job Order R0209107 Perform 1-BATT-CD 18 Month Surveillance Design Change Procedure (DCP) 4504, Replace Reserve Auxiliary Transformers 101AB and 102CD with Load Tap Changing Transformers Job Order 01159017 1-DCP-4504/Replace Unit 1 TR101AB Job Order 01159019 1-DCP-4504/Replace Unit 1 TR101CD 01 OHP 4030-182-026 Auxiliary Power Transfer Test Revision 0a, Attachment 1 Surveillance Procedure, Automatic Performed Transfer of Reactor Coolant Buses to May 30, 2002 Reserve Feed By Simulated or Intended Unit Trip 01 OHP 4030-132-217A DG1CD Load Sequence & ESF Revision 2

[Engineered Safety Features] Testing 01 OHP 4030-132-217B DG1AB Load Sequence & ESF Testing Revision 2 1-DCP-4504-TP-1 Reserve Auxiliary Transformer 101AB Revision 0 Functional Test 1-DCP-4504-TP-2 Reserve Auxiliary Transformer 101CD Revision 0 Functional Test 1-DCP-4504-TP-3 Bus T11A and DCP-4505 Relay Change Revision 0 Out Functional Test 1-DCP-4504-TP-4 Bus T11D and DCP-4505 Relay Change Revision 0 Out Functional Test

1-DCP-4504 Replace Auxiliary Transformers 101AB Revision 0 and 101CD with Load Tap Changing Transformers DCP 4504, Install New Undervoltage Protection Relays Job Order R0228922 Perform 1-IHP-6030-IMP-309 4kV Bus May 23, 2002 Undervoltage Relay Calibration Job Order R0229719 Perform 1-IHP-6030-IMP-309 4kV Bus June 4, 2002 Undervoltage Relay Calibration 01 IHP 6030-IMP-309 4KV Bus Loss of Voltage and 4KV Bus Revision 5 Degraded Voltage Relay Calibration CR 02154052 Degraded Voltage Relay 1-27-T11A1 June 3, 2002 Failed to Actuate During Train B LOP

[Loss of Off-site Power]/LOCA Testing 01 OHP 4022.082.004 Degraded Offsite AC Voltage Response Revision 1 01 OHP 4024-119 Annunciator #119 Response: Station Revision10 Auxiliary AB 01 OHP 4024-120 Annunciator #120 Response: Station Revision xx Auxiliary CD 01 OHP 4024-121 Annunciator #121 Response: Generator Revision 17 01 OHP 4023-SUP-010 Starting Reactor Coolant Pumps Revision 1 01 OHP 4021-002-003 Reactor Coolant Pump Operation Revision 14 TS Table 3.3-4, Engineered Safety Feature Actuation Amendment 268 Functional Unit 8 System Instrumentation Trip Setpoints Job Order 02093039, Unit 2AB Station Battery Cell 46 Replacement UFSAR Chapter 8 Electrical Systems Revision 17.2 IEEE Standard 450-1995 IEEE Recommended Practice for May 31, 1995 Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications ANSI/IEEE IEEE Recommended Practice for May 18, 1987 Standard 484-1987 Installation Design and Installation of Large Lead Storage Batteries for Generating Stations and Substations

12-IHP-5021-EMP-006 Battery Cell Replacement Revision 2 Change 3 12-IHP-4030-082-001 AB, CD and N Train Battery Weekly Revision 0 Surveillance and Maintenance Change 1 Job Order 02093039 Unit 2AB Station Battery Cell 46 Replacement Unit 1 TDAFP Maintenance Job Order 01333060 Replace Valve 1-MS-326 By Welding April 11, 2002 Job Order 01303055 Repair Trap 1-T-76-2 Lack of Flow April 12, 2002 Job Order 0130357 Repair Trap 1-T-76-1 Lack of Flow April 12, 2002 Job Order R0221579 1-PP-4- Lube Pump Bearings and April 12, 2002 Coupling, Sample Oil Job Order R0212013 1-T-132 Perform Steam Trap Internal April 12, 2002 Inspection Job Order R0221666 1-QT-506 Generic Letter 89-10 Perform April 11, 2002 External Preventive Maintenance Specification Shop and Field Fabrication and Erection Revision 11 DCCPV102QCS of Conventional Piping 12-IHP-5030-EMP-001 Limitorque Valve Operator Preventive Revision 4 Maintenance Change 2 1R20 Refueling and Outage Activities D. C. Cook Nuclear Plant Unit 2 Technical Specifications D. C. Cook Nuclear Plant Updated Final Safety Analysis Report 01-OHP-4021-001-004 Plant Cooldown From Hot Standby to Revision 36 Cold Shutdown 01-OHP-4030-114-030 Daily and Shiftly Surveillance Checks Revision 0 12-OHP-4050-FHP-001 Refueling Procedure Guidelines Revision 3 12-OHP-4050-FHP-005 Core Unload/Reload and Incore Shuffle Revision 3 12-OHP-4050-FHP-023 Reactor Vessel Head Removal With Fuel Revision 0 in the Vessel

12-OHP-4050-FHP-026 Upper Internals Removal With Fuel in the Revision 1 Vessel 01-OHP-4030-STP-041 Refueling Integrity Revision 8 PMP 4100-SDR-001 Plant Shutdown Safety and Risk Revision 5, C1 Management Daily Shift Managers Logs May 3, 2002 through June 9, 2002 U12C18 Outage Schedule Shutdown Risk Review 01 OHP 4021-017-002 Placing In Service The Residual Heat Revision 16 Removal System 01 OHP 4021-001-004 Plant Cooldown From Hot Standby To Revision 36 Cold Shutdown 01-EHP-4030-102-386 Multiple Rod Drop Measurements Revision 0a 01-OHP-4021-001-002 Reactor Startup Revision27a 12-EHP-4030-002-356 Low Power Physics Tests with Dynamic Revision 0b Rod Worth Measurement 1-DCP-5075 Unit 1 Cycle 18 Reload Cord Design Revision 0 CR 02111020 Generator Voltage Dropped From 116 April 21, 2002 Volts to 110 Volts CR 02118009 MVARs [Megavolt-Amperes Reactive] April 28, 2002 Dropped From 60 in to 700 in While Attempting to Raise the Main Generator Voltage CR 02124001 1-MRV-240 (Number 4 Main Steam Stop May 4, 2002 Valve) Drifted Open Just After Reactor Trip CR 02124003 Unit 1 Main Turbine High Vibration After May 4, 2002 Manual Reactor Trip Required Partial Condenser Vacuum Breaking CR 02124004 Two Steam Plums Coming From the May 4, 2002 Fitting on the Top of the Transmitter Approximately 1 to 2 Feet Long

CR 02124023 Four Control Rod Bottom Lights Failed to May 4, 2002 Illuminate Following the Reactor Trip to Enter the Unit 1, Cycle 18 Refueling Outage CR 02125005 "B" Reactor Trip Breaker Control Switch May 5, 2002 was Inadvertently Turned to the "Close" Instead of the "Trip" Position CR 02037026 2-PW-275 Is Not Expected to Performed February 6, 2002 Adequately as a Containment Isolation Valve Throughout the Next Cycle CR 02114043 Design Change Number 12-RFC-2718 April 24, 2002 Was Initiated in 1989 to Replace Carbon Steel Valve Studs CR 02123056 Pipe Cap Leak in Containment Annulus May 3, 2002 Quad 4 CR 02123059 Brown Oily-like Substance Leaking from May 5, 2002 Overhead in Accumulator Number 2 CR 02124047 An Oxygen Alarm Received While May 4, 2002 Venting Nitrogen From the Accumulators in the Unit 1 Annulus CR 02127075 NRC Identified the Shutdown Risk May 7, 2002 Reporting Database in Lotus Notes Is Missing a Row From the Safety Function Table CR 02130012 1-DCR-304 Process was Breached May 10, 2002 Without Sufficient Clearance Protection CR 02131015 During Troubleshooting of ERS-2300, May 11, 2002 VRA-2310 Was Rendered Inoperable Without the Control Rooms Knowledge and Without Entering the Appropriate TS CR 02133015 Improper Lineup on SI [Safety May 13, 2002 Injection]/Charging Suction Lead to the Volume Control Tank and Refueling Water Storage Tank Being Operated in a Cross-Tied Configuration CR 02134003 Fuel Assembly GG02 Identified as May 14, 2002 Leaking by In-mast Fuel Sipping

CR 02134039 U1 Refueling Water Sequence Was May 14, 2002 Initiated when a Drain (1-CS-348) Was Opened Prior to the CCP [Centrifugal Charging Pump] Suction Valves (1-IMO-910/911) De-energized CR 02135066 Debris Was Found and Then Removed May 15, 2002 on Top of the Reactor Head During Remote Visual Inspection CR 02136042 Inactive/Passive Boric Acid Was Found May 16, 2002 on the Top of the Reactor Vessel Head CR 02136095 In-core Fuel Source Secondary Source May 16, 2002 (SS17) Has Been Found with on Finger Missing 4-5 Feet in Length CR 02141047 During U1C18 Steam Generator Eddy May 22, 2002 Current Inspections 4 Tubes Were Identified with Abnormal Eddy Current Signals CR 02143095 NRC Identified That Reactor Operator May 5, 2002 Returned Control Power to Residual Heat Removal Pump Refueling Water Storage Tank Suction Contrary to Procedural Guidance CR 02159004 NRC Identified Concerns Associated with June 7, 2002 Access Controls to Reactor Vessel Head During Sub-critical Control Rod Withdrawals CR 02177047 NRC Identified Adverse Housekeeping June 26, 2002 and Work Practice in the Control Room Back Panel Areas on June 7, 2002. A CR Was Not Promptly Written to Trend This Condition 1R22 Surveillance Testing 12 MHP 4030-10-03, "Ice Condenser Lower Inlet Door Surveillance" 12 MHP 4030-010-003 Ice Condenser Lower Inlet Door Revision 2a Surveillance CR 02149034 NRC identified that the test acceptance May 29, 2002 criteria for the ice condenser lower inlet door testing was incorrectly determined

CR 02132047 Unit 1 lower ice condenser inlet door 15 May 12, 2002 right failed the 40 degree opening force test CR 02133017 Unit 1 lower ice condenser inlet door 4 May 13, 2002 right failed the 40 degree opening force test CR 02136018 Unit 1 lower ice condenser inlet door 21 May 16, 2002 right door spring dragging DIT S-00105-02 Ice Condenser Lower Inlet Door Revision 2 Surveillance Requirements and Basis Donald C. Cook Nuclear Plant, Unit 1 - February 14, 2002 Issuance of Amendment RE: Ice Condenser Lower Inlet Doors (TAC Number MB3989)

01-OHP-4030-108-008R, Attachment 8, "Accumulator Check Valve Test" 01-OHP-4030-108-008, Accumulator Check Valve Test Revision 0 Attachment 8 PMI 5070 Inservice Testing Revision 1 Westinghouse Nuclear Nitrogen Release to Residual Heat April 8, 2002 Safety Advisory Letter Removal During SI Accumulator Low NSAL-02-6 Pressure Blowdown Tests Westinghouse Letter AEP [American Electric Power] Units 1 April 24, 2002 LTR-SEE-02-110 and 2 Accumulator Check Valve Blowdown Test Report Design Information Information Requested by Westinghouse April 18, 2002 Transmittal (DIT) to Support Analysis of Proposed S-00885-03 Accumulator Check Valve Blowdown Testing DIT B-02320-02 Engineering Limitations on Conduct of May 1, 2002 Accumulator Check Valve Testing 01-OHP-4030-STP-017R, "Auxiliary Feedwater Pump Time Response Test" 01-OHP-4030-STP-017R Auxiliary Feedwater Pump Response Revision 9 Time PMP 4030.TRT.001 Time Response and Verification of Revision 2, Engineered Safety Features Change 7

02-OHP-4030-214-029, Attachment 1, "PPC [Plant Process Computer] Derived Reactor Thermal Power Evaluation" and 02-OHP-4030-214-029, Attachment 4,"

Power Range NI [Nuclear Instruments] Adjustments" 02-OHP-4030-214-029, PPC [Plant Process Computer] Derived Revision 1 Attachment 1 Reactor Thermal Power Evaluation 02-OHP-4030-214-029, Power Range NI [Nuclear Instrument] Revision 1 Attachment 4 Adjustments Daily Shift Managers Log April 5, 2002 CR P-00-10476 During Investigation of the June 30, 2000 July 26, 2000 Event Identified CR 00-9437, the Question Was Raised Regarding Whether the Power Range NIs, Which Were Found to Be Reading Above the TS 2.2.1 Limit, Should Have Been Declared Inoperable CR 01065006 TS 3.0.3 Was Entered Twice Due to NI March 6, 2001 Trip Set Point Being Greater Than 110 Percent Power CR 02095001 When Performing Power Reduction in April 5, 2002 Unit 2 Control Room Received Rod Sequence Violation Annunciator CR 02095045 Discovered Three Power Range NIs With April 5, 2002 a Calculated Trip Greater Than 110 Percent While Performing a Thermal Power Calculation CR 02107060 NRC Identified Sequencing of Sign-offs April 17, 2002 for Attachments and Listed Acceptance Criteria in Attachment 1 Appear to Indicate That It Is Acceptable to Sign-off the Acceptance Criteria As Satisfactory Prior to Performing Attachment 4 If Required PMI 5070, Inservice Testing," [Valve Stroke Testing of 1-MCM-221]

PMI 5070 Inservice Testing Revision 2

12 IHP 4030-082-003, "AB, CD and N Train Battery Discharge Test and 18 Month Surveillance Requirements" 12-IHP-4030-082-003 AB, CD and N Train Battery Discharge Revision 2 Test and 18 Month Surveillance Requirements Job Order R0209107 Perform 1-BATT-CD 18 Month Surveillance IEEE Std 450-1995 IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications CR 02143010 While Performing Drawdown on May 23, 2002 1-BATT-CD, Redundant Test Data Was Not Acquired Within the Required 2 Minute Time Frame at Test Initiation CR 02151069 NRC Identified That Battery Performance May 31, 2002 Testing Steps Associated with Comparison to Previous Test Data May Have Been Inappropriately Marked as Not Applicable CR 02151074 NRC Identified That No Process or May 31, 2002 Procedures Exist to Document or Control the Use of Vendor Testing to Satisfy TS Requirements CR 02143005 Electro Alarm for Annunciator Panel 120, May 23, 2002 Drop 101 Did Not Work Correctly During Battery Draw Down Testing 12-IHP-4030-082-003 AB, CD, and N-Train Battery Discharge Revision 2 Test and 18 Month Surveillance Requirements Job Order C0051164 Replace 1-BATT-CD During Year 2002 Outage Job Order R0209107 Perform 1-BATT-CD 18 Month Surveillance 01-OHP 4030.001.002, "Containment Inspection Tours" 01 OHP 4030.001.002 Containment Inspection Tours Revision 17 12 MHP 5040-010-003 Ice Condenser Support Activities Revision 2

CR 02156016 NRC Identified Small Boric Acid Buildup June 4, 2002 on 1-RC-102-L2 CR 02156014 NRC Identified Small Amount of Boric June 5, 2002 Acid Buildup on 1-SI-141-L3 CR 02156013 NRC Identified Small Amount of Boric June 4, 2002 Acid Buildup on 1-IMO-130 CR 02156012 NRC Identified Small Amount of Boric June 4, 2002 Acid Buildup on 1-SI-141-L2 CR 02154016 NRC Identified Minor Housekeeping and June 2, 2002 Transient Material Storage Issues in the Auxiliary Building CR 02156023 NRC Identified Standing Water by Ice June 4, 2002 Condenser Inlet Doors CR 02155082 NRC Identified a Puddle of Liquid Below June 4, 2002 Steam Generator Snubber 1-OME-3-3-HSD-3L CR 02156008 NRC Identified 1-QPX-200-V1 Has Valve June 5, 2002 Stem Leakage CR 02156010 NRC Identified 1-IMO-315 Had Boric Acid June 5, 2002 Buildup on the Stem CR 02156011 NRC Identified 1-QRV-114 Has Boric June 5, 2002 Acid Build-up on the Stem CR 02156017 NRC Identified Missing Screws From an June 5, 2002 Electrical Box Cover on the North Wall of the Regenerative Heat Exchanger Room Near 1-QRV-51 and -1-QRV-62 CR 02156019 NRC Identified Foreign Material June 5, 2002 Embedded in Concrete Against Outer Wall in the Overhead CR 02156021 NRC Identified Water Beneath the June 4, 2002 Number 13 Reactor Coolant Pump CR 02156083 NRC Identified Deficiencies When June 5, 2002 Inspecting the Unit 1 Containment 1R23 Temporary Plant Modifications D. C. Cook Nuclear Plant Updated Final Safety Analysis Report

Temporary Modification Install Water Splash Shields on the Unit 1 July 14, 2001 12-TM-01-23-R0 and Unit 2 AFW Pumps 12-EHP-5040-MOD-001 Temporary Modifications Revision 7a 10 CFR 50.59 Safety AFW Pump Bearing Housing Shield and July 13, 2001 Screening 2000-0604-00 Shaft Flinger Ring 10 CFR 50.59 Temporary Modification 12-TM-01-23-RO July 13, 2001 Applicability Determination 2001-0604-00 CR 01184086 Unit 1 West Motor Driven AFW Pump July 3, 2001 Inboard and Outboard Pump Bearing Have Water in the Bearing Reservoirs 1EP6 Drill Evaluation Cook Nuclear Plant Unannounced Drill Revision 1 Scenario April 16, 2002 CR 02107026 Perform Emergency Preparedness April 17, 2002 Self-assessment SA-2002-SPS-027,

"Second Quarter 2002 Off Hours Emergency Preparedness Drill" 2OS1 Access Controls For Radiologically Significant Areas PMP-6010-RPP-003 High, Locked High, and Very High Revision 10 Radiation Area Access Apparent Cause CR 021101048 Condition Evaluation - May 22, 2002 Evaluation Unlocked High Radiation Area in (Draft)

Drumming Room 01-OHP-4021-004-001, South Deborating Demineralizer Revision 10 Attachment 4 Operation as Parallel Flow Mixed Bed Demineralizer Rapid Event Response Inadequate Radiological Control and May 22, 2002 Investigation Report Postings (Draft)

Post Crud Burst Surveys of 617 Foot May 5 - 18, 2002 Demineralizer Gallery 587 Foot Drumming Room Survey April 10, 2002

CR 02101048 Door to 587 Foot Drumming Room April 11, 2002 Posted as Locked High Radiation Area But Card Reader Allowed Door to Open CR 02126004 Locked High Radiation Area Posting May 5, 2002 CR 02126018 Radiological Posting Around Pressurizer May 6, 2002 Hatch Didnt Reflect Conditions CR 02126020 Un-posted Locked High Radiation Area May 6, 2002 After Peroxide Flush CR 02041007 Radiological Area Status Sheets With February 9, 2002 Inaccurate Information 2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls U1C18 Outage ALARA Guide May 2002 U1C18 RWP Dose Totals Reports and May 16 - 24, 2002 Daily ALARA Dose Reports/Graphs Listing of Outage Generated CRs Coded May 1 - 23, 2002 to RP Issues PMP-6010.ALA.001 ALARA Program - Review of Plant Work Revision 11 Activities 12-THP-6010-RPP-018 Controls For Radiological Risk Significant Revision 0 Work Activities 12-THP-6010.RPP.006 Radiation Work Permit Processing Revision 17 RWP 021141 and U1C18 Steam Generator Primary Work - RWP Revisions 0 -

Associated ALARA Plan Platform Activities 4 TEDE ALARA Install Steam Generator Tube Plugs, Various Dates Evaluations For Steam Install Diaphragms and Manways, Steam Between April 30 -

Generator Platform Work Generator Nozzle Installation and May 20, 2002 Removal, Decontamination Activities on Platform, ROGER Removal 12-THP-6010.RPP.014 Total Effective Dose Equivalent Revision 3(a)

Evaluation RP Calculation 96-07 Contamination to DAC [Derived Air December 10, 1996 Concentration] Fraction Conversions ALARA In-Progress U1C18 Steam Generator Primary Work May 20, 2002 Review Activities

RWP 021136 and U1C18 Containment Install, Modify and RWP Revision 1 Associated ALARA Plan Remove Scaffold RWP 021140 and U1C18 Steam Generator Manway and RWP Revision 6 Associated ALARA Plan Diaphragm Activities ALARA In-Progress U1C18 Steam Generator Manway and May 15, 19 and 21, Reviews Diaphragm Activities 2002 TEDE ALARA Steam Generator Manway and April 30 and May Evaluations For Steam Diaphragm Removal, Installation and 20, 2002 Generator Manway and Support Work Diaphragm Activities RWP 021139 and U1C18 Valve Maintenance/Repair RWP Revision 3 Associated ALARA Plan ALARA In-Progress Valve Maintenance/Repair May 15 and 18, Review 2002 RWP 021134 and U1C18 Containment Remove, Reinstall RWP Revision 1 Associated ALARA Plan and Modify Insulation RWP 021149 and U1C18 Regenerative Heat Exchanger RWP Revision 2 Associated ALARA Plan Activities ALARA In-Progress Regenerative Heat Exchanger May 15, 2002 Review Maintenance CR 02139007 Contamination Event During Eddy May 18, 2002 Current Testing Rapid Event Response Personnel Contamination Event Resulting May 18, 2002 Report In Internal Contamination of Steam (Draft)

Generator Eddy Current Workers 12-THP-6010-RPP-006, Pre-job ALARA Briefing Checklist and May 6, 2002 Data Sheet 1 Attendance Roster Whole Body Count Analyses Results and May 22 - 24, 2002 Corresponding Dose Calculations Personnel Contamination Log May 7 - 23, 2002 12-THP-6020-CHM-110 RCS Chemistry - Shutdown/Refueling Revision 8(b)

Performance Assurance Radiation Protection February 22, 2002 Audit PA-02-06 through March 15, 2002 Root Cause Analysis U2C13 ALARA Dose Estimates May 2002 (Draft)

Exceeded

Performance Assurance CRUD Burst Activities During U1C18 May 7, 2002 Field Observation FO-02-E-030 Performance Assurance Personnel Use of Contamination May 17, 2002 Field Observation Monitors FO-02-E-088 Performance Assurance Follow-up of Actions as a Result of May 20, 2002 Field Observation Personnel and Internal Contamination FO-02-E-099 Performance Assurance Upper Internals Removal With Fuel in the May 11, 2002 Field Observation Vessel FO-02-E-054 Performance Assurance RP Practices When Exiting Contaminated May 10, 2002 Field Observation Areas FO-02-E-047 Performance Assurance Transfer Canal Pre-job ALARA Brief May 7, 2002 Field Observation FO-02-E-057 Performance Assurance ALARA Plan For Scaffold Activities May 5, 2002 Field Observation FO-02-E-020 2PS2 Radwaste Processing and Transportation 12-THP-6010-RPP-901 Resin Transfer to Qualified Shipping Revision 4A Container 12-THP-6010-RPP-904 High Integrity Containers Revision 1C PMP-6010-PCP-900 Radioactive Waste Process Control Revision 4B Program 12-THP-6010-RPP-909 Filter Packaging Revision 1B 12-THP-6010-RPP-906 Processing Wet Radioactive Wastes Revision 1A 12-THP-6010-RPP-902 De-watering of High Integrity Containers Revision 3 PMP-6010-PCP-901 Shipment of Radioactive Materials and Revision 1A Waste 12-THP-6010-RPP-900 Preparation of Radioactive Shipments Revision 7A 12-THP-6010-RPP-903 Activity Determination and Waste Revision 3 Classification

12-THP-6010-RPP-913 Scaling Factor Determination Revision 0A Shipment RMC-01-048 Waste Manifest and Associated October 25, 2001 Shipment Preparation Documents Shipment RMC-01-070 Waste Manifest and Associated December 15, 2001 Shipment Preparation Documents Shipment RMC-01-003 Waste Manifest and Associated January 17, 2001 Shipment Preparation Documents Shipment RMC-00-106 Waste Manifest and Associated May 5, 2000 Shipment Preparation Documents Shipment RMC-99-100 Waste Manifest and Associated September 17, 1999 Shipment Preparation Documents Shipment RMC-00-293 Waste Manifest and Associated December 18, 2000 Shipment Preparation Documents Shipment RMC-01-009 Waste Manifest and Associated February 1, 2001 Shipment Preparation Documents Shipment RMC-02-025 Waste Manifest and Associated February 11, 2002 Shipment Preparation Documents EA-C-R-RW01 Radioactive Waste Lesson Plan November 2001 EA-O-509005 Qualification Card - Survey a Shipment of Various Dates and Radioactive Material Individuals EA-O-509007 Qualification Card - Prepare Radioactive Various Dates and Waste Containers Individuals EA-O-509024 Qualification Card - Perform Checks on Various Dates and Radioactive Materials Shipping Individuals Containers EA-O-509029 Qualification Card - Load Radioactive Various Dates and Waste onto Vehicles Individuals EA-O-509035 Qualification Card - Sort Radioactive Various Dates and Waste in Preparation for Shipment Individuals PA-02-06 Performance Assurance Audit - Radiation February 22 - March Protection 15, 2002 PA-01-14 Performance Assurance Audit - Radiation February 9 - March Protection 16, 2001 FO-99-K-173 Field Observation - Environmental October 20, 1999 Radioactive Shipment

FO-00-C-154 Field Observation - Review of Findings March 7 - 10, 2000 from Audit 99-10/NSDRC 268. Receipt, Packaging and Shipment of Radioactive and Fissile Material FO-00-I-046 Field Observation - Radwaste Laundry September 8 - 11, Shipment 2000 FO-00-L-072 Field Observation - High Level December 17, 2000 Radioactive Waste Shipment SA-2002-REA-001 Draft Report of Self Assessment - March 11 - 15, 2002 Packaging and Shipping of Radioactive Waste CR 02074040 Potential Declining Trend in Procedure March 15, 2002 Adherence by Radiation Protection CR 01043011 High Integrity Container Rigging February 12, 2001 CR 01068026 Radioactive Source Potentially March 9, 2001 Improperly Controlled CR 01081034 Certificate of Compliance Minor March 22, 2001 Discrepancy CR 01129036 Drum Being Prepared for Shipment With May 9, 2001 Unexpected Dose Rate CR 01205043 Contamination on Resin High Integrity July 24, 2001 Container CR 01345038 Unexpected Dose Rate on Side of December 11, 2001 Container Being Loaded for Shipment CR 02066016 Issues from Self Assessment March 7, 2002 SA-2002-REA-001, Packaging and Shipping of Radioactive Waste 3PP1 Physical Protection (Access Authorization)

12 PMP 2060.ACS.002 Access Authorization Program January 13, 1997 Revision 1 AEP:NRC:2691-01 FFD [Fitness-for-Duty] Six Month Data February 22, 2002 (July 1, 2001 to December 31, 2001)

CO801-03 FFD Six Month Data (January 1, 2001 - August 3, 2001 June 30, 2001)

Performance Assurance Access Authorization/ May 25, 2001 Audit PA-01-11 Personnel Access Data System (PADS)

Performance Assurance Fitness-for-Duty Program December 11, 2000 Audit PA-00-15 Quarterly Security Event Log 1st Quarter 2002 Quarterly Security Event Log 4th Quarter 2001 Performance Assurance Access Authorization April 16, 2002 Surveillance SR-02-0005 3PP2 Physical Protection (Access Control)

12 PP2060 SEC 008 Tests of Security Related Equipment Revision 6 12 PMP 2060 SEC.006 Security Requirements for Plant Revision 0 Personnel CR 02113070 Unauthorized Vehicle Past Post One April 23, 2002 Quarterly Security Event Log 1st Quarter 2002 Quarterly Security Event Log 4th Quarter 2002 Security Initiated Condition Reports January 1, 2002 to April 26, 2002 4OA1 Performance Indicator (PI) Verification Special Plant Procedure Performance Indicator Data Gathering Revision 0 (SPP) 2060 SFI 101 PMP 7110.PIP.001 Regulatory Oversight Program Revision 1 Performance Indicators PI Camera Submittal October 1, 2001 to March 31, 2002 Perimeter PI Submittal October 1, 2001 to March 31, 2002 4OA3 Event Follow-up LER 50-316-2001-002-00 Failure of Lower Containment Airlock March 16, 2001 Door Interlock Results in Inadvertent Opening of Both Doors LER 50-316-2001-002-01 Failure of Lower Containment Airlock October 26, 2001 Door Interlock Results in Inadvertent Opening of Both Doors

LER 50-316-2002-001-00 Containment Isolation Valve Alignment March 28, 2002 Error During Local Leak Rate Testing LER 50-315-2002-002-00 Pressurizer Power Operated Relief April 19, 2002 Valves Inoperable Due to Control Switch Position 02-OHP-4030.STP.041 Refueling Integrity Revision 8 Drawing OP-2-5120D-25 Flow Diagram Containment Control Air Revision 25 85 Pound and 50 Pound Ring Headers Unit 2 CR 02043026 Refueling Integrity Lost When 2-XCR-101 February 12, 2002 Was Stroked During Core Alterations LER 50-316-2002-002-00 Technical Specification 3.9.4.c Was April 12, 2002 Violated During Core Alterations 4OA3.5 Ice Condenser Lower Inlet Door Testing CR 02032016 NRC Identified That Ice Condenser January 31, 2002 Lower Inlet Door Testing Performed Prior to the Unit 1 and Unit 2 Restart in 2000 Was Inadequate NRC Letter to Donald C. Cook Nuclear Plant, Unit 1 - February 14, 2002 Mr. Issuance of Amendment Re: Ice Condenser Lower Inlet Doors (TAC Number MB3989)

Job Order R0210872 Unit 1 - Perform Lower Ice Condenser May 30, 2002 Inlet Door Surveillance Job Order R0087658 Perform Lower Inlet Door Surveillance November 22, 2000 12 MHP 4030.010.003 CR 02091007 NRC Identified Incorrect Title in Cover April 1, 2002 Letter for LER 50315-2002-001-00 CR 02132047 Unit 1 Lower Ice Condenser Inlet Door 15 May 12, 2002 Right Failed As-found Opening Torque Test Required by TS 4.6.5.3.1.b.3 CR 02133017 Unit 1 Lower Ice Condenser Inlet Door 4 May 13, 2002 Right Failed As-found Opening Torque Test Acceptance Criteria of 12 MHP 4030.010.003

CR 02150052 NRC Identified Error in Reportability May 30, 2002 Evaluation for Ice Door 15 Right Failure.

Condition Is Reportable.

4OA3.6 Cell Cracking Rendered 2AB 250 VDC Station Battery Inoperable and Review of Associated Notice of Enforcement Discretion (NOED)

AEP Letter Donald C. Cook Nuclear Plant Unit 2 April 8, 2002 AEP:NRC:2016-01 Request for Notice of Enforcement Discretion for the Unit 2 AB Station Battery NRC Letter to Notice of Enforcement Discretion for April 10, 2002 Mr. Indiana Michigan Power Company Regarding D.C. Cook, Unit 2 (NOED 02-3-001), EA 02-065 CR 01347067 Internal Degradation Found on 23 Cells December 13, 2001 of 2-BATT-AB During Surveillance CR 02093039 2AB Station Battery Cells 102 and 27 April 3, 2002 Have Top Cover Cracks CR 02095021 Inoperability of Three 2AB Battery Cells April 4, 2002 Not Reported in a Timely Manner CR 02107063 NRC Identified Minor Inconsistency April 17, 2002 Between Verbal and Written NOED Request for 2AB 250 VDC Station Battery 4OA3.7 Significance Determination Process Review for Gas Binding of Unit 2 Centrifugal Charging Pumps Due to Inadequate Valve Maintenance Activity CR 02047050 The Unit 2 West CCP Showed Signs of February 16, 2002 Air Entrainment During Attempts to Swap Its Suction From the Volume Control Tank to the Refueling Water Storage Tank 12 MHP 5021-001-023 Manual Diaphragm Valve Maintenance Revision 6 Job Order 01094018 2-CS-369 Replace Diaphragm 02 OHP 4021.002.013 Reactor Coolant System Vacuum Fill Revision 1 Memo from R.W. Hennan Unit 2 Time to 200°F and Time to Boil January 4, 2002 to Shift Technical Advisor Graphs for the Refueling Outage Vendor Manual DIA-FLO Handwheel Operated VTD-ITEV-0027 Diaphragm Valves

Vendor Manual DIA-FLO Diaphragm Valves Installation, VTD-ITEV-0017 Operation, and Maintenance Manual Vendor Manual ITT Engineered Valves Maintenance and VTD-ITEV-0016 Instruction Manual for Handwheel Operated Diaphragm Valves Unit 2 Control Room Logs February 2002 4OA3.8 URI 50-316-00-19-02; 50-316-00-19-02: "Potentially Non-Conservative Engineered Ventilation TS 3.7.6.1."

CR 01138078 Calculation 12-HV-042-N Was Issued to May 18, 2001 Address CR 00-6947. The Calculation Acceptance Criteria Is Not Traceable to an Approved Design Input.

CR 00-11265 NRC Questioned Inconsistency Between August 12, 2000 Design Basis Calculation and TS 3.7.6.1 Limiting Conditions for Operation CR 98-6364 New Calculation of Heat Gain of the November 2, 1998 Auxiliary Building Ventilation System Was Performed and Results Show Several ESF Equipment Rooms Exceed 125°F

[Degrees Fahrenheit]

Calculation TH-01-05 Auxiliary Building Temperature Analysis Revision 0 DIT B-00501-03 Time-Temperature Profiles for Plant Revision 3 Areas During Normal Conditions DIT B-00197-26 Time-Temperature Profiles for Plant Revision 26 Areas During Accident Conditions CR 02046034 Calculation TH-01-05 Supercedes Old February 15, 2002 Auxiliary Building Calculations and Results in Higher Temperatures 40A5 Other MRS-SSP-1319 Reactor Vessel Head Penetration May 8, 2002 Remote Visual Inspections for D. C. Cook Unit 1 MRS-SSP-1320 Reactor Vessel Head Penetration May 8, 2002 Inspection Tool Operation D. C. Cook Unit 1

MRS-SSP-1321 Penetration Thermal Sleeve Removal May 8, 2002 and Installation at D. C. Cook Unit 1 D. C. Cook Unit 1 Reactor Vessel Head May 6, 2002 Penetration Inspection Acquisition and Analysis Training Outline ISI-ET-001 Eddy Current Inspection of J-Groove January 7, 2002 Welds in Vessel Head Penetrations ISI-ET-002 Eddy Current Procedure for Detection of January 7, 2002 Cracks in Vessel Head Penetrations With or Without Thermal Sleeves-Differential Gap Probe ISI-UT-003 Ultrasonic Inspection of Reactor Vessel October 22, 2001 Head Penetrations Using Pulse Echo Techniques WDI-UT-007 Ultrasonic Procedure for Detection of January 14, 2002 Circumferential Indications in Reactor Head Penetration Welds - 0 Degree to 20 Degree Sword Probes ISI-UT-002 Time of Flight Ultrasonic Inspection of January 13, 2002 Reactor Head Penetrations CR 02135066 Debris Was Found and Then Removed May 15, 2002 on Top of the Reactor Head During Remote Visual Inspection CR 02136042 Inactive/passive Boric Acid Was Found May 16, 2002 on the Top of the Reactor Vessel Head 91

IR 05000315/2002003

Text

SUBJECT:

Dear Mr. Bakken:

Enclosure:

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2002 Quarterly Integrated 1Q (0) 2Q (0) 3Q (1) 4Q (0) Assessments Mid Cycle End of Cycle 7(0) 8(0) 9(0) Security Operator Exams 301(0) Emergency Planning Other