IR 05000315/2006006
| ML062920318 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 10/18/2006 |
| From: | Christine Lipa NRC/RGN-III/DRP/RPB4 |
| To: | Nazar M Indiana Michigan Power Co, Nuclear Generation Group |
| References | |
| IR-06-006, IR-06-013 | |
| Download: ML062920318 (38) | |
Text
October 18, 2006
SUBJECT:
D. C. COOK NUCLEAR POWER PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000315/2006006; 05000316/2006006 and 05000315/2006013; 05000316/2006013
Dear Mr. Nazar:
On September 30, 2006, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your D. C. Cook Nuclear Power Plant, Units 1 and 2. The enclosed report documents the inspection results, which were discussed on September 27, 2006, with Mr. J. Jensen and other members of your staff.
This inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
Based on the results of this inspection, no findings of significance were identified.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Christine A. Lipa, Chief Projects Branch 4 Division of Reactor Projects Docket Nos. 50-315; 50-316 License Nos. DPR-58; DPR-74 Enclosure:
Inspection Report 05000315/2006006; 05000316/2006006 and 05000315/2006013; 05000316/2006013 w/Attachment: Supplemental Information cc w/encl:
M. Peifer, Site Vice President L. Weber, Plant Manager S. Simpson, Regulatory Affairs Manager G. White, Michigan Public Service Commission L. Brandon, Michigan Department of Environmental Quality -
Waste and Hazardous Materials Division Emergency Management Division MI Department of State Police State Liaison Officer, State of Michigan
SUMMARY OF FINDINGS
IR 05000315/2006-006, IR 05000316/2006-006; 05000315/2006-013, IR 05000316/2006-013; 07/01/2006-09/30/2006; D. C. Cook Nuclear Power Plant, Units 1 and 2; Integrated Inspection Report.
The report covered a 13-week period of inspection by the resident inspectors and announced inspections by regional inspectors. No findings of significance were identified. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.
NRC-Identified
and Self-Revealed Findings None.
Licensee Identified Violations
None.
REPORT DETAILS
Summary of Plant Status
Unit 1 was operated at or near full power during the inspection period with the following exceptions:
C On July 30, 2006, Unit 1 was shut down as required by the plant's Technical Specifications (TS) due to exceeding the 120 degrees Fahrenheit (EF) lower containment air temperature limit. Following the installation of a supplemental cooling water supply to the lower containment ventilation coolers and reduction of the lower containment air temperature, the licensee performed a reactor startup and synchronized the unit to the grid on August 3, 2006.
C On August 18, 2006, the licensee began a gradual power reduction (i.e., a coast down)from 100 percent to 53 percent on September 13, 2006. The unit was maintained at about 53 percent power to perform steam generator safety valve testing until September 16, 2006, when the licensee conducted a reactor shutdown for the Cycle 21 refueling outage (U1C21). The unit was defueled at the end of the inspection period.
Unit 2 was operated at or near full power during the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness
1R04 Equipment Alignment
.1 Partial System Walkdowns
a. Inspection Scope
The inspectors completed three partial equipment walkdown inspection samples for the following risk significant systems:
C Unit 1 AB Emergency Diesel Generator (EDG)
C Unit 2 West Motor Driven and Turbine Driven Auxiliary Feedwater Pump Trains C
Unit 1 Train "A" Auxiliary Feedwater, Essential Service Water (ESW), and Component Cooling Water Flow Paths and Electrical Requirements to Support Safe Shutdown for Unit 2 The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones. The inspectors reviewed operating procedures, system diagrams, TS requirements, and the impact of ongoing work activities on redundant trains of equipment. The inspectors verified that conditions did not exist that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components were aligned correctly and available as necessary.
In addition, the inspectors verified that equipment alignment problems were entered into the licensee's corrective action program with the appropriate characterization and significance. Selected condition reports were reviewed to verify that corrective actions were appropriate and implemented as scheduled.
b. Findings
No findings of significance were identified.
.2 Complete System Walkdown
a. Inspection Scope
The inspectors performed one complete system walkdown inspection sample for the following risk significant system:
C Unit 2 Auxiliary Feedwater System The inspectors interviewed the system engineer and reviewed ongoing system maintenance, open job orders, and design issues for potential effects on the ability of the system to perform its design functions. The inspectors reviewed operating procedures, system diagrams, TS requirements, and applicable sections of the Updated Final Safety Analysis Report (UFSAR) to ensure the correct system lineup. 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
.1 Routine Resident Inspector Tours
a. Inspection Scope
The inspectors completed six quarterly fire protection inspection samples by performing walkdowns in the following plant areas:
C Technical Support Center Uninterruptible Power System Inverter and Battery Room (Zone 127)
C Auxiliary Building Access Control Area 609' Elevation (Zone 43)
C Unit 1 East Containment Accumulator Enclosure 612' Elevation (Zone 120)
C Unit 1 Ice Condenser 640' Elevation (Zone 132)
C Unit 1 Containment Instrument Room 612' Elevation (Zone 122)
C Unit 1 West Containment Accumulator Enclosure 612' Elevation (Zone 110)
The inspectors verified that transient combustibles and ignition sources were appropriately controlled; and, assessed the material condition of fire suppression systems, manual fire fighting equipment, smoke detection systems, fire barriers and emergency lighting units.
In addition, the inspectors verified that fire protection related problems were entered into the licensee's corrective action program with the appropriate characterization and significance. Selected condition reports were reviewed to verify that corrective actions were appropriate and implemented as scheduled.
b. Findings
No findings of significance were identified.
1R06 Flood Protection
.1 Internal Flood Protection
a. Inspection Scope
The inspectors performed one inspection activity related to the licensee's precautions to mitigate the risk from internal flooding events. Specifically, the inspectors verified the adequacy of internal flood protection features for the lower elevations of the Auxiliary Building. The following inspection activities were performed:
C The inspectors reviewed the Unit 1 and Unit 2 Flooding Evaluation reports, the UFSAR and other selected design basis documents to identify those areas susceptible to internal flooding.
C The inspectors performed a walkdown of the lower elevations of the Auxiliary Building to verify that the installation of components was consistent with the assumptions in the licensee's design basis and that the components would be operable in the event of flooding.
C The inspectors reviewed selected operating procedures used to identify and mitigate internal flooding events and verified that these procedures were adequate.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program
.1 Resident Inspector Quarterly Review
a. Inspection Scope
The inspectors assessed licensed operator performance and the training evaluators' critique during a licensed operator requalification evaluation in the D. C. Cook plant operations training simulator on August 29, 2006. The inspectors focused on alarm response, command and control of crew activities, communication practices, procedural adherence, and implementation of emergency plan requirements. This activity represented one inspection sample.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
.1 Resident Inspector Quarterly Review
a. Inspection Scope
The inspectors completed three quarterly maintenance effectiveness inspection samples by evaluating the licensee's handling of selected degraded performance issues involving the following risk-significant structures, systems, and components (SSCs):
C Unit 1 and Unit 2 Power Range and Intermediate Range Nuclear Instruments C
Supplemental Diesel Generators C
Unit 1 and Unit 2 Auxiliary Feedwater System The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the SSCs. Specifically, the inspectors independently verified the licensee's handling of SSC performance or condition problems in terms of:
C appropriate work practices, C
identifying and addressing common cause failures, C
scoping of SSCs in accordance with 10 CFR 50.65(b),
C characterizing SSC reliability issues, C
tracking SSC unavailability, C
trending key parameters (condition monitoring),
C 10 CFR 50.65(a)(1) or (a)(2) classification and reclassification, and C
appropriateness of performance criteria for SSCs/functions classified (a)(2)and/or appropriateness and adequacy of goals and corrective actions for SSCs/functions classified (a)(1).
In addition, the inspectors verified that problems associated with the effectiveness of plant maintenance were entered into the licensee's corrective action program with the appropriate characterization and significance. Selected condition reports were reviewed to verify that corrective actions were appropriate and implemented as scheduled.
b. Findings
b.1 Power Range and Intermediate Range Nuclear Instruments The inspectors reviewed equipment performance issues associated with the power range and intermediate range nuclear instruments for both units and found multiple examples where Maintenance Rule Evaluations (MREs) were either not performed for component failures or where the completed MRE conclusion was questionable.
Sufficient information or justification was not provided in some of the MREs that were completed to support the conclusion that was reached. As a result, it appeared that there were several functional failures that were either not evaluated or not correctly evaluated. The licensee wrote condition reports to address these examples and other questions raised by the inspectors in its corrective action program. This issue is considered to be an Unresolved Item (URI 05000315/316/2006006-01) pending review of MREs that will need to be completed or revised for the examples identified during this inspection.
.2 Periodic Evaluation
a. Inspection Scope
The inspectors examined the Maintenance Rule Periodic Evaluation Report completed for the period of July 2004 through March 2006. To evaluate the effectiveness of (a)(1)and (a)(2) activities, the inspectors examined a sample of (a)(1) Action Plans, performance criteria, functional failures, and condition reports. These same documents were reviewed to verify that the threshold for identification of problems was at an appropriate level and the associated corrective actions were appropriate. Also, the inspectors reviewed the Maintenance Rule procedures and processes. The inspectors focused the inspection on the following four systems (samples):
C Auxiliary Power (4160 Vac)
C Control Rod Drive C
Chemical and Volume Control System C
ESW The inspectors verified that the periodic evaluation was completed within the time restraints defined in 10 CFR 50.65 (once per refueling cycle, not to exceed 24 months).
The inspectors also ensured that the licensee reviewed its goals, monitored SSCs performance, reviewed industry operating experience, and made appropriate adjustments to the Maintenance Rule Program as a result of the above activities.
The inspectors verified that:
- the licensee balanced reliability and unavailability during the previous cycle, including a review of high safety significant SSCs;
(a)(1) goals were met, that corrective action was appropriate to correct the defective condition, including the use of industry operating experience, and that (a)(1) activities and related goals were adjusted as needed; and
- the licensee has established (a)(2) performance criteria, examined any SSCs that failed to meet their performance criteria, and reviewed any SSCs that have suffered repeated maintenance preventable functional failures including a verification that failed SSCs were considered for (a)(1).
In addition, the inspectors reviewed Maintenance Rule self-assessments and audit reports that addressed the Maintenance Rule Program implementation.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Evaluation
a. Inspection Scope
The inspectors completed six inspection samples regarding maintenance risk assessments and emergent work evaluations for the following maintenance activities:
C Unit 1 AB EDG Planned Maintenance on July 18, 2006 C
Unit 2 Turbine Driven Auxiliary Feedwater Pump Planned and Emergent Maintenance Activities from July 26 through July 28, 2006 C
Unit 2 CD EDG Planned Maintenance from August 8 through August 9, 2006 C
Unit 2 East Motor Driven Auxiliary Feedwater Pump Maintenance Concurrent with Switchyard Maintenance on September 6, 2006 C
Unit 1 AB EDG Maintenance and West Centrifugal Charging Pump Maintenance During the Week of September 18, 2006 C
Unit 1 Dual ESW Pump Outage from September 29 through September 30, 2006 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 in the plant's daily schedule, verified that plant risk assessments were completed as required by 10 CFR 50.65(a)(4) prior to commencing maintenance activities, discussed the results of the assessment with the licensee's probabilistic risk analyst and/or shift technical advisor, and verified that plant conditions were consistent with the risk assessment assumptions. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify that risk analysis assumptions were valid, that redundant safety-related plant equipment necessary to minimize risk was available for use, and that applicable requirements were met.
In addition, the inspectors verified that maintenance risk related problems were entered into the licensee's corrective action program with the appropriate significance characterization. Selected condition reports were reviewed to verify that corrective actions were appropriate and implemented as scheduled.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors completed three inspection samples associated with operability evaluations by reviewing the following condition reports (CRs):
C CR 06145114, "The Lower Containment Average Air Temperature May Not Be Representative of the Entire Lower Volume" C
CR 00800196, "ERS-1300 Not Showing Expected Activity Post Filter Change" C
CR 00801388, "Containment Purge TS" The inspectors verified that the conditions did not render the associated equipment inoperable or result in an unrecognized increase in plant risk. When applicable, the inspectors verified that the licensee appropriately applied TS limitations and appropriately returned the affected equipment to an operable status.
In addition, the inspectors verified that problems related to the operability of safety-related plant equipment were entered into the licensee's corrective action program with the appropriate characterization and significance.
b. Findings
No findings of significance were identified.
1R19 Post Maintenance Testing
a. Inspection Scope
The inspectors completed two baseline inspection samples pertaining to post maintenance testing by assessing testing activities that were conducted on the following plant equipment:
C Unit 1 AB EDG Voltage Regulator Replacement C
Unit 2 CD EDG Fuel Injector Pump Replacements The inspectors reviewed the scope of the work performed and evaluated the adequacy of the specified post maintenance testing. The inspectors verified the post maintenance testing was performed in accordance with approved procedures, that the procedures clearly stated the acceptance criteria, and that the acceptance criteria were met. The inspectors interviewed operations, maintenance, and engineering department personnel and reviewed the completed post maintenance testing documentation.
b. Findings
No findings of significance were identified.
1R20 Refueling and Other Outage Activities
.1 Unit 1 Forced Outage
a. Inspection Scope
The inspectors completed one inspection sample regarding forced outage activities.
On July 30, 2006, the licensee entered a forced outage on Unit 1 following a plant shutdown required by the TS because the average lower containment exceeded the 120EF limit. The unit was maintained in Mode 3 (Hot Standby) during the forced outage since the lower containment temperature was reduced below 120EF before the time required to have the unit enter Mode 5 (Cold Shutdown). Following the flushing of lower containment ventilation coolers and installation of a temporary supplemental cooling system for the non-essential service water supply to the containment, the licensee performed a reactor startup and synchronized the unit to the grid on August 3, 2006.
The inspectors evaluated the conduct of forced outage activities to assess the control of plant configuration and management of risk. The inspectors reviewed configuration management to verify that the licensee maintained defense-in-depth commensurate with the risk plan and reviewed outage work activities to ensure that correct system lineups were maintained for key mitigating systems. The inspectors also observed portions of the reactor startup activities to verify that the TS requirements and administrative procedure requirements were met prior to changing operational modes or plant configurations. The inspectors interviewed operations, engineering, work control, and maintenance department personnel and reviewed selected procedures and documents.
b. Findings
No findings of significance were identified.
.2 Unit 2 Refueling Outage
a. Inspection Scope
On September 16, 2006, the licensee started the Cycle 21 refueling outage on Unit 1.
The inspectors began refueling outage inspection activities, which are expected to be completed and documented during the next inspection period. An inspection sample was not completed during this inspection period.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors completed two inspection samples regarding surveillance testing by reviewing the following activities.. This constituted one Inservice Testing (IST) sample and one local leak rate test (LLRT) sample.
C 1-EHP-4030-134-203, "Unit 1 LLRT" (LLRT sample)
C 2-OHP-4030-208-051S, "South Safety Injection Pump System Test" (IST sample)
The inspectors observed portions of the test activities to verify that the testing was accomplished in accordance with plant procedures. The inspectors reviewed the test methodology and documentation to verify that equipment performance was consistent with safety analysis and design basis assumptions, and that testing acceptance criteria were satisfied. In addition, the inspectors verified that surveillance testing problems were being entered into the licensee's corrective action program with the appropriate characterization and significance.
b. Findings
No findings of significance were identified.
1R23 Temporary Modifications
a. Inspection Scope
The inspectors completed one inspection sample by reviewing the following temporary modification that was utilized on plant equipment:
C 12-TM-06-32-R1, "Installation of Supplemental Containment Cooling for Units 1 and 2" The inspectors interviewed engineering, operations and maintenance department personnel, and reviewed the design documents and applicable 10 CFR 50.59 evaluation to verify that TS and the UFSAR requirements were satisfied. The inspectors reviewed documentation and conducted plant walkdowns to verify that the modification was implemented as designed and that the modification did not adversely impact system operability or availability.
The inspectors also reviewed a sample of condition reports pertaining to temporary modifications to verify that problems were entered into the licensee's corrective action program with the appropriate significance characterization and that corrective actions were appropriate.
b. Findings
No findings of significance were identified.
1EP6 Drill Evaluation
a. Inspection Scope
The inspectors observed activities in the plant simulator and the Technical Support Center during an emergency preparedness training drill conducted on August 22, 2006.
The drill included operator participation in the plant simulator and a turnover between two emergency response duty teams. The inspectors verified the emergency classifications and notifications to offsite agencies were completed in an accurate and timely manner as required by the Emergency Plan implementing procedures. The inspectors also verified that the training drill was conducted in accordance with the prescribed sequence of events, drill objectives were satisfied and that the required prompts from the licensee drill controllers were appropriately communicated to the drill participants.
The inspectors observed the post-drill critique in the Technical Support Center and reviewed documented post-drill critique comments by licensee evaluators to verify licensee personnel and licensee drill evaluators adequately self-identified drill performance problems of significance. The inspectors also verified that condition reports were generated for drill performance problems of significance and entered into the corrective action program with the appropriate characterization and significance.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification
Cornerstone: Barrier Integrity
.1 Reactor Coolant System Leakage
a. Inspection Scope
The inspectors verified the Reactor Coolant System (RCS) Leakage Performance Indicator for both units. The inspectors reviewed a sample of operating logs and the results of RCS water inventory balance calculations performed from July 1, 2004, through June 30, 2006, and verified the licensee's calculation of RCS leakage for both units.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
.1 Routine Review of Identification and Resolution of Problems
a. Inspection Scope
As discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensee's corrective action system at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Some minor issues were entered into the licensee's corrective action system as a result of inspectors' observations but are not discussed in this report.
b. Findings
No findings of significance were identified.
.2 Annual Sample Review
a. Inspection Scope
The inspectors completed two annual review samples by selecting the following condition reports for in-depth review:
C CR 06117010, "Inadvertent Safety Injection Occurred on Unit 2 While Performing 2-IHP-4030-STP-180" C
CR 06112038, "2CD Fuel Injection Pump Seizures" The inspectors verified the following attributes during their review of the licensee's evaluations and corrective actions for the above condition reports:
C complete and accurate identification of the problem in a timely manner commensurate with its safety significance and ease of discovery; C
consideration of the extent of condition, generic implications, common cause and previous occurrences; C
evaluation and disposition of operability/reportability issues; C
classification and prioritization of the resolution of the problem, commensurate with safety significance; C
identification of the root and contributing causes of the problem; and C
identification of corrective actions which were appropriately focused to correct the problem.
b. Findings
No findings of significance were identified.
4OA3 Event Followup
.1 Actions to Address Unit 1 Lower Containment High Temperatures/Plant Shutdown as
Required by TS
a. Inspection Scope
On the evening of July 29, 2006, operators identified that Unit 1 lower containment air temperature had exceeded the 120EF limit of TS 3.6.5, Condition 'A.' The licensee subsequently performed a reactor shutdown on July 30th to comply with the TS action requirement. Very warm Lake Michigan water temperatures (over 80EF for many days)and warm ambient temperatures (upper 80's and lower 90's) created a problem for cooling the Containment Building, which utilizes non-essential service water to provide cooling to air coolers in the Containment Building. The inspectors reviewed the licensee's actions to address the elevated lower containment temperatures and observed portions of the reactor shutdown from the Control Room. The inspectors also verified that the licensee completed an 4-hour notification of the plant shutdown to the NRC Operations Center as required by 10 CFR 50.72(b)(2)(I).
b. Findings
No findings of significance were identified.
.2 Actions to Address Unit 2 Lower Containment High Temperatures
a. Inspection Scope
During late July and early August 2006, the inspectors reviewed the licensee's actions to address elevated lower containment temperatures in Unit 2. The licensee shut down Unit 1 on July 30th because operators identified that the 120EF lower containment air temperature limit of TS 3.6.5, Condition 'A' had been exceeded. The average lower containment temperature for Unit 2 had been tracking only 4 - 5EF below that of Unit 1 and was very near the 120EF limit. The licensee installed a temporary modification to provide supplemental cooling to the lower containment air coolers while concurrently exploring other possible solutions.
b. Findings
No findings of significance were identified.
.3 (Closed) Licensee Event Report (LER) 05000316/2006-005-00:
"Failure to Comply with TS Surveillance Requirement 3.6.1.1." The licensee failed to perform an as-found local leak rate test for containment isolation valve 2-SI-189 (emergency core cooling system safety valves discharge to the primary relief tank containment isolation check valve) prior to performing maintenance that affected the valve's leak tightness as required by the plant's TS. Although the licensee promptly recognized the failure to complete an as-found local leak rate test for 2-SI-189, the inspectors identified that the licensee did not recognize and correctly evaluate this as a failure to comply with TS Surveillance Requirement (SR) 3.6.1.1. Two findings, a Non-Cited Violation of TS SR 3.6.1.1 and a Severity Level IV Non-Cited Violation of 10 CFR 50.73(a)(1), were documented in NRC Inspection Report 05000315/316/20060004. The licensee reported this as a condition prohibited by the plant's TS in accordance with 10 CFR 50.73(a)(2)(i)(B). The inspectors determined that the information provided in LER 05000316/2006-005-00 did not raise any new issues or change the conclusion of the initial review. This LER is closed.
.4 (Closed) LER 05000316/2006-03-00:
"Inadvertent Emergency Core Cooling System Actuation During Testing." On April 27, 2006, with Unit 2 in Mode 5, an inadvertent main steam line low pressure safety injection actuation signal occurred on both trains during surveillance testing. All plant safety equipment operated as expected; however, there was no actual injection into the RCS due to the low temperature over-pressure protection system alignment in effect. The root cause of the inadvertent safety injection actuation was instrument maintenance personnel not following the licensee's requirements for procedure use and adherence when using the bypass function to clear the standing reactor trip signals during testing. The inspectors verified that the licensee completed an 8-hour notification of this event to the NRC Operations Center as required by 10 CFR 50.72(b)(3)(iv)(A).
As a prerequisite to the surveillance test, instrument maintenance technicians needed to clear existing reactor trip signals. An instrument maintenance supervisor decided to use a Job Order Activity to bypass existing reactor trip signals by utilizing a newly installed bypass switch in the reactor protection system in lieu of using the applicable surveillance test procedure attachment. The use of a Job Order Activity to perform this task was not allowed by the licensee's procedure use and adherence procedure. The bypass switch had just been installed by a plant modification and operations personnel were not yet trained on its function. As a result, plant operators did not prevent the Job Order Activity from being issued. Knowledge weaknesses by the instrument maintenance supervisor on how the bypass switch functioned also contributed to this event.
Additionally, during the post-event review, the licensee identified that the pressurizer surge line temperature changed about 200EF over a short period of time during the transient. The licensee evaluated this condition as acceptable for continued operation.
The inspectors noted that the licensee appropriately accounted for this incremental increase in pressurizer surge line fatigue stress in accordance with TS 5.5.4.
The inspectors reviewed the licensee's root cause evaluation, the engineering evaluation of the pressurizer surge line temperature transient, and corrective actions. The inspectors concluded that this event was a performance deficiency since instrument maintenance personnel failed to follow the surveillance test procedure, which is a procedure required by TS 5.4.1.a and Regulatory Guide 1.33, Appendix A, Revision 2.
The inspectors concluded that this violation of TS 5.4.1.a constitutes a violation of minor significance and is not subject to formal enforcement action in accordance with Section IV of the NRC's Enforcement Policy. This finding was of minor significance because there was no adverse consequence to the plant due to the Mode 5 low temperature over-pressure protection system alignment in effect during the testing. The licensee reported this event as a valid actuation of the containment isolation, emergency core cooling system, and emergency alternating current electrical power systems in accordance with 10 CFR 50.73(a)(2)(iv)(A). This LER is closed.
.5 (Closed) LER 05000316/2006-004-00:
"Failure to Comply With TS 3.8.2, AC Sources -
Shutdown, LCO [Limiting Condition for Operation] 3.8.2.b." On May 1, 2006, with Unit 2 in Mode 5, Cold Shutdown, it was determined that TS 3.8.2.b, which required one EDG to be operable, had not been met for two separate occasions totaling 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and 32 minutes between April 21 and April 22, 2006.
On April 21, 2006, the Unit 2 CD EDG was declared operable after testing activities were completed following planned maintenance to replace fuel injector pumps with new pumps. Between April 21st and 22nd, the Unit 2 AB EDG was inoperable for a total 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and 32 minutes for planned testing. Subsequently, on April 22nd, three fuel injector pumps seized during additional testing activities on the CD EDG because foreign material caused mechanical binding. Consequently, the CD EDG was considered inoperable back to the time that the fuel injector pumps had been replaced. As a result, both Unit 2 EDGs were inoperable during the 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and 32 minutes that the AB EDG was inoperable on April 21st and 22nd. The licensee reported this as a condition prohibited by the plant's TS in accordance with 10 CFR 50.73(a)(2)(i)(B) and as an event that could have prevented the removal of residual heat in accordance with 10 CFR 50.73(a)(2)(v)(B).
The inspectors reviewed the circumstances that led to this event and did not identify any licensee performance deficiencies. Testing activities after the fuel injector pumps were replaced on the CD EDG were considered reasonable for the work scope. Also, licensee personnel had previously implemented reasonable corrective actions to address operating experience regarding fuel injector pump failures due to foreign material introduced during the fabrication process, which required the vendor to perform an 8-hour bench test of the new fuel injector pumps prior to shipping them to the licensee. However, as noted in the licensee's root cause evaluation, this time the foreign material was introduced by the vendor during bench testing.
Technical Specification 3.8.2.b, Condition B, required actions when the one required EDG was inoperable were to immediately: suspend core alterations, suspend movement of irradiated fuel assemblies, suspend operations involving positive reactivity additions, and initiate action to restore the required EDG to operable status. During the time that both EDGs were inoperable, no core alterations were in progress, irradiated fuel assemblies were not being moved, and no evolutions to add positive reactivity were in progress. Also, because this issue was identified after the AB EDG was in an operable status, compliance with the TS requirements was restored.
The inspectors noted that during the time both EDGs were inoperable, the AB EDG was available to satisfy the safety function to power residual heat removal equipment, if needed, except for a brief period. In accordance with plant procedures, the AB EDG lockout relay was tripped to conduct cylinder leak checks prior to testing. This evolution rendered the EDG unavailable for approximately 10 minutes on April 21st, when conducted in a controlled fashion. During the evolution, plant operators were stationed in the EDG room and in communication with operators in the Control Room.
Consequently, if the EDG were needed, operators could suspend cylinder leak checks and reset the lockout relay to restore the EDG to an available status. Licensee personnel indicated that restoration from the cylinder leak checks could be accomplished in approximately 3 minutes by the operators if the EDG was needed.
The inspectors concluded that this violation of TS 3.8.2.b, Condition B, constitutes a violation of minor significance and is not subject to formal enforcement action in accordance with Section IV of the NRC's Enforcement Policy. The licensee entered this violation into its corrective action program as CR 06121035. This LER is closed.
4OA5 Other Activities
.1 Reactor Vessel Head Replacement
a. Inspection Scope
From September 5, 2006, through September 14, 2006, inspectors performed an on-site review of fabrication and pre-service records related to replacement of the Unit 1 reactor pressure vessel head in accordance with Section 02.03 and Step 02.05(e) of Inspection Procedure 71007 "Reactor Vessel Head Replacement Inspection." This review was performed to determine if the fabrication of the vessel head was completed in accordance with Section III of the American Society for Mechanical Engineers (ASME)
Code, 1995 Edition through 1996 Addenda and to determine if pre-service nondestructive examinations (NDE) were completed in accordance with Section XI of the ASME Code1989 Edition No Addenda. Specifically, the inspectors reviewed samples of the following records:
C Fabrication process sheets, fabrication drawings, and NDE records to determine if the manufacturing process included provisions for NDE as required by the construction Code; C
NDE records and procedures used for pre-service and fabrication examinations to determine if Code qualified examinations were completed and examination results met Code acceptance criteria; C
Weld data sheets, weld procedures, and weld procedure qualification records, to determine if Code qualified weld procedures were used in fabrication of the J-groove welds, control rod drive housing mechanism (CRDM) flange-to-adaptor sleeve welds and head cladding welds; C
Certified Material Test Reports for materials used in fabrication of the reactor vessel head including weld materials to determine if appropriate chemical, mechanical tests and heat treatment records existed to meet material and Code specifications; C
Non-conformance reports issued by the licensees fabricator and subcontractors to determine if fabrication related deviations were appropriately tracked, evaluated and resolved; and C
Audit records of the head fabricator and subcontractors associated with welding activities and NDE to determine if these activities had been properly controlled in accordance with the contract specifications or Code requirements.
The records reviewed by the inspectors are identified in the attachment to this report.
b.
Finding No findings of significance were identified.
.2 Verification of Reactor Vessel Head Lift Commitments
a. Inspection Scope
The inspectors verified the licensee's commitments and plans for lifting the reactor vessel head from the vessel and setting it on a stand in the Containment Building to provide reasonable assurance of safety in response to NRC staff concerns identified with the licensee's reactor head drop analysis. The licensee's commitments included a limitation on lift height, flooding of the reactor cavity while lifting the head, various administrative controls, and other compensatory measures. As part of this verification, the inspectors interviewed operations and engineering staff, attended the licensee's pre-job briefing, and directly observed the reactor vessel head lift activities. Docketed correspondence between the NRC staff and the licensee regarding the reactor vessel head lift commitments is referenced in the Documents Reviewed section at the end of this report.
b. Findings
No findings of significance were identified.
.3 Mitigating Systems Performance Index Verification (TI 2515/169)
a. Inspection Scope
On June 12, 2006, the NRC issued Regulatory Issue Summary 2006-07, "Changes to the Safety system Unavailability Performance Indicators." The purpose of this Regulatory Issue Summary (RIS) was to inform licensees that beginning on April 1, 2006, the agency replaced the Safety System Unavailability (SSU) performance indicators (PI) with the Mitigating Systems Performance Index (MSPI). The RIS and Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator Guideline," provided guidance for calculating and submitting MSPI data to the NRC.
The NRC inspection program is implemented within the framework of the Reactor Oversight Process (ROP). The performance indicators and inspection findings provide the two major inputs into the assessment of licensee performance under the ROP. The MSPI monitors the unavailability and the unreliability of the same four safety systems that comprise the SSU. It also monitors the cooling water support systems for those four safety systems. For pressurized water reactors, these systems include:
- (1) Emergency Alternating Current
- (2) High Pressure Injection
- (5) Cooling Water Support (Emergency Service Water and Component Cooling Water)
The objective of Temporary Instruction (TI) 2515/169, "Mitigating Systems Performance Index Verification," was to validate the unavailability and unreliability input data and to verify accuracy of the first reporting results for the 2006 second quarter. During the week of August 14, 2006, the inspectors reviewed the licensee's MSPI data and supporting documentation. The results of the inspectors' review included documenting observations and conclusions in response to the questions identified in TI 2515/169.
b.
Observations Summary The inspectors did not identify any significant discrepancies based upon validation of the unavailability and unreliability input data, and verification of accuracy of the 2006 second quarter MSPI results.
Evaluation of Inspection Requirements In accordance with the requirements of TI 2515/169, the inspectors evaluated and answered the following questions:
1. For the sample selected, did the licensee accurately document the baseline
planned unavailability hours for the MSPI systems?
Yes. The licensee accurately documented the baseline planned unavailability hours for the MSPI systems in accordance with the prescribed method outlined in NEI 99-02, Revision 4.
2. For the sample selected, did the licensee accurately document the actual
unavailability hours for the MSPI systems?
Yes. The licensee accurately documented the actual unavailability hours for the MSPI systems in accordance with the prescribed method outlined in NEI 99-02, Revision 4.
3. For the sample selected, did the licensee accurately document the actual
unreliability information for each MSPI monitored component?
Yes. The licensee accurately documented the actual unreliability information for each MSPI monitored component in accordance with the guidance outlined in NEI 99-02, Revision 4.
4. Did the inspectors identify significant errors in the reported data, which resulted
in a change to the indicated index color? Describe the actual condition and corrective actions taken by the licensee, including the date when the revised PI information was submitted to the NRC.
No. The inspectors did not identify significant errors in the reported data that resulted in a change to the indicated index color.
5. Did the inspectors identify significant discrepancies in the basis document which
resulted in:
- (1) a change to the system boundary,
- (2) an addition of a monitored component, or
- (3) a change in the reported index color? Describe the actual condition and corrective actions taken by the licensee, including the date of when the bases document was revised.
No. The inspectors did not identify significant discrepancies in the basis document that resulted in either:
- (1) a change to the system boundary,
- (2) an addition of a monitored component, or
- (3) a change in the reported index color.
c. Findings
No findings of significance were identified.
4OA6 Meetings
.1 Resident Inspectors' Exit Meeting
The inspectors presented the inspection results to Mr. J. Jensen and other members of the licensee's staff at the conclusion of the inspection on September 27, 2006. 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.
.2 Interim Exit Meetings
Interim exits were conducted for:
C Maintenance Effectiveness Periodic Evaluation with Mr. J. Jensen and other members of licensee management on July 21, 2006.
C Reactor Vessel Head Replacement Fabrication Review (IP 71007) with Mr. D. Fadel and other members of the licensee's staff on September 14, 2006, and final phone exit meeting on September 21, 2006. The licensee confirmed that none of the potential report input discussed was considered proprietary.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- L. Bush, Site Senior License Holder
- P. Carteaux, Emergency Preparedness Manager
- T. Craven, System Engineering
- J. Eaton, Maintenance Rule Program Engineer
- H. Etheridge, Regulatory Affairs Specialist
- D. Fadel, Design Engineering Director
- J. Gebbie, Plant Engineering Director
- C. Graffenius, Emergency Preparedness Coordinator
- J. Jensen, Support Services Vice President
- J. Kingseed, RVCH Project
- Q. Lies, Operations Manager
- R. Meister, Regulatory Affairs Specialist
- M. Peifer, Site Vice President
- S. Simpson, Regulatory Affairs Manager
- W. Wah, System Engineering
- L. Weber, Plant Manager
- V. Woods, Performance Assurance Manager
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
- 05000315/2006006-01 URI Incomplete Maintenance Rule Evaluations for Nuclear
- 05000316/2006006-01 Instrumentation Component Failures (Section 1R12.b.1)
Closed
- 05000316/2006-005-00 LER Failure to Comply with TS Surveillance Requirement 3.6.1.1 (Section 4OA3.3)
- 05000316/2006-003-00 LER Inadvertent Emergency Core Cooling System Actuation During Testing (Section 4OA3.4)
- 05000316/2006-004-00 LER Failure to Comply With TS 3.8.2, AC Sources - Shutdown, LCO 3.8.2.b (Section 4OA3.5)
- 05000315/2515/169 TI Mitigating Systems Performance Index Verification
- 05000316/2515/169 (Section 4OA5.3)
Discussed
- 05000316/2006004-06 NCV Failure to Perform As-found Local Leak Rate Testing for a Containment Isolation Valve (Section 4OA3.3)
- 05000316/2006004-07 NCV Failure to Submit a Required Licensee Event Report (Section 4OA3.3)