IR 05000445/2005009

IR 05000445-05-009 and 05000446-05-009; 07/05/05 - 07/29/05; Comanche Peak Steam Electric Station, Units 1 & 2; Biennial Baseline Inspection of the Identification and Resolution of Problems

ML052550636
Person / Time
Site:	Comanche Peak
Issue date:	09/12/2005
From:	Laura Smith Division of Reactor Safety IV
To:	Blevins M TXU Power
References
IR-05-009
Download: ML052550636 (43)

Text

ber 12, 2005

SUBJECT:

TXU GENERATION COMPANY LP COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 AND 2 -- NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000445/2005009 and 05000446/2005009

Dear Mr. Blevins:

On July 29, 2005, the Nuclear Regulatory Commission (NRC) completed a team inspection at your Comanche Peak Steam Electric Station. The enclosed report presents the results of this inspection. On July 29, 2005, we discussed the inspection results with you and other members of your staff.

This inspection examined activities conducted under your license as they relate to the identification and resolution of problems, compliance with the Commissions rules and regulations and with the conditions of your license. The team reviewed approximately 150 risk important issues, apparent and root cause analyses, and other related documents. In addition, the team reviewed cross-cutting aspects of NRC and licensee-identified findings and interviewed personnel regarding the safety-conscious work environment.

On the basis of the sample selected for review, the team concluded that your processes to identify, prioritize, evaluate, and correct problems were generally effective; thresholds for identifying issues remained appropriately low and, in most cases, corrective actions were adequate to address conditions adverse to quality. The team concluded that a positive safety-conscious work environment existed at Comanche Peak Steam Electric Station.

The report documents one finding concerning inadequate corrective actions to address longstanding Agastat relay issues which resulted in the inoperability of a 6.9 kV safeguards bus.

This finding has potential safety significance greater than very low significance. This finding did not present an immediate safety concern because the licensee has replaced, at the time of the exit meeting, 192 of 210 safety related relays in the plant. The team reviewed the function and compensatory measures in place for those relays that had not been replaced and deemed them to be adequate until long-term corrective measures have been implemented. In addition, the report also documents two findings that were evaluated under the risk significance

TXU Power -2-determination process as having very low safety significance (Green). The NRC determined that a violation was associated with one of these findings. The violation is being treated as a noncited violation because it was of very low safety significance and because it has been entered into your corrective action program consistent with Section VI.A of the Enforcement Policy. If you contest the violation or the significance of the noncited violation, you should provide a response within 30 days of the date of the inspection report, with the basis for your denial, to the U.S. Nuclear Regulator Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Comanche Peak Steam Electric Station.

In accordance with 10 CFR 2.390 of the NRC's Rules of Practice, a copy of this letter, its enclosure, and your response will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records 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).

Sincerely,

//RA//

Linda Joy Smith, Chief Engineering Branch 2 Division of Reactor Safety Dockets: 50-445 50-446 Licenses: NPF-87 NPF-89

Enclosure:

Inspection Report 05000445/2005009; 05000446/2005009 w/Attachment: Supplemental Information

REGION IV==

Docket: 50-445, 50-446 License: NPF-87, NPF-89 Report: 05000445/2005009 and 05000446/2005009 Licensee: TXU Power Facility: Comanche Peak Steam Electric Station, Units 1 and 2 Location: FM-56, Glen Rose, Texas Dates: July 5 through July 29, 2005 Inspectors: M. Peck, Senior Resident Inspector D. Allen, Senior Resident Inspector B. Tindell, Reactor Inspector J. Groom, Reactor Inspector A. Barrett, Resident Inspector D. Livermore, Reactor Inspector Approved By: L. Smith, Chief Engineering Branch 2 Division of Reactor Safety Enclosure

SUMMARY OF FINDINGS

IR 05000445/2005009 and 05000446/2005009; 7/05/05 - 7/29/05; Comanche Peak Steam

Electric Station, Units 1 & 2; Biennial baseline inspection of the identification and resolution of problems, prioritization and evaluation of issues, and effectiveness of corrective actions.

This report documents the biennial assessment of identification and resolution of problems conducted by two senior resident inspectors, one resident inspector, and three reactor inspectors. Three findings were identified during the inspection: two Green findings of very low safety significance, one of which was classified as a noncited violation, and one finding, which was unresolved for pending completion of inspection necessary to determine the significance.

The findings were evaluated using the significance determination process. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. 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. Identification and Resolution of Problems

• The team reviewed 151 risk significant issues, apparent and root cause analyses, and other related documents, to assess the effectiveness of the licensee's problem identification and resolution processes and systems. The team concluded that the licensee's management systems were generally effective. However, the team identified poor evaluation, prioritization, and corrective actions associated with longstanding safety related Agastat relay problems. A similar performance concern was documented in the last problem identification and resolution assessment. The team also concluded that licensee corrective actions taken to address an historical adverse trend in human performance have not been effective.

The team concluded that the licensee established a safety-conscious work environment at Comanche Peak Steam Electric Station. The team determined that employees and contractors felt free to enter issues into the corrective action program and raise safety concerns to their supervision, to the employees concern program, and to the NRC. All plant personnel, interviewed by the team, stated that potential safety issues were addressed by the licensee. However, the licensee had identified long-term organizational effectiveness issues within the operations department, which continued to challenge the safety-conscious work environment for shift operations personnel. The team concluded that licensee's past actions to improve operations department organizational effectiveness had not been fully effective.

Cornerstone: Mitigating System

• (TBD) The team identified a finding and an unresolved item related to Technical Specification 3.8.1 and 10 CFR 50, Appendix B, Corrective Action, after neither the alternate nor emergency power was supplied to a 6.9 kV safeguards bus within the time assumed in the accident analysis. On October 19, 2004, an unplanned loss of the preferred offsite power caused the Unit 2, Train B, 6.9 kV safeguards bus to deenergize.

A degraded Agastat relay delayed the normal power supply breaker from opening for 30 seconds. Both the emergency diesel generator and the alternate offsite AC power supplies were prevented from powering the bus due to a breaker interlock with the normal supply. This delay rendered both the emergency diesel generator and the alternate offsite AC power supplies inoperable. The 30 second delay in providing power to the safeguards bus would have resulted in the station not meeting the 10 CFR 50,

Appendix K, Emergency Core Cooling System Evaluation Models Acceptance Criteria, for that equipment train if a design bases loss of coolant accident had occurred. The licensee had a previous opportunity to correct the degraded Agastat relay issues. On October 7, 2002, the emergency diesel generator unexpectedly started due to a degraded Agastat relay. The licensee concluded that the failure could have been caused by aging and formed a corrective action plan to replace all safety related Agastat relays that have been in service for greater than the licensee established 12-year lifetime. The relay that failed in October 2004 was 16 years old.

This finding adversely impacted the reliability of emergency power to mitigating systems.

This finding is greater than minor because the reactor mitigating systems cornerstone and the equipment performance attribute to prevent core damage were affected. The licensee's failure to identify the cause and implement corrective actions to prevent repetitive failures of safety related Agastat relays was a performance deficiency. The inspectors determined that the finding had potential safety significance greater than very low because the condition represents an actual loss of a safety function for a single train greater that Technical Specification allowed outage time. This is an unresolved item pending completion of inspection required to bound the performance deficiency and determine the significance (Section 4OA2).

• (Green) A noncited violation of Technical Specification 3.3.2 was identified after the licensee failed to place an inoperable containment pressure channel isolation function in trip within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. While operating in Mode 1 on August 5, 2004, a control room containment pressure channel deviation alarm occurred. The licensee failed to recognize that the channel was inoperable. On August 6, 2004, the licensee identified that a grounded transmitter shield wire had caused the channel deviation alarm. Using a Channel Statistical Allowance analysis the licensee determined that the pressure channel became inoperable at the time of the alarm. The channel was inoperable for a total of 31 hours3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br />.

This finding is greater than minor because, if left uncorrected, the failure to recognize inoperable mitigating systems instrumentation would become a more significant safety concern. This finding is only of very low safety significance because the condition was not a design or qualification deficiency confirmed to result in loss of function per Generic Letter 91-18; did not result in an actual loss of safety function of a system; did not increase the likelihood of a fire; and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. This finding involved the failure of operations personnel to implement a Technical Specification action requirement and was associated with the crosscutting area of human performance. The licensee entered this condition into their corrective action program (SMF-2005-002752 and SMF-2005-003157) (Section 4OA2).

Cornerstone: Barrier Integrity

• (Green) A self-revealing finding associated with inadequate postmodification testing of the Unit 2 refueling machine festoon was identified. The festoon failed during refueling operations, resulting in the introduction of loose parts into the lower internals storage area of the refueling cavity.

The licensee installed the festoon during Refueling Outage 5 to replace the older take-up reel on the refueling machine, however the festoon rails were not adequate to allow bridge travel to the mechanical stops. When the bridge was operated beyond the length of the festoon rails, the cable trolleys became compacted and enough stress was placed on the tow rods to break the welds of the base plates holding the rods in place. The postmodification test only verified festoon clearance for bridge travel to the electrical bridge stops.

Failure of the licensee to perform a postmodification test that demonstrated that the festoon would perform satisfactorily in service was a performance deficiency. This finding is more than minor because the barrier integrity cornerstone objective to provide reasonable assurance that physical barriers (including the fuel clad) to protect the public from radionuclide releases caused by accidents or events is affected. The introduction of loose parts into the reactor cavity during refueling is associated with the fuel clad attributes of human performance and foreign material exclusion. The team analyzed the finding using Appendix G, Shutdown Operations, of Manual Chapter 0609,

Significance Determination Process, Attachment 1, Checklist 4. The team concluded that the finding did not require a quantitative assessment because the condition does not increase the likelihood of a loss of reactor coolant system inventory or loss of reactor coolant system level instrumentation, does not degrade the licensee's ability to terminate a leak path or add reactor coolant system inventory when needed, and does not degrade the ability to recover decay heat removal once it is lost. Since a quantitative assessment was not required, the finding was of very low safety significance (Section 4OA2).

Licensee-Identified Violations

None.

REPORT DETAILS

4OA2 Identification and Resolution of Problems

An inspection team completed the biennial assessment of the effectiveness of the TXU Generation Companys management systems to identify and resolve problems at the Comanche Peak Steam Electric Station (CPSES). The assessment focused on the twenty-eight month period since the previous NRC biennial assessment (February 1, 2003 through May 1, 2005). The team performed the assessment based on an independent inspection of the licensees evaluation and disposition of 151 risk significant issues that occurred during the assessment period. The inspection scope included 11 NRC findings; 19 licensee event reports; 76 significant conditions adverse to quality; independent and external audits and assessment reports; radiation protection and security logs; items generated or addressed by the plant safety review committees; adverse trends in configuration control, human performance, and corrective action programs; and maintenance preventable functional failures that occurred during the period. Performance deficiencies that occurred during the 28 month period since the previous assessment will be referred to as current.

The team expanded the inspection scope to include the past five years for selected longstanding risk significant issues with performance deficiencies that occurred prior to the assessment period. The team used the expanded inspection scope to identify historical performance trends. Performance deficiencies which occurred prior to the current assessment period, will be referred to as historical. The assessment samples included issues representing all seven safety cornerstones.

a. Effectiveness of Problem Identification

(1) Inspection Scope The inspectors reviewed 151 risk significant issues to determine if the licensee properly identified, characterized, and entered plant problems into the corrective action program.

The team performed selected equipment walkdowns, reviewed operator, radiation protection, and security logs, work orders, plant tracking logs, and action requests for equipment deficiencies to verify that problems and issues were captured in the corrective action program (CAP). The team reviewed the audits, self-assessments, and system health reports listed in the attachment. The team conducted interviews of station personnel and evaluated corrective action documentation to determine if the licensee established the proper threshold for identifying and documenting problems in the CAP. In addition, the team reviewed the licensees evaluation of selected industry experience information, including operating event reports, NRC Generic Letters, Bulletins, Information Notices, and generic vendor notifications to assess if issues applicable to CPSES were appropriately addressed.

(2) Assessment The team concluded that the licensee effectively identified, characterized, and entered problems at CPSES. The licensee established a low threshold for entering items into the CAP. The licensee entered over 6,000 issues into the CAP during the 28 month assessment period. The team concluded that all of the licensee personnel interviewed clearly understood the licensees expectation for CAP thresholds. The current team identified three examples of poor problem identification that occurred during the assessment period:

Example 1: Loose Parts in the Reactor Cavity During Refueling Operations During prior operation with the electrical stops bypassed, the licensee had several opportunities to identify problems with the refueling machine festoon.

The refueling machine festoon lacked sufficient length to accommodate full refueling bridge travel beyond the electrical stops to the mechanical stops.

Damage to the festoon tow bar and brace occurred during fuel handling operations beyond the electrical stops. Some of these damaged, loose parts dropped into the reactor cavity. This issue was discussed as a finding in section 4OA2e(2)(ii) of this report.

Example 2: Relief Request Issues The NRC identified that the licensee failed to fully comply with an NRC-approved relief request from Section XI of the ASME Code. The licensee had not implemented portions of the alternative process requiring periodic reassessment as committed in the relief request. The licensee should have identified a formal method to perform and document this assessment (NRC NCV 05000445;05000446/2004008-002).

Example 3: Failure to Promptly Initiate a SmartForm (SMF) Following a Reactivity Event A unit supervisor did not promptly document a reactivity event in the CAP. The unit supervisor defeated a Tavg loop rod control input which resulted in unplanned control rod movement. The Unit 2 supervisor's action was not consistent with operations department expectations and represented a human performance issue. The licensee entered the condition into the CAP (SMF-2005-002499)fours days after the event. The inspectors concluded that this condition was a minor finding.

b. Prioritization and Evaluation of Issues

(1) Inspection Scope The team reviewed 76 Category 1 and 2 SmartForm reports (significant conditions adverse to quality) and 13 root cause evaluations to assess the licensees ability to evaluate adverse conditions, determine the full extent of conditions, generic implications, common causes, and to properly prioritize issues. The team also observed management oversight of significant conditions adverse to quality at CAP meetings and reviewed operability evaluations. The team reviewed licensee evaluations of selected industry operating experience information, including NRC Information Notices and industry provided information, to assess whether issues applicable to CPSES were appropriately addressed. In addition, the team performed a five year historical review of SmartForm reports addressing operability evaluations, an adverse trend in human performance, and Agastat relay problems to determine if the licensee had appropriately addressed longstanding issues.

(2) Assessment The team concluded that the licensee's problem prioritization and evaluation processes were effective and conducted in accordance with CAP and NRC requirements. The licensee was generally self-critical and thorough in evaluating the causes of significant conditions adverse to quality for most of the problems sampled by the team. The team identified five examples of inadequate problem prioritization and evaluation.

Example 1: Agastat Relay Issues The team identified that the licensees prioritization and evaluation of the longstanding Agastat relay issues were inadequate. The team assessed both the licensee's current and historical management effectiveness. This issue was discussed as a finding in section 4OA2e(2)(i) of this report.

Untimely Corrective Action Plans - Historical As discussed in NRC Problem Identification and Resolution Inspection Report 05000445/2003-006; 05000446/2003-006, the 2003 team noted that Smart Form 2002-003391 was still open (in the planning stage) and that many corrective actions were not yet scheduled. The potential aging issue was initially identified on April 18, 2002, in Smart Form 2002-001504, however, a root-cause analysis was not developed until the unexpected EDG start occurred on October 7, 2002, and an operational evaluation was not developed until a low grid response time was revealed during testing on the 480V buses on October 16, 2002. Based on this information, the 2003 team concluded that the licensees corrective actions, while adequate, were not timely.

Inadequate Extent of Condition - Historical As discussed in NRC Problem Identification and Resolution Inspection Report 05000445/2003-006; 05000446/2003-006, the licensee determined that there was no program to periodically replace Agastat relays prior to them exceeding their life expectancy. As a result of this determination, the licensee developed preventative maintenance tasks to periodically replace these relays (at this time on a manufacturer recommended 10-year life expectancy basis) and any other Agastat relays involved with 6.9kV bus transfers before their operating life was exceeded. The 2003 team noted that the licensee did not expand these corrective actions to include any other systems that used these relays.

Inadequate Assessment of Setpoint Drift - Current As discussed in NRC Problem Identification and Resolution Inspection Report 05000445/2003-006; 05000446/2003-00, the licensee identified the main effect of aging on Agastat relays was an increase in setpoint drift with a maximum drift of + 18 percent. The licensee determined that a setpoint drift of +

18 percent would not prevent the relays from completing their intended tasks and the 2003 team agreed. However, an Agastat relay that failed in October 2004 exhibited setpoint drift in excess of the + 18 percent maximum identified by the licensee. The relay was observed to operate in 30 seconds instead of the required

.5 seconds and resulted in the relay not completing its intended task.

The team noted the licensees inaccurate assessment of setpoint drift as an example of inadequate problem evaluation.

Ineffective Failure Analysis for October 7, 2002 Event - Current As discussed in NRC Problem Identification and Resolution Inspection Report 05000445/2003-006; 05000446/2003-006, an emergency diesel generator unexpectedly started due to a faulty Agastat relay (SMF-2002-003391). The licensee determined that the relay failures could have been caused by aging and developed plans to replace the relays. However, the team noted that the failed relay was discarded and the exact failure mechanism was not determined. A subsequent analysis of a failed Agastat relay in October 2004 revealed the presence of foreign material within the relay timing mechanism.

The presence of foreign material suggests flaws in the licensees determination that aging was the failure mechanism for previous relays and was identified by the team as an example of inadequate problem evaluation.

Example 2: Poor Prioritization for Degraded Equipment The licensee did not effectively ensure timely prioritization and evaluation of all degraded equipment. The team reviewed four examples of longstanding degraded equipment issues which were not corrected and/or the corrective action delay was not justified. The team used guidance provided in Generic Letter 91-18, Resolution of Degraded and Nonconforming Conditions as the bases for acceptability. Generic Letter 91-18 stated: If the licensee does not resolve the degraded or nonconforming condition at the first available opportunity or does not appropriately justify a longer completion schedule, the staff would conclude that corrective action has not been timely and would consider taking enforcement action. Three of the degraded conditions had not been corrected at the time of this inspection. While all of the degraded equipment remained operable, the licensees problem prioritization process was not consistent with Generic Letter 91-18. The inspectors concluded that each example of longstanding degraded equipment issues was minor.

S Failure to Meet the Diesel Generator Room Temperature Licensing Bases - Current During 1999, the licensee identified that the licensing bases requirement to maintain minimum diesel generator room temperatures with the heating and ventilation system could not be met (SMF-1999-000248).

The licensee evaluated the condition using Generic Letter 91-18. The licensee concluded that the diesel generator support equipment was operable but degraded. The licensee ensured that appropriate compensatory actions were in place. The team concluded that the corrective action delay was not appropriately justified. The degraded condition had not been corrected at the time of this inspection.

S Degraded Atmospheric Relief Block Valves - Current During 2003, the licensee identified that the licensing bases requirement to maintain the atmospheric relief block valves as safety-related and seismic Category I was not met (SMF-2003-000188). The licensee evaluated the condition using Generic Letter 91-18. The licensee concluded that the atmospheric relief valve block valves were operable but degraded. The licensees corrective actions included planned modifications to bring the valves into full compliance. However, the licensee had not corrected the degraded condition at the time of the inspection nor provided an appropriate justification for the delay. The team concluded that the corrective action delay was not appropriately justified. The licensee entered this issue into the CAP as SMF-2005-001756.

S Degraded Primary Plant Ventilation Exhaust Fans - Current During 2003, the licensee identified that the licensing bases requirements for the primary plant ventilation exhaust fan instrument tubing were not in compliance with design bases seismic requirements (SMF-2003-002423).

The licensee evaluated the condition using Generic Letter 91-18. The licensee concluded that the ventilation exhaust fans were operable but degraded. However, the licensee had not corrected the degraded condition at the time of the inspection nor provided a justification for the delay. The team concluded that the licensee did not provided an appropriate justification for the corrective action delay.

S Failure to Meet the Electrical Area Ventilation System Room Temperature Licensing Bases Requirements - Historical During 1999, the licensee identified that the licensing bases requirement to maintain minimum electrical area ventilation system room temperature could not be met (SMF-1999-003133). The licensee evaluated the condition using Generic Letter 91-18. The licensee concluded that the electrical area ventilation system equipment was operable but degraded.

The licensee ensured that appropriate compensatory measures were in place. The licensee completed a corrective action plan in 2002.

However, the corrective action plan did not include a completion date.

The degraded condition was corrected during 2003. Generic Letter 91-18 stated: The licensee must establish a time frame for completion of corrective action. The team concluded that the corrective action delay was not appropriately justified.

Example 3: Inadequate Evaluation Following a Reactor Trip The team concluded that the licensees problem evaluation following a July 2003 reactor trip was less than adequate. The reactor trip was directly caused by a failed reactor coolant pump (RCP) motor. The outside motor stator windings, located next to the rotor, had faulted. The RCP had exhibited high vibration during the year prior to the failure. The root cause analysis did not fully consider the high vibration or failure to fully implement pump vendor recommendations as contributing factors to the event.

Specifically, in May 2002, the licensee replaced the RCP rotor. Following a June 2002 reactor trip, RCP vibration amplitude increased by 2.5 mils (SMF-2002-002233) with greater than 18.0 mil spikes (the high vibration alarm setpoint). Vibration data (TXU Vibration Report 2002-022 and SMF-EVAL-2002-002233-01) taken after the June 2002 trip was sent to the pump vendor. The pump vendor analyzed the vibration spectrum and made several recommendations. These recommendations included:

S Balance the RCP to minimize shaft vibration levels and minimize lower motor bearing wear, S Raise the high vibration alarm setpoint to 20.0 mils, and S Trip the RCP if vibration exceeds 20.0 mils.

In response to these vendor recommendations, the licensee increased the high vibration alarm setpoint to 20.0 mils, but did not modify operating procedures to address the new vibration setpoint. They also did not balance the RCP while the plant was offline for 12 days in May 2003. During the subsequent startup RCP vibration exceeded 22.0 mils.

The RCP motor failed in July 2003 as discussed in NRC Integrated Inspection Report 05000445/2003003 and 05000446/2003003. The team concluded that the licensee's failure to trip the plant at the vendor recommended RCP vibration setpoint and the lost opportunity to balance the pump as an example of inadequate problem prioritization. While not a regulatory requirement, this issue provided insight in to the licensees problem evaluation process.

Example 4: Inadequate Problem Evaluation for a Plant Risk Assessment The team concluded that the licensees use of inappropriate failure probabilities when conducting a Technical Specification (TS) required risk assessment was an example of inadequate problem evaluation. On April 2, 2004, the licensee discovered that the last TS required surveillance on the loss of power diesel generator start instrumentation was not performed. Plant TSs required that the licensee complete the surveillance every 18 months. The licensee performed the previous surveillance during the refueling outage in the Fall of 2003. TS Surveillance Requirement 3.0.3 provided for deferral of the missed surveillance until the next refueling outage provided that the licensee assess and manage the risk impact. The licensee deferred the missed surveillance until the next refueling outage in April of 2005.

The licensee completed a risk assessment for the missed surveillance (SMF-2004-001177). The surveillance included a verification of the Agastat relay in the diesel generator start circuit. The licensee used a generic relay demand failure probability (10-4) for the Agastat relay when assessing plant risk for the deferred surveillance. The licensee had plant specific historical data indicating a higher failure probability on the order of magnitude of 10-3. While not a regulatory requirement, the scope and development level of models that are used in plant risk assessments should be sufficient to represent issue being evaluated. In this case, the question, whether or not to require testing, is related to the reliability of the Agastat relays, so the best available Agastat failure data should have been used.

Additionally, during October 2004 the Agastat relay on the diesel generator circuit of the opposite train actually failed when the circuit was challenged during a loss of offsite power event (discussed in Sections 4OA2b and 4OA2c of this report). The licensee did not reevaluate the demand failure of the Agastat in the risk assessment following the actual failure. The inspectors determined that use of the actual failure probability for the Agastat relay in the risk assessment would not have resulted in additional risk mitigation actions by the licensee and the finding was minor.

Example 5: Inadequate Evaluation Resulted in Failure to Identify a Failed Containment Pressure Channel The team concluded that the failure of shift operations personnel to recognize that a containment pressure channel was inoperable was an example of inadequate problem evaluation. On August 5, 2004, a control room containment pressure channel deviation alarm occurred. The alarm was activated when one channel deviated from the other three by greater than +0.3 psig. Control room instrumentation indicated that the channel deviated 2.0 psig from the other channels. Shift operations personnel did not consider the channel inoperable and did not apply the required TS action requirements. Subsequent review revealed that the pressure channel had been inoperable for greater than 31 hours3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br />. This issue was discussed as a finding in Section 4OA2e(2)(iii) of this report.

c. Effectiveness of Corrective Actions

(1) Inspection Scope The team reviewed licensee documentation associated with 151 significant adverse conditions and NRC findings to verify that corrective actions were properly identified and implemented in a manner commensurate with safety. The team reviewed the licenses corrective actions and conducted interviews to determine if root causes and generic concerns were adequately addressed. The team also reviewed corrective actions associated with adverse historical trends in human performance and CAP effectiveness.

(2) Assessment The team concluded that the licensees corrective action processes were effective and conducted in accordance with CAP and NRC requirements. The team did not identify any examples of ineffective corrective actions associated with issues within the assessment period. However, the team identified three historical examples of inadequate corrective actions for problems that originated before the assessment period.

Example 1: Ineffective Corrective Actions Following Lost Environmental Samples The licensee's corrective actions following an August 2002 lost waste monitoring tank environmental sample were not effective. In January 2004, the licensee was not able to locate a second monthly composite sample for the waste monitoring system for October 2003. This issue was previously disposition as NRC NCV 05000445;05000446/2004-009-001.

Example 2: Corrective Actions to Address the Adverse Trend in Human Performance have not been Effective The licensees corrective actions to address a longstanding adverse human performance trend have not been effective. During 2002, external and licensee independent assessments identified an adverse trend in human performance (Eval-2002-008 and Eval-2003-001). This trend included five significant personnel errors in 2002 and five additional significant errors during the first part of 2003 (SMF-2004-000337). The licensee reviewed these events and concluded that increased focus on organizational processes which contributed to human performance events was needed. During 2004, a second external assessment concluded that the adverse trend had continued. The licensees corrective actions to address the adverse trend, which were taken before the assessment period, were not effective. The inspection team identified 14 examples of poor human performance or poor use of human performance tools as significant contributing factors to events that occurred during the assessment period. Based on the continuation of the adverse human performance trend, the team concluded that the licensees corrective actions to address this problem have not been effective. The examples considered by the team included:

- October 2002: Inadequate operational pre-job review resulted in the unplanned inoperability of a residual heat removal train and condition prohibited by TSs (LER 445-03-01 and SMF-2002-003317). This issues was closed as a NCV NCV 05000446/2002-006.

- January 2003: A personnel error resulted in the unplanned loss of a protection bus (SMF-2003-000200). Although this example provided insight in to the licensees corrective actions, the inspectors concluded that the finding was minor.

- August 2003: Inadequate operational pre-job review resulted in the unplanned inoperability of both trains of control room air conditioning, a condition prohibited by TSs (LER 445-03-004, SMF-2003-002463, SMF-2004-000691, SMF-2004-000059, and SMF-200-002619). Although this issue provided insight in to the licensees corrective actions, the inspectors concluded that the finding was minor.

- September 2003: An error resulted in an unplanned reactor shutdown after core criticality was outside reactivity limits (SMF-2002-004139).

Although this issue provided insight in to the licensees corrective actions, the inspectors concluded that the finding was minor.

- November 2003: A valve mispositioning resulted in the inoperability of the spray additive system (LER 446-03-003-00 and SMF-2003-003559).

Although this issue provided insight in to the licensees corrective actions, the inspectors concluded that the finding was minor.

- November 2003: Entry into a high radiation area without a briefing on radiation dose rates (SMF-2003-003594). This finding was previously disposition as NRC NCV 05000445;05000446/2004003-001.

- February 2004: Personnel error resulted in the loss of turbine load (SMF-2004-000514). This finding was previously disposition as NRC FIN 05000446/2004005-02.

- March 2004: Violation of TS 3.7.17, spent fuel assembly storage, due to personnel error (LER 445-04-001-00 and SMF-2004-000797). Although this issue provided insight in to the licensees corrective actions, the inspectors concluded that the finding was minor.

- April 2004: A workers failure to follow a radiation work permit requirement resulted in a violation of TSs (SMF-2004-001202. This finding was previously disposition as NRC NCV 05000446/2004003-03.

- April 2004: Inadvertent removal of the wrong lock box resulted in reactor vessel level indication system probe damage (SMF-2004-001204).

Although this issue provided insight in to the licensees corrective actions, the inspectors concluded that the finding was minor.

- May 2004: Personnel error resulted in the loss of turbine load (SMF-2004-001869). Although this issue provided insight in to the licensees corrective actions, the inspectors concluded that the finding was minor.

- September 2004: An incorrect breaker manipulation during restoration from a containment spray pump lockout test resulted in the inadvertent start of a safety injection pump (SMF-2004-003292). Although this issue provided insight in to the licensees corrective actions, the inspectors concluded that the finding was minor.

- October 2004: Inadequate operational pre-job review resulted in an unplanned power reduction after the loss of heater drain forward flow during the calibration of recirculation Valve 2-HV-2589B (SMF-2004-00514). This finding was previously disposition as NRC FIN 05000446/2004005-01.

- November 2004: Personnel error resulted in the loss of turbine load (SMF-2004-003636 and SMF-2004-003644). Although this issue provided insight in to the licensees corrective actions, the inspectors concluded that the finding was minor.

Example 3: Agastat Relay Issues - Inadequate Corrective Actions The licensee failed to take effective corrective actions to combat repetitive failures of Agastat relays. Following an event in October 2002 when an emergency diesel generator unexpectedly started due to a faulty Agastat relay, the licensee developed corrective actions to combat Agastat relay failures.

These corrective actions were not sufficient to preclude repetition of a similar event as evident in October 2004 when an Agastat relay caused a safeguards 6.9KV bus to de-energize. The repeat failure in October 2004 was the result of ineffective corrective actions following the October 2002 event. Although the licensee had identified the relay for replacement, the team concluded that the licensees failure to implement a timely replacement schedule following the October 2002 event was an example of inadequate corrective actions. This issue was discussed as a finding in section 4OA2e(2)(i) of this report.

d. Assessment of Safety-Conscious Work Environment

(1) Inspection Scope The team conducted 36 interviews, randomly selected from a variety of plant organizations, to assess the establishment of a safety-conscious work environment at CPSES. The inspectors used the guidance provided in Inspection Procedure 71152, Identification and Resolution of Problems, Appendix, Suggested Questions for Use in Discussions with Licensee Individuals Concerning PI&R Issues, while conducting the interviews. The team interviewed both supervisory and non-supervisory individuals from maintenance, work planning, engineering, independent assessment, security, radiation protection, and operations. The team also reviewed the results of the safety-conscious work environment and organizational assessment surveys listed in the attachment and plant safety issues submitted to the employee concerns program.

(2) Assessment The team concluded that the licensee had established a safety-conscious work environment at CPSES. All the individuals interviewed indicated that they felt comfortable raising and pursuing safety concerns and did not feel intimidated or discouraged from initiating condition adverse to quality reports. The team concluded that the employee concerns program effectively resolved safety issues raised by plant personnel. Plant personnel who were interviewed considered the employee concerns program a viable option for pursuing safety concerns.

However, the licensee had identified long-term organizational effectiveness issues within the operations department, which continued to challenge the safety-conscious work environment for shift operations personnel.

The licensee performed a safety-conscious work environment survey of shift operations personnel in 2003. The survey revealed that a minority of shift operations personnel felt intimidated or discouraged from raising safety concerns or initiating condition adverse to quality reports. Less than 50 percent of the surveyed personnel returned the completed surveys. The survey also revealed strong indications of organizational ineffectiveness between some workers and first level supervision. The licensee implemented a corrective action plan to address these concerns.

In 2004, the licensee conducted a followup safety-conscious work environment survey with operations personnel. The followup survey was designed to assess the effectiveness of the corrective actions. The followup survey indicated safety culture and organizational improvements. However, about 30 percent of licensed reactor operators continued to express that they felt intimidated or discouraged from raising safety concerns or initiating condition adverse to quality reports. The licensee took additional corrective actions.

During this inspection, the team conducted interviews of 14 randomly selected licensed operations personnel to assess the safety-conscious work environment. All of the individuals indicated that they felt comfortable raising and pursuing safety concerns and did not feel intimidated or discouraged from initiating condition adverse to quality reports. However, about half of the licensed reactor operators interviewed stated that organizational issues have not improved.

The team concluded that the licensee's past actions to improve operations department organizational effectiveness have not been fully effective. The team concluded that without licensee management attention, these organizational issues may evolve into a safety-conscious work environment concern.

e. Specific Issues Identified During this Inspection

(1) Inspection Scope During the reviews described in Sections 4OA2 a.(2), 4OA2 b.(2), and 4OA2 c.(2) the team identified the following findings.

(2) Findings and Observations

(i) Inadequate Corrective Actions to Address Longstanding Agastat Relay Issues Resulted in the Inoperability of a 6.9 kV Safeguards Bus

Introduction.

The team identified a finding and an unresolved item related to TS 3.8.1 after neither the alternate offsite AC nor the emergency diesel generator supplied power to a 6.9 kV safeguards bus within the time assumed in the accident analysis. This item is unresolved pending completion of inspection necessary to determine enforcement and the significance.

Description.

On October 19, 2004, an unplanned loss of the preferred offsite power caused the Unit 2, Train B, 6.9 kV safeguards bus to deenergize. A degraded Agastat relay delayed the normal power supply breaker from opening for 30 seconds. Both the emergency diesel generator and the alternate power supply were prevented from powering the bus due to a breaker interlock with the normal supply. This delay rendered both the emergency diesel generator and alternate offsite AC power supplies inoperable. The 30 second delay in providing power to the safeguards bus would have resulted in the station not meeting the 10 CFR 50, Appendix K, Emergency Core Cooling System Evaluation Models Acceptance Criteria, for that equipment train.

The licensee had a previous opportunity to correct the degraded Agastat relay issues.

On October 7, 2002, the emergency diesel generator unexpectedly started due to a degraded Agastat relay. The licensee concluded that the failure could have been caused by aging and formed a corrective action plan to replace all safety-related Agastat relays that have been in service for greater than the licensee established 12 year lifetime. Licensee Evaluation 2003-001440-01-01 stated that the main effect of aging on these relays was an increase in setpoint drift. The licensee issued SMF-2002-003391 to track the root cause and corrective actions associated with the faulty Agastat relays. Also, the NRC previously identified that Agastat relays used in the 6.9 kV bus transfer circuitry were exhibiting setpoint drift (SMF-2002-001504 and Inspection Report 05000445/2003006; 05000446/2003006). The relay that failed in October 2004 was 16 years old. The team concluded that the failure to perform immediate corrective actions after the October 2002 event was an example of inadequate corrective actions.

Analysis.

This finding adversely impacted the reliability of emergency power to mitigating systems. This finding is greater than minor because the reactor mitigating systems cornerstone and the equipment performance attribute to prevent core damage are affected. The licensee's failure to identify the cause and implement corrective actions to prevent repetitive failures of safety related Agastat relays was a performance deficiency. The inspectors determined that the finding has potential safety significance greater than very low because the condition represents an actual loss of a safety function for a single train greater that its TS allowed outage time.

Enforcement.

TS 3.8.1 required the licensee to restore either the alternate offsite transmission source or the emergency diesel generator to the onsite Class 1E AC electrical distribution system within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Contrary to the above, neither the alternate offsite transmission source nor the emergency diesel generator were capable of supplying the Class 1E AC electrical distribution within the response time assumed in the accident analysis. This condition existed for an extended duration, in excess of the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> TS limiting condition for operation. Pending determination of the performance deficiency and the safety significance, this finding is identified as URI 05000446/2005009-01, inoperability of emergency power to a safety bus.

(ii) Inadequate Postmodification Test Resulted in the Introduction of Loose Parts into the Reactor Cavity

Introduction.

The team identified a Green self-revealing finding associated with inadequate postmodification testing of the Unit 2 refueling machine festoon. The festoon failed during refueling operations, resulting in the introduction of loose parts into the lower internals storage area of the refueling cavity.

Description.

The festoon tow bar broke and parts of it fell into the pool and settled in the vicinity of the reactor cavity lower internals storage area. The parts included two 20-inch austenitic stainless steel fasteners, nuts, and washers.

The licensee installed the festoon during Refueling Outage 5 to replace the older take-up reel on the refueling machine, however the festoon rails were not adequate to allow bridge travel to the mechanical stops. The postmodification test only verified festoon clearance for bridge travel to the electrical bridge stops. However, some refueling operations required bridge travel beyond the electrical stops to the mechanical stops.

The operators bypassed the electrical bridge stops on several occasions. Travel beyond the length of the festoon rails caused the cable trolleys to compact and placed enough stress on the tow rods to break the welds of the base plates holding the rods in place. Engineering personnel establishing the postmodification test did not understand that some fuel handling operations required bridge travel past the electrical stops.

Analysis.

Failure of the licensee to perform a postmodification test that demonstrated that the festoon would perform satisfactorily in service was a performance deficiency.

This finding is more than minor because the barrier integrity cornerstone objective to provide reasonable assurance that physical barriers (including the fuel clad) to protect the public from radionuclide releases caused by accidents or events is affected. The introduction of loose parts into the reactor cavity during refueling is associated with the fuel clad attributes of human performance and foreign material exclusion. The team analyzed the finding using Appendix G, Shutdown Operations, of Manual Chapter 0609, Significance Determination Process, Attachment 1, Checklist 4. The team concluded that the finding did not require a quantitative assessment because the condition does not increase the likelihood of a loss of reactor coolant system inventory or loss of reactor coolant system level instrumentation, does not degrade the licensee's ability to terminate a leak path or add reactor coolant system inventory when needed, and does not degrade the ability to recover decay heat removal once it is lost. Since a quantitative assessment was not required, the finding was of very low safety significance.

Enforcement.

No violation of regulatory requirements occurred. The team determined that the finding did not represent a noncompliance because it occurred on nonsafety related equipment. This finding was entered into the corrective action program as SMF-2003-003283 (FIN 05000446/2005009-02).

(iii) Inadequate Evaluation Resulted in Failure to Identify a Failed Containment Pressure Channel

Introduction.

The team identified a Green noncited violation after the licensee failed to complete a required TS action after a containment pressure channel failed. The operating crew did not recognize that the channel had failed.

Description.

While operating in Mode 1 on August 5, 2004, a control room containment pressure channel deviation alarm occurred. The alarm was activated when one channel deviated from the other three by greater than +0.3 psig. Control room instrumentation indicated that the channel deviated -2.0 psig from the other channels. Operating Procedure OPT-102A-1, Mode 1 and Mode 2 Shiftily Surveillances, established a

+3.0 psig channel deviation acceptance criteria. On August 6, 2004, the licensee identified that a grounded transmitter shield wire had caused the channel deviation alarm. The licensee calculated a channel statistical allowance of +1.5 psig for containment pressure data obtained from the plant computer. Using archived plant computer data, the licensee determined that the pressure channel became inoperable at the time of the deviation alarm and remained inoperable for greater than 31 hours3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br />. The licensee repaired and returned the channel to service. TS 3.3.2, required the licensee to place the safety injection and steamline isolation function in trip, and bypass the containment spray and containment isolation functions, within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, or place the unit in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The licensee did not meet either of the required actions.

Plant operators should have requested a Quick Turnaround Evaluation, per Procedure STA-422, Corrective Action Program, at the time of the deviation alarm.

The Quick Turnaround Evaluation would have prompted the licensee to perform the plant computer data evaluation and the inoperability of the channel could have been determined before the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> TS action.

Analysis.

The inspectors used the at-power situation significance determination process to analyze this finding. This finding affected the mitigating systems cornerstone because of the containment pressure channel safety function. The failure of operations personnel to place the inoperable containment pressure channel in trip/bypass within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> was a performance deficiency. This finding is greater than minor because, if left uncorrected, the failure to recognize inoperable mitigating systems instrumentation would become a more significant safety concern. This finding is only of very low safety significance because the condition was not a design or qualification deficiency confirmed to result in loss of function per Generic Letter 91-18; did not result in an actual loss of safety function of a system; did not increase the likelihood of a fire; and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. This finding involved the failure of operations personnel to implement a TS Action requirement and was associated with the crosscutting area of human performance.

Enforcement.

TS 3.3.2, Conditions D and E required the licensee to place the safety injection and main steamline isolation functions in trip, and the containment spray and containment isolation functions in bypass, within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following an inoperable containment pressure channel or place the unit in Mode 3 within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Contrary to the above, the licensee did not place the safety injection and main steamline isolation functions in trip, nor the containment spray and containment isolation functions in bypass, within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following an inoperable containment pressure channel or place the unit in Mode 3 within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> on August 5, 2004. The containment channel was inoperable greater than 31 hours3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br />. Because the violation was of very low safety significance, and was entered into the licensees CAP (SMF-2005-002752 and SMF-2005-003157), this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000446/2005009-03).

4OA3 Event Follow-up

(Closed) License Event Report 05000446/2004-03-00: Containment Pressure Channel Inoperable due to a Secondary Ground On August 5, 2004, the licensee failed to complete a required TS action after a containment pressure channel failed. This event and the inspectors findings were described in Section 4OA2e(2)(iii) of this report. The inspectors reviewed the LER and no additional findings of significance were identified. This LER is closed.

4OA4 Crosscutting Aspects of Findings

Section 4OA2 documents a finding with human performance crosscutting aspects which involved the failure of shift operations personnel to recognize that a containment pressure channel was inoperable for an extended period.

4OA6 Exit Meeting

The team discussed the findings with Mr. M. Blevins, Senior Vice President and Chief Nuclear Officer, and other members of the licensees staff on July 29, 2005. The team reviewed some proprietary information during the inspection but that information was returned to the licensee prior to the exit.

ATTACHMENT PARTIAL LIST OF PERSONS CONTACTED Licensee I. Ahmad, Generic Letter 91-18 Program Owner J. Audas, Manager, Safe Team M. Blevins, Senior Vice President and Chief Nuclear Officer D. Bozeman, Manager, Emergency Planning R. Flores, Vice President, Operations T. Gilder, Manager, Corrective Action Program T. Hope, Manager, Regulatory Performance R. Kidwell, Licensing Engineer M. Lucas, Vice President, Nuclear Engineering F. Madden, Manager, Regulatory Affairs T. Mavrey, Manager, Equipment Reliability R. Smith, Manger, Operations B. Turnipseed, Valve Team Supervisor T. Weyandt, System Engineer D. Wilder, Manager, Radiation and Industrial Safety, Radiation and Industrial Safety LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 05000446/2005009-01 URI Inadequate Corrective Actions to Address Longstanding Agastat Relay Issues Resulted in the Inoperability of a 6.9 kV Safeguards Bus (Section 4OA2e(2)(i))

Opened and Closed 05000446/2005009-02 FIN Inadequate Postmodification Test Resulted in the Introduction of Loose Parts into the Reactor Cavity (Section 4OA2e(2)(ii))05000446/2005009-03 NCV Inadequate Evaluation Resulted in Failure to Identify a Failed Containment Pressure Channel (Section 4OA2e(2)(iii))

Closed 05000446/2004-03-00 LER Containment Pressure Channel Inoperable due to a Secondary Ground (Section 4OA3)

LIST OF

DOCUMENTS REVIEWED

PLANT PROCEDURES

Procedure Title

CHM-517 Chemistry Control of Liquid Waste Systems, Revision 9

CHM-708 ODCM Surveillance of the Low Volume Waste Pond, Revision 6

ECE 6.02-01 Procurement Levels, Revision 4, December 17, 2002

ECE 6.02-05 Technical and Quality Assurance Requirements, Revision 6,

December 8, 2004

ECE 6.02-03 Critical Characteristics Development, Revision 5B, January 10, 2003

ECE 6.02-06 Preparation of Verification Plans, Revision 3, December 17,2002

INC-214 I Installation of Electrical Conductor Seal Assemblies, Revision 0

NQA 3.09-11.03 Receiving Inspection, Revision 14, April 11, 2005

NQA 6.02 Quality Review of Procurement Documents, Revision 10,

January 15,1999

RPI-602 Radiological Surveillance and Posting, Revision 24

RPI-606 Radiation Work and General Access Permits, Revision 12

RPI-618 Operation of the Filter Shear System, Revision 3

RPI-713 Collection, Preparation, and Shipment of Radiological Environmental

Samples, Revision 4

STA-124 Human Performance Program, Revision 0

Attachment

STA-421 Initiation of Smart Forms, Revision 11

STA-422 Processing Smart Forms, Revision 19

STA-424 Self-assessment and Benchmarking Programs, Revision 2

STA-426 Industry Operating Experience Program, Revision 0

STA-428 Station Issue/Event Trending, Revision 0

STA-690 Risk Informed - Inservice Testing, Revision 2

TRA 17 Inspection Personnel Certification Program and Materials Test Lab

Personnel Qualification Program, Revision 4, May 17, 2005

Receipt Reports

RR 31042 Strainer, VP-NEM1119-01, March 9, 2005

RR 31074 Terminal Block, VP-NEE0623-02, March 24, 2005

RR 31216 Unistrut Screw, VP-NEM0870-01, April 3, 2005

RR 31237 U-Bolt, VP-NEM1343-01, March 29, 2005

RR 31409 Grout, VP-NES0002-01, July 7, 2005

RR 31412 Solder, Rosin Core, VP-NEE0596-01, July 9, 2005

RR 31436 04/08/05, Integrated Circuit, VP-NEE0730-01

RR 31554 06/02/05, Capacitor, VP-NEI0273-02

RR 31559 Receipt Report, Fitting, Conduit Nipple VP-NEE0665-01, June 18, 2005

RR 31571 Pressure Gage, VP-NEM1072-01, June 28, 2005

Attachment

RR 31573 Pressure Gage, VP-NEM1072-01, June 28, 2005

RR 31574 Connector, VP-NEE0603-01, June 18, 2005

RR 31579 Conduit, VP-NEE0566-01, June 18, 2005

RR 31583 Copper Fittings and Tubing, VP-NEM1375-01, May 31, 2005

RR 31596 06/17/05, Unistrut Nut, VP-NEM0870-01

RR 31619 Light Assembly, VP-NEE0636-01, June 14, 2005

RR 31642 Terminal Block Jumper, VP-NEE0714-01, June 27, 2005

RR 31661 O-Rings, VP-NEM1053-01, July 14, 2005

RR 31676 AR440AR Relay, VP-WEST611-01, June 27, 2005

RR 31715 Turbine Oil, VP-NEC0176-02, July 11, 2005

RR 31743 Flexitallic Gasket, VP-NEM1078-01, July 15, 2005

RR 31744 Mounting Bracket, VP-NEM1030-01, July 21, 2005

NRC Inspection Reports

IR 05000445/2003-006; 05000445/2003-006

IR 05000445/2004-003; 05000446/2004-003

IR 05000445/2004-008; 05000446/2004-008

IR 05000445/2004-009; 05000446/2004-009

SmartForms

SMF-1999-000704 SMF-1999-002772 SMF-2001-000728

SMF-1999-002579 SMF-1999-002776 SMF-2001-000889

SMF-1999-002655 SMF-2000-001115 SMF-2001-001015

SMF-1999-002720 SMF-2000-002242 SMF-2001-001268

SMF-1999-002740 SMF-2001-000345 SMF-2001-001861

SMF-1999-002755 SMF-2001-000686 SMF-2001-002122

Attachment

SMF-2001-002531 SMF-2003-001075 SMF-2004-000049

SMF-2001-002635 SMF-2003-001120 SMF-2004-000059

SMF-2002-000122 SMF-2003-001161 SMF-2004-000060

SMF-2002-000255 SMF-2003-001345 SMF-2004-000062

SMF-2002-000270 SMF-2003-001365 SMF-2004-000069

SMF-2002-000532 SMF-2003-001369 SMF-2004-000100

SMF-2002-000616 SMF-2003-001384 SMF-2004-000120

SMF-2002-000859 SMF-2003-001452 SMF-2004-000151

SMF-2002-001047 SMF-2003-001479 SMF-2004-000329

SMF-2002-001057 SMF-2003-001486 SMF-2004-000330

SMF-2002-001504 SMF-2003-001545 SMF-2004-000337

SMF-2002-001523 SMF-2003-001567 SMF-2004-000471

SMF-2002-001642 SMF-2003-001773 SMF-2004-000509

SMF-2002-001842 SMF-2003-001857 SMF-2004-000514

SMF-2002-001879 SMF-2003-001992 SMF-2004-000566

SMF-2002-002151 SMF-2003-002037 SMF-2004-000620

SMF-2002-002156 SMF-2003-002106 SMF-2004-000691

SMF-2002-002233 SMF-2003-002120 SMF-2004-000693

SMF-2002-002456 SMF-2003-002142 SMF-2004-000742

SMF-2002-002480 SMF-2003-002158 SMF-2004-000774

SMF-2002-003317 SMF-2003-002187 SMF-2004-000797

SMF-2002-003376 SMF-2003-002196 SMF-2004-000836

SMF-2002-003391 SMF-2003-002356 SMF-2004-000908

SMF-2002-003448 SMF-2003-002435 SMF-2004-001024

SMF-2002-003504 SMF-2003-002463 SMF-2004-001177

SMF-2002-003534 SMF-2003-002517 SMF-2004-001193

SMF-2002-003579 SMF-2003-002619 SMF-2004-001202

SMF-2002-003665 SMF-2003-002756 SMF-2004-001204

SMF-2002-003792 SMF-2003-002912 SMF-2004-001264

SMF-2002-003880 SMF-2003-003018 SMF-2004-001350

SMF-2002-003915 SMF-2003-003077 SMF-2004-001419

SMF-2002-003916 SMF-2003-003253 SMF-2004-001427

SMF-2002-003951 SMF-2003-003264 SMF-2004-001440

SMF-2002-004008 SMF-2003-003283 SMF-2004-001457

SMF-2002-004026 SMF-2003-003309 SMF-2004-001581

SMF-2002-004064 SMF-2003-003479 SMF-2004-001610

SMF-2002-004118 SMF-2003-003514 SMF-2004-001662

SMF-2002-004139 SMF-2003-003559 SMF-2004-001677

SMF-2002-004167 SMF-2003-003594 SMF-2004-001685

SMF-2002-004242 SMF-2003-003599 SMF-2004-001869

SMF-2002-004318 SMF-2003-003604 SMF-2004-001927

SMF-2003-000152 SMF-2003-003675 SMF-2004-002120

SMF-2003-000200 SMF-2003-003853 SMF-2004-002244

SMF-2003-000439 SMF-2003-003898 SMF-2004-002269

SMF-2003-000571 SMF-2003-003918 SMF-2004-002357

SMF-2003-000604 SMF-2003-003965 SMF-2004-002391

SMF-2003-000754 SMF-2003-004016 SMF-2004-002411

SMF-2003-000931 SMF-2003-004075 SMF-2004-002488

Attachment

SMF-2004-002568 SMF-2005-000114 SMF-2005-001529

SMF-2004-002679 SMF-2005-000119 SMF-2005-001549

SMF-2004-002752 SMF-2005-000164 SMF-2005-001557

SMF-2004-002831 SMF-2005-000257 SMF-2005-001574

SMF-2004-002852 SMF-2005-000259 SMF-2005-001619

SMF-2004-002865 SMF-2005-000267 SMF-2005-001641

SMF-2004-002903 SMF-2005-000273 SMF-2005-001666

SMF-2004-002938 SMF-2005-000284 SMF-2005-001689

SMF-2004-002962 SMF-2005-000288 SMF-2005-001692

SMF-2004-003187 SMF-2005-000292 SMF-2005-001704

SMF-2004-003192 SMF-2005-000296 SMF-2005-001740

SMF-2004-003292 SMF-2005-000323 SMF-2005-001756

SMF-2004-003306 SMF-2005-000350 SMF-2005-001781

SMF-2004-003399 SMF-2005-000377 SMF-2005-001787

SMF-2004-003413 SMF-2005-000527 SMF-2005-001835

SMF-2004-003485 SMF-2005-000591 SMF-2005-001854

SMF-2004-003495 SMF-2005-000722 SMF-2005-001875

SMF-2004-003528 SMF-2005-000806 SMF-2005-001895

SMF-2004-003610 SMF-2005-000870 SMF-2005-002113

SMF-2004-003636 SMF-2005-001070 SMF-2005-002228

SMF-2004-003644 SMF-2005-001152 SMF-2005-002399

SMF-2004-003833 SMF-2005-001223 SMF-2005-002437

SMF-2004-003883 SMF-2005-001253 SMF-2005-002471

SMF-2004-003917 SMF-2005-001308 SMF-2005-002499

SMF-2004-003932 SMF-2005-001343 SMF-2005-002681

SMF-2004-004007 SMF-2005-001361 SMF-2005-002717

SMF-2004-004026 SMF-2005-001392 SMF-2005-002739

SMF-2004-004033 SMF-2005-001468 SMF-2005-002834

SMF-2005-000032 SMF-2005-001486 SMF-2005-002929

SMF-2005-000038 SMF-2005-001512

SMF-2005-000069 SMF-2005-001521

SMF-2005-000085 SMF-2005-001528

Miscellaneous

ACTN-MAN-2004-003528-04

ACTN-MAN-2004-003528-03

AOV Component Health Report 2nd Quarter, 2004

AOV Component Health Report 3rd Quarter, 2004

CLS-2-04-01660

CPSES Component Status, 1st Quarter, FY 2005

CPSES Safeguards Events Log, Site Location #218 Quarter Beginning 07-01-2003

Attachment

CPSES Safeguards Events Log, Site Location #218, Quarter Beginning 04-01-2004

CPSES Safeguards Events Log, Site Location #218, Quarter Beginning 04-01-2005

CPSES Self Assessment Program Assessment SA-2004-056

CPSES Safeguards Events Log, Site Location #218, Quarter Beginning 10-01-2004

CPSES Safeguards Events Log, Site Location #218, Quarter Beginning 07-01-2004

CPSES Safeguards Events Log, Site Location #218, Quarter Beginning 01-01-2005

CPSES Safeguards Events Log, Site Location #218 Quarter Beginning 01-01-2004

CPSES Safeguards Events Log, Site Location #218 Quarter Beginning 04-01-2003

CPSES System Status, Unit 1, Main Steam, 1st Quarter, FY 2005

CPSES System Status, Unit 2, Main Steam, 1st Quarter, FY 2005

CPSES Quarterly Trend Summary Report, 3rd Quarter 2004

CPSES Quarterly Trend Summary Report, 4th Quarter 2004

CPSES Quarterly Trend Summary Report, 1st Quarter 2005

Drawing Number M1-2941, Revision CP-4

Drawing Number M2-2941, Revision CP-4

Failure Analysis of Agastat Time-Delay Relay Southwest Research Institute Report

Final Design Authorization FDA-2003-003283-01-00

Fuel Storage and Handling, Design Basis Document DBD-ME-080, Revision 17

Radiation Protection Guideline 6-3, Crud Burst Trending, Revision 3

Radiation Protection Power Operations Detail Report, July 11, 2005

SA-2003-020, STARS Alliance Round Robin Nuclear Safety Focus, April 24, 2003

Trend Analysis of Rad Worker Practices, Second Quarter 2005

Trend Analysis of ODCM and Related Smart Forms, Second Quarter 2005

Trend Analysis of Radiation and Industrial Safety Personnel/Managers Trend Errors,

June/Second Quarter 2005

Attachment

TXU Energy Report: Stevenville Switching Station OB. 4060 - Investigation Findings Following

Unwanted Trip Operation

TXU Engineering Calculation EE-CA-0008-0871

TXU Power Cause Analysis Handbook, Revision 6, July 13, 2004

NRC Publications

NUREG-1022, Revision 2

Regulatory Guide 1.97, Revision 3

Information Notice 88-89, Degradation of Captain Electrical Insulation

Information Notice 98-21, Potential Deficiency of Electrical Cable/Connection Systems

Assessment of Safety-Conscious Work Environment Surveys Reviewed

NOD Departmental Survey, 2005

Operations Department Nuclear Safety Culture Survey

Safe Team Program Audit, 2003-129

Safe Team Employee Survey results, December 2004

Safety Conscious Work Environment Survey with shift operations personnel, 2003

Safety Conscious Work Environment Survey with shift operations personnel, 2004

TUX Organizational Assessment Survey, 2002, NU-003

Independent Assessments

EVAL-2001-000728-01 EVAL-2003-000022 EVAL-2004-000025

EVAL-2002-001368-03 EVAL-2003-000031 EVAL-2004-000027

EVAL-2002-002233-01 EVAL-2003-001440-01 EVAL-2004-000030

EVAL-2002-003391-03 EVAL-2003-001440-01 EVAL-2004-001000-01

EVAL-2002-003391-06 EVAL-2003-002886-01 EVAL-2004-002676

EVAL-2002-003391-06 EVAL-2004-000009 EVAL-2004-003528-06

EVAL-2002-003579-01 EVAL-2004-000011 EVAL-2005-001361-01

EVAL-2002-004167-02 EVAL-2004-000015 EVAL-2005-001574-01

EVAL-2003-000019 EVAL-2004-000016 EVAL-2005-002113-02

EVAL-2003-000021 EVAL-2004-000021

Work Orders

WO-3-03-326804

WO-3-03-327774-01

WO-4-03-150145

WO-4-05-160956-00

WO-5-01-505017-AB

WO-5-03-501451-AA

WO-5-03-501452-AA

WO-5-03-501453-AA

Attachment

Licensee Event Reports

LER-445-03-001 LER-445-04-03 LER 446-04-002-01

LER-445-03-002 LER 446-03-001 LER 446-04-003

LER 445-03-003-00 LER 446-03-002 LER 446-05-001

LER 445-03-004 LER 446-02-003-01 LER 446-05-003

LER-445-04-001 LER 446-03-003

LER 445-04-002 LER 446-04-001

INFORMATION REQUESTS

From: Michael S. Peck

Sent: Monday, May 16,

To: Snow, Douglas W

Subject: Information Request 1, Comanche Peak Comanche Peak Steam Electric Station

PIR Inspection

Dear Mr. Snow:

The inspection will cover the period of Jun 19, 2003 to June 1, 2005. All requested information

should be limited to this period unless otherwise specified. To the extent possible, please

provide the information in electronic media in the form of CDs (Corel WordPerfect 8,

Presentations, Quattro Pro, MS Word, Excel, Power Point, and Adobe Acrobat (.pdf) text files).

Please provide the following information to the following address by May 31, 2005.

NRC Resident Inspector Office, Callaway Nuclear Plant, ATTN: Michael Peck, 8201 NRC Road,

Steedman, MO 65077

I am planning a pre-inspection site visit June 28th and 29th.

Thank you,

msp

1. Summary list and a copy of all condition reports of significant conditions adverse to

quality opened or closed during the period

2. Summary list of all condition reports of conditions adverse to quality opened or closed

during the period

3. Summary list of all condition reports which were down-graded or up-graded during the

period

4. Summary list of operator work arounds, engineering review requests and/or operability

evaluations, temporary modifications, and control room and safety system deficiencies

5. A list of all corrective action documents that subsume or roll-up one or more smaller

issues for the period

Attachment

6. List of all root cause analyses completed during the period

7. List of root cause analyses planned, but not complete at end of the period

8. List of plant safety issues raised or addressed by the employee concerns program

during the period

9. List of action items generated or addressed by the plant safety review committees

during the period

10. All quality assurance audits and surveillances of corrective action activities completed

during the period

11. A list of all quality assurance audits and surveillances scheduled for completion during

the period, but which were not completed

2. All corrective action activity reports, functional area self-assessments, and non-NRC

third party assessments completed during the period

13. Corrective action performance trending/tracking information generated during the period

and broken down by functional organization

14. Current revision of the following procedures: LI-102, 01-S-03-9, 01-S-06-5, 01-S-06-44,

01-S-06-2, 01-S-06-5

15. Any additional governing procedures/policies/guidelines for:

a. Condition Reporting

b. Corrective Action Program

c. Root Cause Evaluation/Determination

d. Deficiency Reporting and Resolution

16. A listing of all external events and operating experience evaluated for applicability at

Grand Gulf during the period

17. Condition Reports or other actions generated for each of the items below:

1. Part 21 Reports

2. NRC Information Notices and Bulletins

3. All LERs issued by Grand Gulf during the period

4. NCVs and Violations issued to Grand Gulf during the period

18. Radiation protection event logs

19. Current system health reports or similar information

Attachment

20. Current predictive performance summary reports or similar information

21. Corrective action effectiveness review reports generated during the period

From: Michael S. Peck

Sent: Monday, June 5, 2005 2:54 PM

To: Snow, Douglas W

Subject: Information Request 2 - Comanche Peak Comanche Peak Steam Electric

Station PIR Inspection

Dear Mr. Snow:

Please provide the following information to support the Comanche Peak PI&

R. If practical, I

could pick an electronic copy of the requested information during my on-site visit June 20th.

Thank you,

msp

1. Please provide the root cause analysis and a list of corrective actions (including design

modifications) following the centrifugal charging pump gas binding issues (Smart Form 2002-

004242). Please include a list of any subsequent gas binding issues at CP with corrective

actions.

2. Please provide a list of complete corrective actions and root cause analysis following relay

failures (Smart Form 2002-003391). Please include a list of any subsequent age related relay

failures at CP with corrective actions.

3. Please provide corrective actions and root cause analysis following the failure to maintain

design control over a safety class boundary isolation (Smart Form SMF-2003-001773-00).

4. Please provide corrective actions and root cause analysis following the failure to fully

implement Commission granted relief and alternative requirements (Smart Form SMF-2004-

003883-00).

5. Please provide the root cause analysis and corrective actions following the loss of Unit 2

turbine load due to missed step in transferring control to manual hydraulic control (SMF-2004-

3638-00 and SMF-2004-3644-00).

6. Please provide the root cause analysis and corrective actions following the Unit 2 downpower

due to loss of heater drain forward flow during calibration of 2-HV-2589B (SMF-2004-3413-00).

7. Please provide a summary list of all problem evaluation requests related to significant

conditions adverse to quality that were opened or closed between January 1, 2003 and June

19, 2003.

Attachment

8. Please provide a summary list of all problem evaluation requests related to conditions

adverse to quality that were opened or closed between January 1, 2003 and June 19, 2003.

9. Please provide a list of all root cause analyses completed during the period between

January 1, 2003 and June 19, 2003.

From: Michael S. Peck

Sent: Monday, June 16, 2005

To: Snow, Douglas W

Subject: Information Request 3, Comanche Peak Comanche Peak Steam Electric

Station PIR Inspection

Dear Mr. Snow:

Please provide the following additional information to support the Comanche Peak PI&R. If

practical, I could pick an electronic copy of the requested information during my on-site visit

June 20th.

Thank you,

Michael

1. A Smart forms and root analysis generated over the past five years associated with:

- Offsite power line and switchyard reliability

- RCS leakage detection systems, including suspected voiding of piping, and algae blocking an

orifice in

the containment cooler leakage detection system

- Adverse trends with configuration control stemming from valve, switch, and component mis-

positionings

- Steam Generator ARVs.

- Loose parts in the secondary side of the Unit 2 S/G's

- TDAFWP governor valve issues

- Adverse trends in occupational Radiation Safety

2. Smart Forms:

- SMF-2004-1264

- SMF-2004-062

- SMF-2004-0471

- SMF-2003-3594

- SMF-2004-1202.

From: Michael S. Peck

Sent: Monday, June 22, 2005

To: Snow, Douglas W

Attachment

Subject: Information Request 4, Comanche Peak Comanche Peak Steam Electric Station

PIR Inspection

Dear Mr. Snow:

Please provide the following information to support the upcoming Comanche Peak PI&R

Inspection.

Thank you,

Michael

1. The first information request, item #10, included All quality assurance audits. The CD did

not include any adits. Where any adits performed between February 1, 2003 and May 1, 2005?

2. Please provide a copy of the following Surveillance Reports (performed between February 1,

2003 and May 1, 2005) and related corrective action documents:

- Surv_CM_Configuration_and_Design_Control

- Surv_ER_Equipment_Reliability

- Surv_LP_Emergency_Preparedness

- Surv_LP_Fire_ProtectionSurv_LP_Problem_ID_&_Resolution

- Surv_LP_Security

- Surv_OP_Operations

- Surv_WM_Maintenance

- Surv_WM_Rad_Protection

3. The first information request, item #20" included Condition reports associated with

maintenance preventable functional failures during the period. None were provided on the C

D.

Did the plant have any maintenance preventable functional failures between February 1, 2003

and May 1, 2005? If so, how where they documented?

4. Please provide a copy of the following LERs:

- 2-04-002-01 (SMF-2004-003495) 10/19/04 Autostart of 2-02 EDG Ervin

- 2-05-001-00 (SMF-2004-004007) 01/18/05 Containment Airlock Door Inoperable

- 2-05-002-00 (SMF-2005-000722) 02/23/05 AFW Autostart Due to Loss of XST1

- 2-05-003-00 (SMF-2005-001666) 04/27/05 Two Pressurizer Safety Valves Failed

Surveillance

- 1-04-001-00 (SMF-2004-000797) 03/03/04 Violation of TS 3.7.17 Spent Fuel Assembly

Storage

- 1-04-002-00 (SMF-2004-001177) 04/02/04 Missed Surveillance on Loss of Power EDG Start

Instrumentation

- 1-04-003-00 (SMF-2004-002244) 07/26/04 RCS Leakage Detection Instrumentation

Inoperable

- 2-04-001-00 (SMF-2004-000100) 01/13/04 RWST Level Channel 2-L-0932 Inoperable

- 2-04-002-00 (SMF-2004-003495) 10/19/04 Autostart of 2-02 EDG

- 2-04-003-00 (SMF-2004-002752) 11/23/04 Containment Pressure Channel 2-PI-0935

Inoperable

Attachment

- 1-02-002-01 (SMF-2002-003142) 10/06/02 Unit 1 SGs in TS Category C-3

- 1-03-001-00 (SMF-2002-003317) 01/06/03 U1 Train B RHR Made Inop Due To Testing

- 1-03-002-00 (SMF-2003-000754) 03/16/03 Unit 1 Rx Trip Due to Loss of Main Feedwater

- 1-03-003-00 (SMF-2003-001365) 05/15/03 Dual Unit Turbine/Reactor trips due to a loss of

345KV switchyard.

- 1-03-004-00 (SMF-2003-002463) 08/20/03 TS 3.0.3 Entered When Both Trains of Control

Room Air

Conditioning System Were Inop per LCO 3.7.11.

- 2-03-001-00 (SMF-2003-001992) 07/09/03 Reactor trip due to loss of Reactor Coolant Pump

- 2-03-002-00 (SMF-2003-002196) 07/25/03 AFW autostart due to trip of both main FW

pumps.

- 2-03-003-00 (SMF-2003-003559) 11/02/03 Spray Additive System inoperable due to

mispositioned valves.

- 2-03-004-00 (SMF-2003-003599) 11/05/03 Containment pressure channel 2-pi-0935

inoperable

- 2-03-005-00 (SMF-2003-004016) 12/22/03 Reactor Trip Due to Strobescope Cover Falling

Into

Main Generator Exciter

5. Please provide a copy of the following Smart Forms, including attachments:

SMF-2005-001666-01, Evaluation of the Pressurizer Safety Valve Setpoint Drift,

SMF-2005-001343-00, Initial Licensed Operator Class Throughput / Pass Rate Was

inadequate.,

SMF-2005-000722-00, Unit 2 Black out Due to a Lightning Strike in West Texas.,

SMF-2005-000032-00, Perform a Collective Review of the Issues with the Unit 1 and 2

Containment Personnel Airlocks,

SMF-2004-004007-00, Unit 2 Pal Inner Door Seal Failure.

SMF-2004-003644-00, Unit Two Experienced a 464 Mwe Load Reduction.,

SMF-2004-003528-00, During Loss of Xst1, 2ea2-1 Breaker Did Not Open in Required Time.

SMF-2004-003495-01, Loss of 138 Switchyard (Xst1) Supply to Safeguard Buses Unit 2. This

Revision Is to Correct a Typographical Error in Eval-2004-003495-03 Which Reference an

Incorrect Smf Number.,

SMF-2004-003413-00,During the Calibration of 2-fv-2589b-ip1, 2-fv-2589a Failed Open

Causing a Heater Drain System Transient That Resulted in the Loss of Forward Flow Heater

Drains.

SMF-2004-003292-00,Incorrect Breaker Manipulation During Restoration from Containment

Spray Pump 2-02 86 Lockout Test Resulted in Inadvertent Start of the 2-02 Safety Injection

Pump.

SMF-2004-002852-00,Unit 2 Mfp 2b Speed Drifting above Commanded Setpoint.

SMF-2004-002752-00,Cable Shield, Grounded at Both Ends, Caused Intermittent Ground Loop

and Erroneous Indication. Intermittent Ground Caused by Dripping Mineral Deposit Material.

SMF-2004-002244-00,Unit One Containment Sump Flow Counter Inoperable

SMF-2004-001177-00,Ts Surveillance Requirement (Sr) 3.3.5.3, Channel Calibration Was Not

Completed Within the Required Frequencies for All Functions Specified on Table 3.3.5-1

SMF-2004-000797-00,Violation of Ts 3.7.17 `Spent Fuel Assembly Storage`

SMF-2004-000514-00,During Replacement of U1 Ehc System Dc to Dc Converter, Experienced

Approximately 300 Mwe Load Reject

Attachment

SMF-2004-000100-00,Received Channel Iii Rwst Level Low Computer Alarm and after

Comparing to Other Three Channels Dispatched Prompt Team to Investigate Channel Iii.

SMF-2003-004016-00,Unit Two Reactor/turbine Trip

SMF-2003-003675-00,Questionable CP Air Pressure Test Rig That Is Used to Check the Seals

of the Shipping Container for Air Leakage.

SMF-2003-003599-00,Loop 2-p-0935 Was Found to Be Inoperable. It Was Discovered at 0945

11/05/2003 That it Had Been Inoperable since 0530 11/03/2003.

SMF-2003-003559-00,During Performance of Opt-205b Containment Spray Sys Vpv, Found

2ct-0030 and 2ct-0034 Closed.

SMF-2003-003283-00,Refueling Machine Festoon Brace Broke and Fell into Lower Internals

Storage Stand.

SMF-2003-002463-00,Technical Specification Lco 3.0.3 Entered When Both Trains of Control

Room Air Condition System Were Identified as Inoperable per Ts Lco 3.7.11.

SMF-2003-002356-00,Circ Water Pump 2-01 Tripped, Resulting in a Loss Unit Two Output of

Mw.

SMF-2003-002196-00,Feed Water Pump 2b Tripped on Low Suction Pressure after Feed

Heaters 5b & 6b Were Unisolated. Turbine Was Manually Tripped.

SMF-2003-002120-00,Improper Bearing Installation Performed During Rebuild of Saftey Chiller

2-06.

SMF-2003-001384-00,Leakage Indicated from Unit 2 Primary Water System into Unit 2 Main

Generator.

SMF-2003-000754-00,Unit 1 Manual Reactor Trip Initiated Due to Loss of Main Feedwater.

SMF-2003-000571-00,Fire Pump X-04 Unexpected Start. 11,500 Gallons of Water Pumped

into Mmo Building (2k3). Reportable to Tceq. 50.72 to Nrc Issued

SMF-2002-004167-00,Rod Control System Malfunction Which Caused Shutdown Bank B Rod

G-13 to Fully Insert.

SMF-2002-004139-00,Unit 1 Reactor Achieved Criticality Outside the 500 Pcm Limit, but above

the Rod Insertion Limit.

SMF-2002-004064-00,Unit 1 Manual Shut Down. During Hot Torque Activity on 1ms-0063, a

Loud Popping Noise Came from Valve Body and Graphoil Dust Covered the Inner Side of

Yoke.

SMF-2002-004026-00,Primary Water Pump Inboard Labyrinth Seal Leaking.

SMF-2002-003951-00,Packing Leak on 1-hv-2336a During Packing Consolidation.

SMF-2002-003916-00,Multiple Cycling of U2 Main Turbine Control Valves Resulted in a

Secondary Transient, Stabilizing at Approximately 950 Mw with Turbine Control on Mhc.

SMF-2002-003915-00,Ran Rhrp 1-02 for Approximately Five Minutes with the Discharge Valve

Closed.

SMF-2002-002151-00,Unit Two Reactor Tripped on Pw Pump Shaft Vibration Signal

SMF-2003-000200-00,Personnel Error Caused Loss of Protection Bus 1pc2 During Restoration

of Iv1pc2.

SMF-2003-001567-00,Since August 6, 2002, Seven Incidents of Safeguards Information Being

Improperly Stored, Unattended, or Containers Left Open.

SMF-2003-001857-00,Declared Sswp 2-01 Inoperable Due to Failure of Opt-207b.

SMF-2003-002158-00,`Yellow` Soer 03-02, `Managing Core Design Changes` Requires

Assessment per Nqa-2.30 and Requires a 150 Day Response.

SMF-2003-002435-00,Through Wall Leak on Fire Protection Pipe.

SMF-2003-003018-01,While Removing 2-hs-6554a an Energized Cable Was Discovered.

Attachment

SMF-2003-003264-00,Area for Improvement from 2003 Inpo Radiological Protection

Assessment

SMF-2003-003479-00,Unit 2 Tdafwp Would Not Control Speed During Opt-206b.

SMF-2003-003898-00,Self-assessment Afis and Issues - 2002 Inpo Findings

SMF-2004-000620-00,Individual Entered a Posted High Rad Area Without First Contacting Rp

as Specified on the Associated Posting.

SMF-2004-000774-00,Performance Indicator for Unplanned Scrams per 7000 Hours Is above

Site Threshold

SMF-2004-001024-00,Source Range Channel N31 Did Not Respond During the Plant

Shutdown for 1rf10

SMF-2004-001193-00,2cs-8386b Failed

SMF-2004-001204-00,Inadvertent Removal of Wrong Lock Box Led to Damage of Rvlis Probe.

SMF-2004-001350-00,A Damaged Control Rod Was Discovered During Ut Inspections. One

Rodlet Remains in Assembly L11.

SMF-2004-001419-00,During Performance of Opt-435a the Recorder at Safety Chiller 1-06

Malfunctioned Failing to Capture Acceptance Criteria Data.

SMF-2004-001427-01,Diesel Generator 1-02 Phase C Linear Reactor Overheated During Start

Up.

SMF-2004-001581-00,Stud Can Hit During Control Rod Shaft Installation.

SMF-2004-001869-00,Testing of Unit 1 Turbine Generator Digital Controls Causes 260 Mwe

Load Reduction.

SMF-2004-001927-00,Surveillance for -16 PMM Response Time (5-04-501803-aa) Did Not

Meet Response Time Allowable Range Criterion as Specified in Inc-7662a

SMF-2004-002391-00,In Trending of Unit 2 Tpcw for June 2004, Copper and Suspended

Impurities Were Noted to Have Increased at a Rate Much Greater than Anticipated.

SMF-2004-002679-00,Quality Assurance Deficiencies Identified During Performance of Nuclear

Overview Audit of Maintenance Procedures and Documents.

SMF-2004-002831-00,Increase in Fission Product Gas Observed in Unit 1 Rcs Sample.

SMF-2004-002865-00,Procedures Not Being Maintained Current

SMF-2004-002938-00,This Smartform Is to Request a Look at the Following Events and the

Challenges They Presented to Determine If There Is a Common or Programmatic Issue That

Needs to Be Addressed.

SMF-2004-002962-00,Adverse Trend Identified

SMF-2004-003187-00,2-p-0935 Indicates Low after Performance of Routine Maintenance.

SMF-2004-003306-00,Discovery of Unposted Radiation Area in 790` Auxiliary Building Corridor.

Good Catch for S. J. Stalling.

SMF-2004-003485-00,Secondary System Air Operated Valve Failures Are Causing Challenges

to Plant Operation. ,Weaknesses in Corrective Actions from Focused Self-assessment Results

SMF-2004-004026-00,Inpo Has Re-issued a Wano Report on Loss of Grid and it Is Listed as

Soer 99-01, Addendum. This Report Needs to Be Assessed per Sta-426.

SMF-2005-000323-00,Issues Were Identified During Nuclear Overview Audit Eval-2005-031,

`Procurement and Materials Management`

SMF-2005-000591-00,Scaffold Erection Within Flash and Limited Approach Boundary of 345

Kv Buss on 2mt2

SMF-2005-001392-00,Diesel Fire Pump X-06 Had Oil Leak from Center Head Cover Gasket.

SMF-2005-001486-00,Fuel Handling Crew Latched on to an Incorrect Assembly During Fuel

Assembly Oxide Measurement Activities.

Attachment

SMF-2005-001521-00,While Filling and Venting U2 Train B Rhr 2rh-0011 Was Left Open

Resulting in Water Draining from the Refueling Cavity into the Containment 808`

SMF-2005-001574-00,Collectively Assess Large Motor Off-site Repair Shop Expectations and

Post Repair Shop in Plant Installation Challenges.

SMF-2005-001689-00,During Equipment Walkdown of Ssw Pump 2-02 Motor, Smart 3

Electrician Noticed Oil in Level Gage Appeared to Be Abnormal in Color.

SMF-2005-001692-00,Entry Made into Unit 2 808` Incore Room to Work Barrier Modification

Was Not in Accordance with the Rwp Requirements.

Attachment

From: Michael S. Peck

Sent: Monday, July 6, 2005 9:59 AM

To: Snow, Douglas W

Subject: Information Request 5, Comanche Peak Comanche Peak Steam Electric Station

PIR Inspection

Dear Mr. Snow:

Please provide the request data. We can pick up the larger files on-site Monday.

Thank you,

Michael

ABN-401, Main Turbine Malfunction

EVAL-2004-003638-02-00 - Unit 2 Main Generator A

Evaluations 2003-001440, 2002-003579, and 2002-003391-06, Agastat relays issue

Smart Form associated with residue in the vicinity of CRDM for rod G-13

SMF 2002-001504, Relay issues

SMF- 2002-003376, Relay issues

SMF 2002-003448 and SMF 2004-000060, NCV IR 2004009

SMF associated with FIN 05000446/2004005-01, Unit 2 Downpower Due to Loss of Heater

Drain Forward Flow During Calibration of 2-HV-2589

B.

SMF associated with FIN 05000446/2004005-02, Loss of Unit 2 Turbine Load Due to Missed

Step in Transferring Control to Manual Hydraulic Control

SMF-2001-00728-01

SMF-2002-003579, Relay issues

SMF-2003-001773, NCV IR 2004008

SMF-2003-001773-00, NCV from IR 2004008

SMF-2003-002567-00

SMF-2003-003755-00

SMF-2003-003755-00 - UNIT 1 CONTAINMENT SUMP

SMF-2003-3594, NCV IR 2004003

SMF-2003-3898

SMF-2004-001709-00

SMF-2004-002202-00 - Unit 1 Containment Sump

SMF-2004-002360-00 - Unit 2 containment sump

SMF-2004-003639-00 - UNIT 2 LOST 'A' PHASE MAI

SMF-2004-003833, Weaknesses in Corrective Actions from Focused Self-assessment Results

SMF-2004-003883, NCV IR 2004008

SMF-2004-0069 NCV IR 2004003

SMF-2004-062 and SMF2004-0471, NCV IR 2004003

SMF-2004-1202 , NCV IR 2004003

SMF-2004-2865

SMF-2004-3306

SMF-2004-4026

SMF-2005-000155-00

SMF-2005-000652-00 - Multiple transients

SMF-2005-000679-00 - INPO Area For Improvement

Attachment

SMF-2005-000948-00

SMF-2005-001149-00

SMF-2005-001390-00

SMF-2005-001400-00

SMF-2005-001662-00

SMF-2005-0032

SMF-2005-1343, not in the subdirectory

SMF-2005-1486

SMF-2005-169

SOP-401B 6 - TURBINE CONTROL FLUID SYSTEM

The Smart Form associated with Unit 2 LER-04-002-00

W.O. 4-04-155609-00

W.O. 4-04-155680-00

Please make the following data available to the team on-site Monday morning.

CLS-2-04-01660 SMF-2003-3853 SMF-2005-001308-00

EVAL-2002-001368-03-00 SMF-2004-000059 SMF-2005-001361-00

EVAL-2004-001000-01 SMF-2004-000151 SMF-2005-001549

EVAL-2004-009 SMF-2004-000691 SMF-2005-001689

EVAL-2005-001361-01-00 SMF-2004-001610 SMF-2005-001704

EVAL-2005-002113-02 SMF-2004-001662-00 SMF-2005-001781

SMF-2001-001861 SMF-2004-001677-00 SMF-2005-001835

SMF-2002-000859-00 SMF-2004-001685 SMF-2005-001854

SMF-2002-001842-00 SMF-2004-002269 SMF-2005-002113

SMF-2003-000152 SMF-2004-002411 WO-3-03-326804

SMF-2003-001075 SMF-2004-003917 WO-3-03-327774-01

SMF-2003-001161 SMF-2004-004033 WO-4-03-150145

SMF-2003-001479 SMF-2004-2568 WO-4-05-160956-00

SMF-2003-002142 SMF-2004-836 WO-5-01-505017-AB

SMF-2003-002187 SMF-2005-000069 WO-5-03-501451-AA

SMF-2003-002619 SMF-2005-000119 WO-5-03-501452-AA

SMF-2003-002756 SMF-2005-000164 WO-5-03-501453-AA

SMF-2003-003309-00 SMF-2005-000527-00

SMF-2003-2106 SMF-2005-000870-00

ACRONYMS

AC alternating current

CPSES Comanche Peak Steam Electric Station

CAP corrective action program

RCP reactor coolant pump

SDP significance determination process

SMF SmartForm

TS Technical Specification

Attachment