IR 05000457/2003002

IR 05000466-03-002, 05000457-03-002, DRP Integrated Report, Dtd 01/01-03/31/03, Braidwood Station, Units 1 and 2, Warrenville, Il

ML031140547
Person / Time
Site:	Braidwood
Issue date:	04/21/2003
From:	Ann Marie Stone NRC/RGN-III/DRP/RPB3
To:	Skolds J Exelon Generation Co
References
IR-03-002
Download: ML031140547 (45)

Text

ril 21, 2003

SUBJECT:

BRAIDWOOD STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 50-456/03-02; 50-457/03-02

Dear Mr. Skolds:

On March 31, 2003, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Braidwood Station, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on April 11, 2003, with Mr. J. von Suskil and other members of your staff.

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

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

Based on the results of this inspection, one self-revealing issue that was evaluated under the risk significance determination process as having a very low safety significance (Green) was identified. The NRC has also determined that a violation is associated with this issue. This violation is being treated as a Non-Cited Violation (NCV), consistent with Section VI.A of the Enforcement Policy. The NCV is described in the subject inspection report.

If you contest the subject or severity of the Non-Cited Violation, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S.

Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission -

Region III, 801 Warrenville Road, Lisle, IL 60532-4351; the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector at the Braidwood facility.

Since the terrorist attacks on September 11, 2001, the NRC has issued two Orders (dated February 25, 2002, and January 7, 2003) and several threat advisories to licensees of commercial power reactors to strengthen licensee capabilities, improve security force readiness, and enhance access authorization. The NRC also issued Temporary Instruction 2515/148 on August 28, 2002, that provided guidance to inspectors to audit and inspect licensee implementation of the interim compensatory measures (ICMs) required by the February 25th Order. The inspections associated with Temporary Instruction 2515/148 were completed at the Braidwood Station. Additionally, table-top security drills were conducted at several licensees to evaluate the impact of expanded adversary characteristics and the ICMs on licensee protection and mitigative strategies. Information gained and discrepancies identified during the audits and drills were reviewed and dispositioned by the Office of Nuclear Security and Incident Response. For calendar year 2003, the NRC will continue to monitor overall safeguards and security controls, conduct inspections, and resume force-on-force exercises at selected power plants. Should threat conditions change, the NRC may issue additional Orders, advisories, and temporary instructions to ensure adequate safety is being maintained at all commercial power reactors.

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

Sincerely,

/RA/

Ann Marie Stone, Chief Branch 3 Division of Reactor Projects Docket Nos. 50-456; 50-457 License Nos. NPF-72; NPF-77

Enclosure:

Inspection Report 50-456/03-02; 50-457/03-02 w/Attachment: Supplemental Information See Attached Distribution

DOCUMENT NAME: C:\MyFiles\Copies\Karen\ML031140547.wpd To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy OFFICE RIII NAME AMStone:dtp DATE 04/21/03 OFFICIAL RECORD COPY

REGION III==

Docket Nos: 50-456; 50-457 License Nos: NPF-72; NPF-77 Report Nos: 50-456/03-02; 50-457/03-02 Licensee: Exelon Generation Company, LLC Facility: Braidwood Station, Units 1 and 2 Location: 35100 S. Route 53 Suite 84 Braceville, IL 60407-9617 Dates: January 1 through March 31, 2003 Inspectors: S. Ray, Senior Resident Inspector N. Shah, Resident Inspector D. Funk Jr., Physical Security Inspector D. Nelson, Radiation Specialist R. Skokowski, Senior Resident Inspector, Byron T. Tongue, Reactor Engineer Observers: C. Roque-Cruz, Reactor Inspector P. Smith, Illinois Department of Nuclear Safety Approved by: Ann Marie Stone, Chief Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000456/2003-002, 05000457/2003-002; Exelon Generation Company, LLC; on 01/01-03/31/03, Braidwood Station; Units 1 & 2. Operability Evaluations.

This report covers a 3-month period of baseline resident inspection and announced baseline inspections on radiation protection and physical security. The inspections were conducted by Region III inspectors, and the resident inspectors assigned to the Braidwood and Byron sites.

One Green finding, which was also determined to involve a violation of Nuclear Regulatory Commission (NRC) requirements, was identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter 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. Inspector-Identified and Self-revealed Findings

Cornerstone: Barrier Integrity

Green.

A finding of very low safety significance was identified through a self-revealing event when the licensee failed to incorporate the correct instantaneous current trip setpoint following maintenance and replacement of a safety-related, motor operated valves molded case circuit breaker. This was a recurrent issue based on similar problems occurring in September 2001 and February 2002, and thus was related to the cross-cutting area of problem identification and resolution.

This finding was considered more than minor, because it affected the availability of the 1B and 1D reactor containment fan coolers, which mitigate containment temperature and pressure increases following a design basis accident, and thus could affect the integrity of the containment barrier. The finding was of very low safety significance because it did not represent an actual reduction of the atmospheric pressure control function of the reactor containment because redundant equipment was available and the breaker could have been rapidly reset. The inspectors identified a Non-Cited Violation for the inadequate corrective action from a previous event. (Section 1R15)

Licensee-Identified Violations

No findings of significance were identified.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near full power throughout most of the inspection period, except that power was briefly reduced to about 84 percent on January 12, 2003, for turbine steam valve testing.

On March 17, 2003, Unit 1 started a gradual coastdown toward a scheduled refueling outage.

Power had reached about 94 percent by the end of the inspection period.

On February 2, 2003, the licensee sought and was granted a Notice of Enforcement Discretion (NOED) to permit continued operation past the Limiting Condition of Operation time stated in Technical Specification (TS) 3.5.2. The licensee requested the NOED in order to complete repairs to the 1B residual heat removal (RH) pump.

Unit 2 operated at or near full power throughout the inspection period, except that power was briefly reduced to about 86 percent on February 16, 2003, for turbine steam valve testing, and power was briefly reduced to about 90 percent on March 2, 2003, for load following.

1R04 Equipment Alignment

.1 Partial Walkdown

a. Inspection Scope

The inspectors performed partial walkdowns of the accessible portions of trains of risk significant mitigating system equipment. These walkdowns were performed when the redundant trains or other related equipment were unavailable due to planned or emergent maintenance. The inspectors utilized the valve and electric breaker checklists listed in the Attachment to verify that the components were properly positioned and that support systems were lined up as needed. The inspectors also examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors reviewed outstanding work orders (WOs) and condition reports (CRs) associated with the train to verify that those documents did not reveal issues that could affect train function. The inspectors used the information in the appropriate sections of the TS and the Updated Final Safety Analysis Report (UFSAR) to determine the functional requirements of the system.

The inspectors verified alignment of the following trains:

• the 1B essential service water (SX) train on January 6, 2003;

• the 1B chemical and volume control (CV) train on January 13, 2003;

• the 1A RH train on January 28, 2003; and

• the 1A safety injection (SI) train on February 4, 2003.

b. Findings

No findings of significance were identified.

.2 Complete Walkdown

a. Inspection Scope

During the week ending March 21, 2003, the inspectors conducted a system alignment inspection of the Unit 1 CV system. This system was selected because it plays an important mitigating system role and also includes aspects of initiating events and barrier integrity. The inspection consisted of the following activities:

• a walkdown of the system in the auxiliary building using the mechanical and electrical lineup checklist to verify proper alignment, component accessibility, availability, and current condition;

• a review of recent CRs to verify that there were no current operability concerns;

• a review of open WOs to verify that there were no conditions impacting availability and that deficiencies had been identified;

• a selective review of temporary and permanent modifications installed on the system within the last two years; and

• a selective review of system abnormal operating procedures to verify whether system alignment was properly controlled.

Documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Fire Protection Walkdowns

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of fire fighting equipment, the control of transient combustibles and ignition sources, and on the condition and operating status of installed fire barriers. The inspectors selected fire areas for inspection based on their overall contribution to internal fire risk, as documented in the Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate a plant transient, or their impact on the plants ability to respond to a security event. The inspectors used the documents listed in the Attachment to verify that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and that fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors verified that minor issues identified during the inspection were entered into the licensees corrective action program.

The following areas were inspected by walkdowns:

• the 1A and 2A SX pump rooms on January 8, 2003;

• the 1A CV pump room on January 15, 2003;

• the 1B RH pump room on January 29, 2003;

• the 1A SI pump room on February 4, 2003;

• the 1A containment spray pump room on February 11, 2003;

• the 1A and 1B diesel generator rooms on February 20, 2003;

• the 2A and 2B diesel generator rooms on February 20, 2003;

• the 1B and 2B SX pump rooms on February 25, 2003; and

• the 1A RH pump room on March 13, 2003.

b. Findings

No findings of significance were identified.

.2 Fire Drill Observation

a. Inspection Scope

On March 12, 2003, the inspectors observed the licensees response to a simulated fire on the Unit 1 turbine generator and exciter. The inspectors chose to observe this scenario because an actual turbine fire would likely result in a turbine trip initiating event.

Prior to the drill, the inspectors performed a walkdown of the simulation with the licensees Fire Marshall to identify the specific hazards and the drill objectives to be addressed by the fire brigade. The inspectors also performed a walkdown of the appropriate fire brigade storage cage to verify that the fire fighting equipment was properly maintained. During the drill, the inspectors observed the following specific aspects of the fire brigade response:

• the fire brigade responded in a timely manner upon being notified of the fire;

• the brigade members protective equipment was in good working order and was properly donned;

• fore hoses were properly laid out, charged and tested prior to entering the fire area of concern;

• fire fighting equipment was properly staged and used; and

• the fire brigade leader maintained appropriate command and control and had good radio communications with the responders.

The inspectors also attended the post-drill critique to determine whether the pre-planned drill scenario was appropriately followed and whether the specific drill acceptance criteria were met. Documents reviewed during this inspection are listed in the

.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

During the week of March 10, 2003, the inspectors evaluated the licensees controls for mitigating external and internal flooding. Specifically, the inspectors performed the following:

• reviewed the licensees design basis documents to identify the design basis for flood protection and to identify those areas susceptible to external or internal flooding;

• reviewed the licensees probabilistic risk assessment results for external and internal flooding;

• reviewed selected maintenance records based on the assessment results;

• reviewed selected abnormal operating procedures for identifying and mitigating flooding events;

• reviewed selected maintenance records and surveillances for auxiliary building floor drains; and

• inspected the watertight doors and flood seals on March 13 and 14, 2003.

The inspectors also reviewed selected shift control room log entries and CRs to determine whether identified problems were being properly addressed via the licensees corrective actions program. Documents reviewed during this inspection are listed in the

.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

Quarterly Review of Requalification Testing and/or Training Activities

a. Inspection Scope

On January 15, 2003, the inspectors observed an operating crew during an out-of-the-box requalification examination on the simulator using the scenario listed in the Attachment. The inspectors evaluated crew performance in the areas of:

• clarity and formality of communications;

• ability to take timely actions in the safe direction;

• prioritization, interpretation, and verification of alarms;

• procedure use;

• control board manipulations;

• oversight and direction from supervisors; and

• group dynamics.

Crew performance in these areas was compared to licensee management expectations and guidelines as presented in the Exelon procedures listed in the Attachment.

The inspectors verified that the crew completed the critical tasks listed in the simulator guide. The inspectors also compared simulator configurations with actual control board configurations. For any weaknesses identified, the inspectors observed the licensee evaluators to verify that they also noted the issues and discussed them in the critique at the end of the session. The inspectors verified that minor issues identified during the inspection were entered into the licensees corrective action program.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the licensees overall maintenance effectiveness for risk-significant mitigating systems. This evaluation consisted of the following specific activities:

• observing the conduct of planned and emergent maintenance activities where possible;

• reviewing selected CRs, open WOs, and control room log entries in order to identify system deficiencies;

• reviewing licensee system monitoring and trend reports; and

• a partial walkdown of the selected system.

The inspectors also reviewed whether the licensee properly implemented the Maintenance Rule, 10 CFR 50.65, for the system. Specifically, the inspectors determined whether:

• the system was scoped in accordance with 10 CFR 50.65;

• performance problems constituted maintenance rule functional failures;

• the system had been assigned the proper safety significance classification;

• the system was properly classified as (a)(1) or (a)(2); and

• the goals and corrective actions for the system were appropriate.

The above aspects were evaluated using the maintenance rule program and other documents listed in the Attachment. The inspectors also verified that the licensee was appropriately tracking reliability and/or unavailability for the systems.

The inspectors reviewed the following systems:

• the component cooling system on February 10, 2003; and

• the SX system on March 3, 2003.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensees management of plant risk during emergent maintenance activities or during activities where more than one significant system or train was unavailable. The activities were chosen based on their potential impact on increasing the probability of an initiating event or impacting the operation of safety-significant equipment. The inspections were conducted to verify that evaluation, planning, control, and performance of the work were done in a manner to reduce the risk and minimize the duration where practical, and that contingency plans were in place where appropriate.

The licensees daily configuration risk assessments records, observations of operator turnover and plan-of-the-day meetings, and the documents listed in the Attachment were used by the inspectors to verify that the equipment configurations were properly listed, that protected equipment were identified and were being controlled where appropriate, and that significant aspects of plant risk were being communicated to the necessary personnel. The inspectors verified that the licensee controlled emergent work in accordance with the expectations in the procedures listed in the Attachment.

In addition, the inspectors reviewed selected issues that the licensee entered into its corrective action program, including minor issues identified by the inspectors, to verify that identified problems were being entered into the program with the appropriate characterization and significance.

The inspectors reviewed the following activities:

• planned maintenance on the 1A SX train during an auxiliary feedwater flow loop calibration on January 6, 2003;

• planned maintenance on the 1A CV train coincident with planned maintenance on the 1A and 1C reactor containment fan coolers (RCFCs) on January 13, 2003;

• planned maintenance on the 1B RH pump coincident with unplanned maintenance on the 0B train of control room ventilation on January 27, 2003;

• activities associated with an NOED to continue work on the 1B RH pump past the TS Limiting Condition for Operation time limit on February 2, 2003;

• planned maintenance on the 1A SI pump and the 1A and 1C RCFCs on February 5, 2003;

• planned maintenance on the 1A containment spray pump in conjunction with planned maintenance on all four auxiliary building supply fans on February 11, 2003;

• planned maintenance on the 1B SX pump in conjunction with planned maintenance on the auxiliary building ventilation supply fans on February 25, 2003; and

• planned maintenance on the 2A containment chiller bypass isolation valve 2SX147A on March 3 and 4, 2003.

On February 2, 2003, the licensee requested and was granted an NOED to continue work on the 1B RH pump past the Limiting Condition of Operation time stated in TS 3.5.2. During this period, the inspectors verified that the licensee had taken the required compensatory actions as stated in the licensees formal, written request for the NOED dated February 4, 2003. Specifically, the inspectors observed the licensees control of protected equipment; reviewed operator logs, and monitored control room and 1B RH pump work activities.

b. Findings

No findings of significance were identified.

With respect to the NOED, the inspectors will review the circumstances which caused the licensee to pursue the NOED. This is considered an Unresolved Item (URI 50-456/03-01). Additional information regarding this issue is discussed in Section 4OA5.2 of this report.

1R14 Personnel Performance Related to Non-routine Plant Evolutions and Events

a. Inspection Scope

On March 26, 2003, Unit 2 experienced a series of small reactor power excursions due to problems with level control in the 2B moisture separator reheater shell drain tank.

The inspectors verified that operator response to the first excursion had been timely and in accordance with procedures by review of control room logs and discussions with operators. The inspectors also observed control room and plant operator response to subsequent excursions.

The inspectors verified that reactor power had been reduced to slightly below the licensed power limit in case there were additional transients, that operators had diagnosed the cause of the transients, and that level control in the 2B shell drain tank had been stabilized by using the emergency level control valve. The inspectors attended meetings of the troubleshooting team evaluating the cause and corrective actions for the problems. The inspectors reviewed plant computer charts to verify that NRC guidance on maintaining reactor power within the steady state licensed power level had not been exceeded. Finally, the inspectors observed plant operators recovering the level control system back to normal on March 27, 2003.

This transient was considered a non-routine plant evolution because multiple simultaneous problems with the shell drain tank level control system made identification, diagnosis, and control of the problems difficult, and because failure to gain control of the level in a timely manner could have resulted in a rapid power reduction or trip transient.

The system experienced simultaneous failures of the 2B moisture separator reheater shell drain tank normal level control valve, emergency level control valve, high level alarm, and high/high level alarm. Documents reviewed as part of this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors evaluated plant conditions and selected CRs for risk-significant components and systems in which operability issues were questioned. These conditions were evaluated to determine whether the operability of components was justified. The inspectors compared the operability and design criteria in the appropriate section of the and UFSAR to the licensees evaluations presented in the CRs and documents listed in the Attachment to verify that the components or systems were operable. The inspectors also conducted interviews with the appropriate licensee system engineers to obtain further information regarding operability questions.

The inspectors reviewed the following operability evaluations and conditions:

• CR 140853 regarding whether TS required an adequate level in the condensate storage tanks to meet actual conditions during a shutdown and cooldown;

• CR 144947 regarding the trip setpoint on the breaker for valve 1SX016B;

• a question regarding whether the safety injection pumps could be considered operable during the time period when they were being used to fill an accumulator; and

• actions taken with regard to an Information Notice and Part 21 Notification on inadequately staked capscrews on RH pumps.

b. Findings

Introduction:

A finding of very low safety significance (Green) and Non-Cited Violation (NCV) was identified through a self-revealing event for inadequate corrective actions following the replacement of the electrical breaker for motor-operated valve 1SX016B.

The finding affected the reliability of the 1B and 1D RCFCs which are used to limit containment temperature and pressure following a design basis accident.

Description:

On February 18, 2003, the operators were performing a quarterly stroke test of valve 1SX016B in accordance with Braidwood operating surveillance requirement procedure 1BwOSR 5.5.8.SX-1B, Essential Service Water Train B Valve Stroke Quarterly Surveillance, Revision 5. This valve is the SX inlet valve for the 1B and 1D RCFCs. The valve failed to stroke in the open position during testing.

The licensee determined that the instantaneous current trip setpoint had been incorrectly set following the replacement of the valves breaker on August 27, 2002. This setpoint was designed to trip the breaker if the in-rush current immediately following valve operation was too high (i.e., locked rotor). The valve was successfully stroke tested following the valve replacement and during the first quarterly stroke test on November 25, 2002. However, the valve failed its second quarterly stroke test as stated above.

The licensee had similar problems (i.e., incorrect setpoint) with motor operated valves on September 10, 2001 and on February 25, 2002. These events were discussed in Section 1R19 of NRC Inspection Report 50-456/457/02-05. As stated in that report, it was possible for the instantaneous trip setpoint error band to overlap into the range of in-rush current experienced when the valve was operating normally. This meant that the valve could be successfully stroked depending on the normal variance in electrical bus voltage. This variance was not accounted for in the licensees stroke test. After the September 2001 event, the licensee had identified numerous valves that required a setpoint revision. However, the licensee had failed to correct the setpoints on all of the identified breakers during subsequent valve breaker maintenance, resulting in the February 2002 and 2003 events.

Analysis:

The inspectors determined that the failure to use the correct setpoint for the 1SX016B breaker was a performance deficiency warranting a significance evaluation in accordance with Inspection Manual Chapter 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on April 29, 2002. This finding was considered more than minor, because it affected the availability of the 1B and 1D RCFCs which mitigate containment temperature and pressure increases following a design basis accident and thus could affect the integrity of the containment barrier. The inspectors determined that this event also affected the cross-cutting area of Problem Identification and Resolution, because of the failure to take adequate corrective actions following two prior events in September 10, 2001, and February 25, 2002.

The inspectors completed a significance determination of this issue, using Inspection Manual Chapter 0609, Significance Determination Process, dated April 30, 2002, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, dated March 18, 2002. For the Phase 1 screening, the inspectors answered No to all three questions under the containment barrier cornerstone. The finding did not represent an actual reduction of the atmospheric pressure control function of the reactor containment because redundant equipment was available and the breaker could have been rapidly reset. Therefore, the event was considered of very low safety significance (Green). The finding was assigned to the Barrier Cornerstone for Unit 1.

Enforcement:

Criterion XVI of 10 CFR Part 50, Appendix B, requires measures be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Contrary to the above, the licensee failed to use the correct instantaneous current trip setpoint for the 1SX016B valve, after identifying that the existing setpoint was incorrect as a result of two earlier similar events on September 10, 2001 and on February 25, 2002. This is considered a violation.

However, this violation is associated with an inspection finding that is characterized by the Significance Determination Process as having very low risk significance (i.e., Green)and is being treated as a Non-Cited Violation, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 50-456/03-02-02). This violation is in the licensees corrective action program as CR 144947, Repeat Maintenance-1SX016B Breaker Tripped on Open Signal, dated February 18, 2003.

1R16 Operator Workarounds

a. Inspection Scope

On February 27, 2003, the inspectors accompanied a non-licensed operator performing a routine walkdown of the Unit 1 Turbine building. Specifically, the inspectors observed the operators activities to determine if any impediments existed that may constitute an operator workaround or challenge as defined by the licensee procedures listed in the

.

b. Findings

No findings of significance were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post maintenance testing activities associated with maintenance or modification of important mitigating, barrier integrity, and support systems to ensure that the testing adequately verified system operability and functional capability with consideration of the actual maintenance performed. The inspectors used the appropriate sections of the TS and UFSAR, as well as the documents listed in the

, to evaluate the scope of the maintenance; to verify that the post maintenance testing was performed adequately and demonstrated that the maintenance was successful; and to verify that operability was restored. The inspectors verified that minor issues identified during the inspection were entered into the licensees corrective action system.

Testing subsequent to the following activities was observed and evaluated:

• planned maintenance on the 1B RH pump on February 3, 2003;

• planned maintenance on the 1A SI pump on February 5, 2003;

• planned maintenance on the 1A containment spray pump on February 11, 2003;

• planned maintenance on the 1B SX pump on February 25, 2003;

• planned maintenance on valve 1FW035B on March 20, 2003; and

• planned maintenance on auxiliary feedwater pump room cooling fan 2VA00CA on March 21, 2003.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors witnessed selected surveillance testing and/or reviewed test data to verify that the equipment tested using the surveillance procedures met the TS, the UFSAR, and licensee procedural requirements, and demonstrated that the equipment was capable of performing its intended safety functions. The activities were selected based on their importance in verifying mitigating systems capability and barrier integrity.

The inspectors used the documents listed in the Attachment to verify that the testing met the frequency requirements; that the tests were conducted in accordance with the procedures, including establishing the proper plant conditions and prerequisites; that the test acceptance criteria were met; and that the results of the tests were properly reviewed and recorded.

The following tests were observed and evaluated:

• local leak rate testing of Unit 2 service air valves 2SA032 and 2SA033 on January 9, 2003;

• Unit 1 reactor coolant system resistance temperature detector alignment on January 17, 2003;

• testing of the 2B solid state protection system on January 30, 2003;

• local leak rate testing of the Unit 2 containment miniflow purge supply and exhaust penetrations;

• monthly testing of the 1B diesel generator on March 5, 2003; and

• once per 18 months testing of the bypassing of automatic trips on the 1B diesel generator on March 19, 2003.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

On January 15, 2003, the inspectors reviewed a temporary maintenance alteration to install a freeze seal isolation on the component cooling water supply to the Unit 2 spent fuel pool heat exchanger. This activity was chosen because a significant problem with the freeze installation could have resulted in a loss of Unit 2 component cooling which would have resulted in a reactor shutdown transient due to the loss of cooling water flow to the Unit 2 reactor coolant pump thermal barrier heat exchangers. The freeze seal was performed to support maintenance and was intended to be in place for less than 90 days, so a formal safety evaluation was not required.

The licensee had unsuccessfully attempted to establish a freeze seal in this same location on October 8, 2002. The inspectors review of that attempt was documented in Inspection Report 50-456/457/02-07, Section 1R23.

The inspectors reviewed the WO for the job, including the lessons learned from the October 8, 2002, freeze attempt, the engineering review for the installation, the engineering change to the original review to allow the work to be accomplished during plant operations, and the plant barrier impairment permits. The inspectors also walked down the piping where the freeze was to be installed before the work began, attended the high level awareness briefing, and observed portions of the work. In addition, the inspectors reviewed the operations contingency plan for potential failure of the freeze and attended shift turnover meetings where the contingencies were discussed. Finally, the inspectors verified that the operations temporary change tracking log was used to record the temporary change as required.

The inspectors verified that problems identified by the licensee during the freeze installation were entered into the corrective action system. As part of this inspection, the inspectors reviewed the documents listed in the Attachment.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

On January 15, 2003, the inspectors observed an operating crew during an out-of-the-box requalification examination on the simulator using the scenario listed in the

. This drill contained opportunities which the licensee had determined would count toward the Drill and Exercise Performance Indicator statistics. The inspectors ensured that the classification and notification opportunities had been predetermined and that adequate timing and success criteria had been established. The inspectors reviewed the licensees emergency plan implementation procedures to ensure that the proper classifications had been determined. The inspectors observed the scenario and the post-scenario critique to ensure that operator performance in emergency response had been properly assessed by the licensee evaluators.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control (71121.01) Plant Walkdowns, Radiological Boundary Verifications, and Radiation Work Permit Reviews

a. Inspection Scope

The inspectors conducted walkdowns of the radiologically restricted area to verify the adequacy of radiological boundaries and postings. Specifically, the inspectors walked down several radiation and high radiation area boundaries in the auxiliary, radwaste, and fuel handling buildings. Confirmatory radiation measurements were taken to verify that these areas were properly posted and controlled in accordance with 10 CFR Part 20, licensee procedures, and TSs. The radiation work permit for NRC general tours was reviewed for electronic dosemeter alarm set points and protective clothing requirements.

b. Findings

No findings of significance were identified.

Cornerstone: Public Radiation Safety

2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems (71122.01)

.1 Offsite Dose Calculation Manual (ODCM)

a. Inspection Scope

The inspectors reviewed the Radioactive Effluent Release Report for the year 2001, to verify that the radiological effluent program was implemented as described in the UFSAR and the ODCM. The inspectors reviewed changes made by the licensee to the ODCM as well as to the liquid and gaseous radioactive waste processing system design, procedures, or operation since the last inspection to verify that changes were documented in accordance with the requirements of the ODCM and the TSs.

b. Findings

No findings of significance were identified.

.2 Gaseous and Liquid Release Systems Walkdowns

a. Inspection Scope

The inspectors performed walkdowns of the major components of the gaseous and liquid release systems to verify that the current system configuration was as described in the UFSAR and the ODCM, and to observe ongoing activities and equipment material condition. This included radiation and flow monitors, demineralizers and filtration systems, compressors, tanks, and vessels. The inspectors also discussed the waste processing system operations and components with the cognizant system engineer to assess its overall operation.

b. Findings

No findings of significance were identified.

.3 Gaseous and Liquid Releases

a. Inspection Scope

The inspectors reviewed liquid and gaseous radioactive waste release records including radiochemical measurements to verify that appropriate treatment equipment was used, and that the radwaste effluents were processed and released in accordance with the ODCM. The inspector also verified that radioactive releases met the 10 CFR Part 20 requirements.

The inspectors reviewed the records of any releases made with inoperable effluent radiation monitors. The inspectors reviewed the licensees actions for those releases to ensure an adequate defense-in-depth was maintained against an unmonitored release of radioactive material to the environment.

b. Findings

No findings of significance were identified.

.4 Dose Calculations

a. Inspection Scope

The inspectors reviewed selected individual gaseous and liquid batch release records for the year 2002, the Annual Radiological Environmental Operating Report and the Radioactive Effluent Release Report for the year 2001, and years 2001 and 2002 monthly dose calculations to ensure that the licensee had properly determined the offsite dose to the public from radiological effluent releases, and to determine if any annual TS or ODCM (i.e., Appendix I to 10 CFR Part 50 values) limits were exceeded.

b. Findings

No findings of significance were identified.

.5 Air Cleaning Systems

a. Inspection Scope

The inspectors reviewed the most recent air cleaning system surveillance test results for containment purge, and the radwaste and auxiliary buildings exhaust ventilation systems activated carbon beds to ensure that test results were within the licensee's acceptance criteria. The inspectors also reviewed surveillance test results for the gaseous release systems to verify that the flow rates were consistent with UFSAR values.

b. Findings

No findings of significance were identified.

.6 Effluent Monitor Calibrations

a. Inspection Scope

The inspectors reviewed calibration records of liquid and gaseous point of discharge effluent radiation monitors to verify that instrument calibrations were within the required calibration frequency. The inspector also reviewed the current effluent radiation monitor alarm setpoint values for agreement with station requirements.

b. Findings

No findings of significance were identified.

.7 Counting Room Instrument Calibrations and Quality Control

a. Inspection Scope

The inspector reviewed the quality control records for radiochemistry instrumentation used to identify and quantitate radioisotopes in effluents, in order to verify that the instrumentation was calibrated and maintained as required by station procedures. This review included calibrations of gamma spectroscopy/spectrometry systems, liquid scintillation instruments, proportional counters, and associated instrument control charts.

The inspectors also reviewed the lower limit of detection determinations to verify that the radiochemical instrumentation and analysis conditions used for effluent analysis could meet the ODCM detection requirements.

b. Findings

No findings of significance were identified.

.8 Interlaboratory Comparison Program

a. Inspection Scope

The inspector reviewed the results of the year 2001 Interlaboratory Comparison Program along with the 2002 Radiochemistry Cross Check Program (Section

.7 ) in order to

evaluate the licensees capability to perform radiochemical measurements, and to assess the quality of radioactive effluent sample analyses performed by the licensee.

The inspectors reviewed the licensee's quality assurance evaluation of the Interlaboratory Comparison Program and associated corrective actions for any deficiencies identified.

b. Findings

No findings of significance were identified.

.9 Identification and Resolution of Problems

a. Inspection Scope

The inspector reviewed audits, self-assessments, and condition reports generated in 2002 to evaluate the effectiveness of the licensees self-assessment process in the identification, characterization, and prioritization of problems, and to verify that previous radiological instrumentation and effluent related issues were adequately addressed.

Condition reports that addressed radioactive treatment and monitoring program deficiencies were also reviewed to verify that the licensee had effectively implemented the corrective action program.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

40A1 Performance Indicator Verification (71151) Cornerstones: Mitigating Systems and Occupational Radiation Safety

.1 Reactor Safety Strategic Area

a. Inspection Scope

The inspectors reviewed documents listed in the Attachment to verify that the licensee had corrected reported performance indicators data, in accordance with the criteria in Nuclear Energy Institute 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 2. The following performance indicators were reviewed for the period of January 1, 2002, through December 31, 2002:

• unplanned scrams per 7000 critical hours and

• safety system unavailability, RH system.

b. Findings

No findings of significance were identified.

.2 Radiation Safety Strategic Area

a. Inspection Scope

The inspectors reviewed documents listed in the Attachment to verify that the licensee had corrected reported performance indicators data, in accordance with the criteria in Nuclear Energy Institute 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 2. The following performance indicator was reviewed:

• Public Radiation Safety Since no reportable elements were identified by the licensee for the 4th quarter of 2001 and 1st, 2nd and 3rd quarters of 2002 and, the inspectors reviewed the licensees data to verify that there were no occurrences concerning the public radiation safety cornerstone during those quarters.

b. Findings

No findings of significance were identified.

40A2 Identification and Resolution of Problems (71152)

.1 Cross-References to Problem Identification and Resolution Findings Documented

Elsewhere Section 1R15 discussed a NCV associated with a finding of very low safety significance (Green) for inadequate corrective actions following the replacement of the electrical breaker for motor-operated valve 1SX016B. This was a recurrent issue since similar problems (with similar breakers) had occurred in September 2001 and February 2002.

.2 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 licensees 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. Minor issues entered into the licensees corrective action system as a result of inspectors observations are generally denoted in the report or in the documents in the Attachment.

b. Findings

No finding of significance were identified.

.3 Annual Sample Review

Extent of Condition Review for Previous Violation Introduction Throughout the inspection period, the inspectors reviewed the licensees extent of condition investigation committed to in its letter from James D. von Suskil, Revised Response to a Notice of Violation, dated August 19, 2002. This letter was written in response to Violation 50-456/457/01-11-02 discussed in Inspection Report 50-456/457/01-11, Section 1R22. In the letter, the licensee stated that it would review design and safety analysis that formed the basis for TS values and have TS values as input parameters, to identify changes to TS input parameters and confirm that the changes have been properly implemented in surveillance and/or analysis, preserving the necessary margin to account for uncertainly in measurement of the changed parameters. Documents reviewed as part of this inspection are listed in the Appendix.

a. Effectiveness of Problem Identification

(1) Inspection Scope The inspectors reviewed the CR Action Tracking Items associated with the issue and verified that the licensee conducted a complete review of all TS values, determined which values were used as inputs to design calculations, determined which TS or design calculations had changed since original licensing, and determined whether these changed values preserved the necessary margin with appropriate allowance for measurement uncertainty.

(2) Issues The licensee limited its detailed review to only those TS parameters for which either the TS had changed or the design calculation had changed since original licensing. The licensees position was that the original TS and UFSAR parameters had sufficient margin for measurement uncertainty, either specifically discussed in the analysis, or implicitly assumed. The inspectors reviewed a sampling of the TS parameters which the licensee placed in this category and verified that most had margin for measurement uncertainty specifically discussed in the UFSAR and/or the associated NRCs Safety Evaluation Report. In addition, the inspectors noted that NRC Inspection Manual, Part 9900, stated that the TS limits are established with allowance for measurement tolerances already incorporated. The inspectors did identify one design calculation for which the associated TS parameters may not have had sufficient measurement tolerance incorporated as discussed below.

The paragraph entitled Inadvertent Spray Actuation, of Section 6.2.1.1.3 of the UFSAR stated that a calculation was performed to calculate the maximum outside to inside pressure differential of the containment following an inadvertent actuation of the containment spray system. A similar statement is contained in the Basis for TS 3.6.4, and in Section 6.2.1.1 of the Safety Evaluation Report.

The calculation apparently showed that the maximum containment differential pressure would be 3.48 pounds per square inch (psi) compared to a design differential of 3.5 psi. However, the documents indicate that an initial containment differential pressure of 0.0 psi was used as the input parameter for the calculation. Technical Specification 3.6.4 allows a containment differential pressure of as low as -0.1 psi (outside to inside). The inspectors were concerned that, if the initial containment pressure was at the minimum allowed at the beginning of the transient, containment outside to inside design differential pressure could be exceeded, especially since measurement uncertainty could result in an even more negative initial pressure.

The licensee could not find the original calculation to verify whether additional measurement uncertainty was included in the design calculation. The licensee issued CR 151931 which included an action to reconstruct the calculation. The inspectors had no immediate safety concern since; 1) the NRCs original Safety Evaluation Report stated that the initial conditions in the calculation were conservatively assumed and were acceptable, even though measurement uncertainty was not explicitly mentioned; 2) the licensees initial review of this issue indicated that the containment may be able to withstand a significantly higher outside to inside differential pressure than 3.5 psi; 3) the other input parameters of the highest allowed TS values of initial containment temperature and humidity and the lowest allowed TS value of containment spray temperature did not exist at the time of the inspection and would be unlikely to ever occur simultaneously; and 4) a containment failure due to inadvertent containment spray actuation, even if it were to occur, would not result in a significant release to the public unless an accident resulting in a release into containment preceded it. In that case, the containment differential pressure would probably be significantly above the initial condition apparently assumed in the analysis.

The licensee reviewed 120 separate TS parameters and identified a total of 7 parameters that were changed by TS amendments and for which the amendment application did not specifically address measurement uncertainty.

Four of those TSs had been amended in such a way that the margin to the design calculations had either not changed or had actually increased over the original values. Three of the TSs had been changed in such a way that the margin to the design calculations had been reduced or eliminated. For those three, the licensee could not identify any discussion of margin for measurement uncertainly in the amendment requests. The three TSs, along with the CRs written to evaluate them, were as follows:

• TS 3.9.5.1 for minimum RH flow in Mode 6, addressed in CR 151545;

• TS 3.7.1.1 for main steam safety valve setpoints, addressed in CR 151550; and

• TS 3.1.4.3 for control rod drop time, addressed in CR 151553.

The inspectors concluded that the licensees extent of condition review was sufficiently complete and detailed that problems similar to the violation discussed above would be identified.

b. Prioritization and Evaluation of Issues

(1) Inspection Scope For the missing design calculation and the three TS margin questions discussed above, the inspectors verified, through review of the CRs, other documents, and discussions with licensee engineering personnel, that no immediate safety concerns existed. The inspectors determined that the licensee had entered the issues into its corrective action system at the appropriate level, that the licensee had sufficiently addressed immediate operability questions, and that actions to evaluate and resolve the issues in a timely manner were underway.

(2) Issues No significant issues were identified.

4OA5 Other

.1 (Closed) Unresolved Item (URI) 50-456/457/00-11-02: Failure to Provide Adequate

Procedural Requirements. The unresolved item involved a change in security plan language of Revision 47 that added a new requirement allowing the transfer of searched material/equipment between protected areas at different sites. The language of the plan change did not adequately describe the methodology relating to the transportation of secure (searched) materials being transported from a licensee site to another licensee site. The wording was modified in Revision 50 of the licensees security plan. No violation of NRC requirements occurred.

.2 (Closed) URI 50-456/03-02-01: Circumstances Leading to a NOED for the 1B RH

Pump. Concerning the inspection of the NOED on the 1B RH pump discussed in Section 1R13 of this report, the issue was considered a URI for tracking purposes pending the inspectors review of the circumstances which led to the need for enforcement discretion. On March 31, 2003, the inspectors completed that review, including the documents listed in the Attachment, and determined that no violations of NRC requirements occurred. Therefore, the URI is closed.

4OA6 Meetings

.1 Exit Meeting

The inspectors presented the inspection results to Mr. J. von Suskil and other members of licensee management at the conclusion of the inspection on April 11, 2003. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

.2 Interim Exit Meetings

The results of the radiation protection inspection were presented to Mr. J. von Suskil at the conclusion of the inspection on January 10, 2003. The inspectors did not receive any information identified as proprietary during this inspection 23 Enclosure

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

J. von Suskil, Site Vice President

T. Joyce, Plant Manager

J. Bailey, Regulatory Assurance - NRC Coordinator

G. Baker, Site Security Manager

R. Blaine, Radiation Protection Manager

G. Dudek, Operations Manager

C. Dunn, Site Engineering Director

R. Gilbert, Nuclear Oversight Manager

B. Stoffels, Maintenance Manager

United States Nuclear Regulatory Commission

M. Chawla, Project Manager, Office of Nuclear Reactor Regulation

A. Stone, Chief, Reactor Projects Branch 3

LIST OF ITEMS

Opened

50-456/03-02-01 URI Circumstances Leading to a NOED for the 1B RH Pump (Section 4OA5.2)

50-456/03-02-02 NCV Failure of Valve to Stroke to the Open Position During Testing (Section 1R15)

Closed

50-456/457/00-11-02 URI Failure to Provide Adequate Procedural Requirements (Section 4OA5.1)

50-456/03-02-01 URI Circumstances Leading to a NOED for the 1B RH Pump (Section 4OA5.2)

50-456/03-02-02 NCV Failure of Valve to Stroke to the Open Position During Testing (Section 1R15)

Discussed

50-456/457/01-11-02 VIO Failure to Maintain an Adequate Test Control Program (Section 4OA2.3)

Attachment