IR 05000456/2004004

IR 05000456-04-004, 05000457-04-004, on 04/01/04 - 06/30/04; Braidwood Station, Units 1 & 2; Adverse Weather Protection and Operability Evaluations

ML042040470
Person / Time
Site:	Braidwood
Issue date:	07/20/2004
From:	Ann Marie Stone Division Reactor Projects III
To:	Crane C Exelon Generation Co, Exelon Nuclear
References
IR-04-004
Download: ML042040470 (54)

Text

uly 20, 2004

SUBJECT:

BRAIDWOOD STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000456/2004004; 05000457/2004004

Dear Mr. Crane:

On June 30, 2004, 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 July 7, 2004, with Mr. T. Joyce 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, two NRC-identified findings of very low safety significance, both of which involved violations of NRC requirements were identified. However, because the violations were of very low safety significance and because the issues were entered into the licensees corrective action program, the NRC is treating the findings as Non-Cited Violations in accordance with Section VI.A.1 of the NRCs Enforcement Policy.

If you contest the subject or severity of a 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, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Braidwood facility. In accordance with 10 CFR 2.390 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 05000456/2004004; 05000457/2004004 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-456; 50-457 License Nos: NPF-72; NPF-77 Report No: 05000456/2004004; 05000457/2004004 Licensee: Exelon Generation Company, LLC Facility: Braidwood Station, Units 1 and 2 Location: 35100 S. Route 53 Suite 84 Braceville, IL 60407-9617 Dates: April 1 through June 30, 2004 Inspectors: S. Ray, Senior Resident Inspector N. Shah, Resident Inspector C. Phillips, Senior Operator Licensing Examiner J. Cameron, Project Engineer T. Tongue, Project Engineer J. House, Radiation Specialist D. Nelson, Radiation Specialist Observers: P. Smith, Illinois Emergency Management Agency Resident C. Roque-Cruz, Reactor Engineer Approved by: Ann Marie Stone, Chief Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000456/2004004, 05000457/2004004; 04/01/04 - 06/30/04; Braidwood Station,

Units 1 & 2; Adverse Weather Protection and Operability Evaluations.

This report covers a 3-month period of baseline resident inspection and an announced baseline inspection on radiation protection. In addition, an inspection in accordance with Temporary Instruction (TI) 2515/156, Onsite Power System Operational Readiness, was conducted. The inspection was conducted by Region III inspectors and the resident inspectors. Two Green findings associated with two Non-Cited Violations were identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP 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: Initiating Events

Green.

The inspectors identified a finding of very low safety significance when unauthorized loose scaffold material was found in the Unit 2 transformer yard during a period of frequent high winds, severe thunderstorm warnings, and tornado watches.

Once identified to licensee management, the material was rapidly removed from the area. The causes for the finding were related to the cross-cutting areas of Human Performance, because operators failed to identify the material despite numerous walkdowns of the area using a procedure that specifically directed them to look for that type of material, and Problem Identification and Resolution because the implementation of corrective actions for two previous loss of offsite power events and a Non-Cited Violation, all involving loose material in the transformer yards, did not prevent this finding.

The finding was more than minor because it increased the likelihood of a loss of offsite power or reactor trip event. The finding was of very low safety significance because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions would not be available. This issue was determined to be a non-cited violation of Technical Specification 5.4.1.a for failure to follow procedures.

(Section 1R01.1)

Cornerstone: Barrier Integrity

Green.

The inspectors identified a finding of very low significance when they determined that the 0A hydrogen recombiner had been inoperable for at least 43 days, longer than its Technical Specifications allowed outage time of 30 days. The train was inoperable because of a combination of conditions which degraded it to the point where it could not be relied upon to perform its intended safety function. Specifically (1) the temperature controller for the reaction chamber temperature was erratic, causing unexpected trips of the heater breaker; (2) a procedure revision to direct operators to gradually bring up reaction chamber temperature by manually adjusting the temperature controller was not completed in a timely manner, nor was training held on the procedure; and (3) annunciators intended to alert operators to a trip of the heater breaker, or other malfunctions of the recombiner, were not functional. At the time the finding was identified, the temperature controller had already been replaced and tested, the procedure revision had been incorporated, and the repairs of the annunciators had been scheduled. The causes of this violation were related to the cross-cutting areas of Human Performance, because engineering personnel did not properly assess operability, and Problem Identification and Resolution, because untimely corrective actions resulted in the recombiner being inoperable for longer than the allowed outage time in the Technical Specifications.

The finding was more than minor because it affected the barrier integrity cornerstone objective of providing reasonable assurance that the physical containment barrier would protect the public from radio nuclide releases caused by accidents or events. The finding was of very low safety significance because the hydrogen recombiner system is not a significant contributor to the large early release frequency for pressurized water reactors with large dry containments. This issue was determined to be a non-cited violation of Technical Specification 3.6.8 for failure to maintain the hydrogen recombiner operable. (Section 1R15.1)

Licensee-Identified Violations

No findings of significance were identified.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near full power for the entire inspection period except that power was reduced to 85 percent from April 17 through April 19, 2004, for turbine and governor valve testing.

Unit 2 operated at or near full power for the entire inspection period except that power was reduced to 85 percent on May 15 for turbine and governor valve testing, and to about 85 percent on June 1, June 13, and June 27, 2004, for load following. Turbine and governor valve testing was also conducted during the June 27, 2004, load reduction.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness For Impending Adverse Weather Conditions

a. Inspection Scope

Between May 9 and May 23, 2004, the licensee entered its abnormal operating procedures for adverse weather seven times for thunderstorm warnings and tornado watches. The inspectors reviewed the licensees readiness and response to those conditions, conducted plant walkdowns, especially of outside areas near the transformers, and reviewed the corrective actions taken for previous issues identified in this area. Documents reviewed as part of this inspection are listed in the Attachment.

The inspectors verified that minor issues identified during this inspection were entered into the licensees corrective action program. This activity constituted one sample for this inspection requirement.

b. Findings

Introduction:

The inspectors identified a repeat Non-Cited Violation (NCV) of Technical Specifications (TS) 5.4.1.a having a very low safety significance (Green) for unauthorized storage of scaffold parts and other material inside of a designated material storage exclusion area around the Unit 2 transformers. This finding also involved the cross-cutting areas of Human Performance and Problem Identification and Resolution.

Description:

On about April 23, 2004, the licensee erected a significant amount of scaffolding around the Unit 2 station auxiliary transformers (SATs) and associated bus ducts from the transformers to the auxiliary building for scheduled work on the SATs.

On about May 7, 2004, the scaffolding around the SATs was removed, but the scaffolding around the bus ducts was left in place. The scaffolding pieces that had been around the SATs were left inside the transformer yard. Most of the pieces were in racks, but several pieces of platforms, ladders, wooden kick boards, etc. were left laying on the ground loose. The pieces were not tied down or secured; therefore, could become missiles during high winds or tornadoes. In addition, a rack of compressed gas cylinders was also left inside of the transformer yard exclusion area. The licensee had deferred the remaining work to remove the material due to manpower constraints.

On the evening of May 9, 2004, the operators received a thunderstorm warning, entered the appropriate abnormal operating procedures, and carried out the actions directed by those procedures. The next day, the inspectors noticed the loose scaffold parts, as well as the tall scaffold still erected around the buses, and asked the auxiliary power (AP)system engineer when the scaffolding was going to be removed. The engineer did not provide an answer.

The plant experienced adverse weather conditions (high winds, thunderstorm warnings, and tornado watches) on six more occasions between May 9 and May 23, 2004. On at least two of those occasions, when the plant operators notified the inspectors that they had entered the abnormal operating procedure, the inspectors reminded the operators that there was still a significant amount of scaffolding and scaffolding parts near the Unit 2 transformers.

As a result of two previous loss of offsite power events caused by loose material near the transformers (Licensee Event Reports [LERs] 05000457/1996-001-00 and 05000456/1998-003-00) as well as an NCV and associated Green finding (05000456/2000005-01), the licensee established Transformer Material Exclusion Areas around the Unit 1 and Unit 2 transformers. The administrative control procedures for the exclusion areas required, in part, that no material may be brought into or stored inside of the areas unless prior permission was received from the shift manager. The inspectors could find no record of such permission being granted for the storage of scaffold parts inside the exclusion area and, during an interview with a shift manager, he stated that he was not aware of any permission being granted. The outside of the areas were marked with placards stating the administrative requirement from an outdated plant procedure that had been superceded by a corporate procedure.

The inspectors determined that the licensee had at least 20 opportunities to identify the unauthorized material stored in the exclusion area. Each of the seven times the licensee entered 0BwOA ENV-1, Adverse Weather Conditions Unit 0, one of the steps directed by that procedure was to eliminate threats to offsite power sources by securing or removing any loose material and equipment from around the plant exterior that could impact offsite power availability. A note in the procedure specifically listed scaffold material as one of the types of materials that could present a hazard during high winds.

In addition, the 2B diesel generator (DG) was inoperable for the period of May 16 through May 21, 2004, while the scaffolding was in the exclusion area. As one of the compensatory actions for a DG being out of service, the operators normally conduct walkdowns of the switchyard and transformer areas to monitor the condition of the offsite power sources. By reviewing the operator logs, the inspectors identified at least thirteen occasions during that period where operators walked down the Unit 2 transformer yard.

On May 27, 2004, the inspectors walked down the area with the Maintenance Director and Mechanical Maintenance Manager to point out the specific concerns. As a result, the loose scaffold material was removed later that day. All of the remaining erected scaffolding and compressed gas cylinders were removed by May 29, 2004. The licensee issued Condition Report (CR) 224258 to document and track the issue. The licensee also issued CR 224281 to document the issue with the outdated procedure reference on the placards.

Analysis:

The inspectors determined that leaving loose scaffold material stored inside of the transformer exclusion area was a performance deficiency warranting a significance evaluation in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued June 20, 2003. The loose material near the Unit 2 transformers increased the likelihood of a unit trip or loss of an offsite power feed during high winds or tornadoes. The inspectors determined that the finding was more than minor because it:

(1) involved the protection against external factors and human performance attributes of the Initiating Events cornerstone; and

(2) affected the cornerstone objective of limiting the likelihood of those events that upset plant stability during power operations.

The inspectors determined that the finding also involved the cross-cutting area of Human Performance, in that the licensee missed numerous opportunities to self-identify the material during operator walkdowns of the area. The inspectors determined that the finding also involved the cross-cutting area of Problem Identification and Resolution because the corrective action of establishing material exclusion areas due to previous loss of offsite power (LOOP) events and a previous finding were not adequately implemented and a repeat finding was identified.

The inspectors determined that the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, because the finding was associated with an increase in the likelihood of an initiating event. The inspectors answered no to all the SDP Phase 1 Screening Worksheet questions in the Initiating Event column, therefore, the finding screened out as Green or of very low safety significance. Specifically, the inspectors determined that it was unreasonable to assume that the material could simultaneously affect both the SATs, which could affect the offsite power supply to mitigating equipment, and the main power transformers, which could cause a plant trip.

Enforcement:

Technical Specification 5.4.1.a stated that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Section 6 of that Regulatory Guide, Procedures for Combating Emergencies and Other Significant Events, specifically addressed the need to have procedures for acts of nature, including tornadoes. The licensee implemented that requirement, in part, with 0BwOA ENV-1, Adverse Weather Protection Unit 0. Step 3.b. of Revision 101 of 0BwOA ENV-1 directed operations and security personnel to eliminate threats to offsite power sources by securing or removing any loose material and equipment from around the plant exterior that could impact offsite power availability. Contrary to the above, on seven occasions between May 9 and May 23, 2004, the licensee implemented 0BwOA ENV-1 and did not secure or remove loose scaffold material in the Unit 2 transformer yard. Such material blowing into a transformer could have impacted offsite power or mitigating system availability. Because the failure to effectively implement procedure 0BwOA ENV-1 was of very low safety significance, has been corrected, and has been entered into the licensee corrective action program as CR 224258, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy.

(NCV 05000457/2004004-01)

.2 Readiness For Seasonal Susceptibilities

a. Inspection Scope

The inspectors reviewed the licensees seasonal preparations for operation during the summer months. This was primarily accomplished by verifying that the licensee had completed the requirements for summer readiness as documented in Exelon Nuclear Procedure OP-AA-108-109, Seasonal Readiness, Revision 1. The inspectors also reviewed the Updated Final Safety Analysis Report (UFSAR), TS, and other design-bases documents to identify those components that were at risk during the summer months due to high temperatures. The inspectors verified that the licensee had addressed these components in preparation for summer operation. In addition, the inspectors selected the following risk-significant support systems for specific review:

• Units 1 and 2 DG ventilation and jacket water subsystems; and

• Units 1 and 2 service water supply to the room and oil coolers for the emergency core cooling system (ECCS) pumps.

These components constituted two samples of this inspection requirement.

The inspectors also reviewed several CRs documenting problems with heat exchangers, room temperatures, or adverse weather control, to determine whether these issues were being properly addressed in the licensees corrective action program. The inspectors also verified that minor issues identified during these inspections were entered into the licensees corrective action program. Documents reviewed as part of this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Complete Walkdowns

a. Inspection Scope

The inspectors performed a complete system walkdown of the safety and risk-significant electrical power supplies to Units 1 and 2. This included: the Units 1 and 2 switchyard; main, unit, and system auxiliary transformers; DGs; and the associated electrical distribution to the safety and risk-significant 6.9 kilovolt (kV) and 4.1 kV electrical buses and 480 volt (V) motor control centers. This walkdown represented one inspection sample. This system was selected because it was considered both safety and risk-significant in the licensees probabilistic risk analysis.

In addition to the walkdown, the inspectors reviewed the following:

• selected abnormal and emergency operating procedures concerning a LOOP;

• the UFSAR, TS, and other selected design bases documentation regarding offsite and onsite electrical distribution and LOOP events;

• outstanding and/or completed temporary or permanent modifications to the system; and

• outstanding system work orders (WOs).

The inspectors also reviewed several selected CRs to verify that issues were being properly addressed in the licensees corrective actions program. The inspectors also verified that minor issues identified during this inspection were entered into the licensees corrective action program. Documents reviewed as part of this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 Partial Walkdowns

a. Inspection Scope

The inspectors performed partial walkdowns of the accessible portions of risk-significant system trains during periods when the train was of increased importance due to redundant trains or other equipment being unavailable. The inspectors utilized the valve and electric breaker checklists, as well as other documents 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 WOs and 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 UFSAR to determine the functional requirements of the system. The inspectors also reviewed the licensees identification of and the controls over the redundant risk-related equipment required to remain in service. The inspectors verified that minor issues identified during this inspection were entered into the licensees corrective action program. The inspectors completed four samples of this requirement by walkdowns of the following trains:

• 2B DG while the 2A DG was unavailable during planned maintenance;

• 2B diesel-driven auxiliary feedwater (AF) pump while it was protected equipment during planned maintenance on the auxiliary building ventilation system;

• 2A DG fuel oil and lube oil subsystems while the 2B DG was unavailable during an overhaul; and

• 1B residual heat removal (RH) train in preparation for planned maintenance on the 1A RH train.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Quarterly Area 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 or their potential to impact equipment which could initiate a plant transient. The inspectors used the documents listed in the 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 inspectors completed nine samples of this inspection requirements during the following walkdowns:

• 2B DG and fuel oil tank rooms, zones 9.1-2 and 9.1-4;

• 346 foot elevation auxiliary building general area, zone 11.2-0;

• 2B DG during planned maintenance (including hot work), zone 9.1-2;

• Unit 1 auxiliary electrical equipment room, zone 5.5-1;

• Unit 2 auxiliary electrical equipment room, zone 5.5-2;

• 1B diesel-driven AF pump room, zone 11.4A-1;

• 2B diesel-driven AF pump room, zone 11.4A-2;

• Unit 1 lower cable spreading rooms, zones 3.2B-1, 3.2C-1, and 3.2D-1; and

• Unit 2 lower cable spreading rooms, zones 3.2B-2, 3.2C-2, and 3.2D-2.

b. Findings

No findings of significance were identified.

.2 Annual Fire Brigade Drill

a. Inspection Scope

The inspectors observed the licensees response to a simulated fire on the 2A component cooling water pump located in the 346 foot elevation of the auxiliary building. The inspectors chose this scenario because the 2A component cooling pump is a safety-related mitigating component. Prior to the drill, the inspectors performed a walkdown of the simulation with the Fire Marshall to identify the specific hazards and drill objectives to be addressed by the fire brigade. Because there were no fire equipment cages in the auxiliary building, the inspectors also observed the licensees controls for bringing in fire fighting equipment from the turbine building fire cages.

During the drill, the inspectors observed the following specific aspects of the fire brigade response:

• the fire brigade responded in a timely manner;

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

• fire 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 had appropriate command and control and had good radio communication with the responders and the control room.

The inspectors also attended the post-drill critique to determine whether the pre-planned drill scenario was followed and whether the drill acceptance criteria was met.

Documents reviewed during this inspection are listed in the Attachment. This review constituted one sample of this inspection requirement.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

Semi-Annual Inspection of Internal Flood Protection Barriers and Procedures

a. Inspection Scope

The inspectors conducted a semi-annual review of internal flooding vulnerabilities and protective measures for the following areas:

• Unit 1 engineered safety features switchgear rooms, and

• Unit 2 engineered safety features switchgear rooms.

This review constituted two samples of this inspection requirement.

These areas contained risk-significant equipment and were susceptible to flooding based on the licensees risk analysis. The inspection included a review of the internal flooding design features described in the UFSAR and in the licensees auxiliary building flood level calculations. The inspectors performed a walkdown of the selected areas to observe the condition of doors, floor drains, sump pumps, or other flood mitigating components credited in the licensees calculation. The inspectors also determined whether assumptions used in the calculation, such as flooding sources or operator actions to identify/mitigate flooding, were reasonable. Documents reviewed as part of this inspection are listed in the Attachment. The inspectors verified that minor issues identified as part of this inspection were entered into the licensees corrective action program.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

Quarterly Review of Testing/Training Activity

a. Inspection Scope

The inspectors observed an operating crew performance during an evaluated simulator out-of-the-box scenario. The inspectors evaluated crew performance in the following areas:

• 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. This inspection constituted one sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

Routine Inspection

a. Inspection Scope

The inspectors reviewed the licensees overall maintenance effectiveness for risk-significant initiating event, mitigating, and barrier integrity 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;

• attending Plant Heath Committee, Management Review, and Nuclear Safety Review Board meetings where the status and plans for degraded systems were discussed;

• a partial walkdown of the selected system; and

• interviews with the appropriate system engineers.

The inspectors also reviewed whether the licensee properly implemented the Maintenance Rule, 10 CFR 50.65, for each 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 completed two samples in this inspection requirement by reviewing the following systems:

• AP system and

• process radiation monitoring system.

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, observations of work in progress, 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; that work was being conducted properly; 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 to verify that identified problems were being entered into the program with the appropriate characterization and significance. The inspectors verified that minor issues identified during these inspections were entered into the licensee corrective action program.

The inspectors completed five samples by reviewing the following activities:

• planned maintenance on the 2A DG coincident with the planned out-of-service of the 2SX016B and 2SX027B isolation valves for the 2B and D containment chillers;

• planned maintenance on the Unit 2 SATs and Unit 2 switchyard bus-tie breaker 14-15;

• emergent maintenance on the 2B DG during planned maintenance on the Unit 2 SATs;

• emergent troubleshooting and maintenance on the 114 instrument inverter following a trip of the inverter; and

• troubleshooting and testing following a 2A AF pump failure to start.

b. Findings

No findings of significance were identified.

1R14 Operator Performance During Non-Routine Evolutions and Events

a. Inspection Scope

The inspectors completed two samples by observing the following events:

• cross tying the Units 1 and 2 safety-related 4 kV buses during planned maintenance on the Unit 2 SATs and

• unplanned loss of instrument bus 114.

For these events, the inspectors observed control room activities, interviewed plant operators and other personnel, and reviewed plant records including control room logs, operator turnovers, and CRs. The inspectors verified that personnel errors did not contribute to the events, that the events were entered into the licensees corrective action program if appropriate, and that the operators response to the events were in accordance with the applicable plant procedures. Documents reviewed as part of this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

.1 Operability of the 0A Hydrogen Recombiner

a. Inspection Scope

As a result of the semiannual review for trends discussed in Section 4OA2.2 of this report, the inspectors evaluated the operability of the 0A hydrogen recombiner after failures of the reaction chamber heater and annunciators. Documents reviewed as part of this inspection are listed in the Attachment. This evaluation constituted one sample of this inspection requirement.

b. Findings

Introduction:

The inspectors identified a NCV of TS 3.6.8 having a very low safety significance (Green) for conditions where the 0A hydrogen recombiner reaction chamber heater may have tripped during operations and operator identification of the problem may have been delayed because the recombiners annunciators were not functioning.

Description:

On March 3, April 23, April 27, and May 3, 2004, the reaction chamber heater breaker tripped during running of the 0A hydrogen recombiner for surveillance and troubleshooting. For the last three of the four trips, neither the local nor main control room annunciators for the recombiner worked, so that operators were not always immediately aware of the problem. During troubleshooting following the second and third trips, the licensee discovered that the output of the reaction chamber temperature controller was erratic and sluggish, but did not replace it until May 7, 2004, after the fourth failure. The licensee determined that the problem with the temperature controller was the most probable cause for all four of the heater breaker trips.

In the CR written for the first failure on March 3, 2004, the Shift Manager evaluated the recombiner as being operable because it functioned correctly for the remainder of the surveillance after the heater breaker was reset. In addition, the CR stated that the operating procedure for the recombiner should be changed to gradually bring the reaction chamber up to operating temperature, by manually adjusting the temperature controller, rather than letting the controller operate automatically up to its preset value.

The inspectors identified several problems with the licensees operability evaluation:

• The recombiner was determined to be operable after the first failure despite the fact that the cause of the failure was not known. The surveillance was evaluated as being completed successfully despite the fact that the heater breaker had tripped during heatup.

• The assessment that it was acceptable to rely on manual operation of the temperature controller was made before the operating procedure was revised to direct that type of operation. In addition, the operators had not been trained on manual operation, and the need to gradually bring up temperature was known only to some of the operators. The NRC generally does not allow credit for manual operation of equipment designed to operate automatically unless, among other requirements, procedures are in place and appropriate training has been completed. The operating procedure was not revised until May 3, 2004.

• On April 5, 2004, operators questioned the operability of the recombiner with this manual action and the Design Engineering Manager evaluated it as being operable based on a statement in the NRC Safety Evaluation Report (SER) that stated that the recombiner was started manually and locally operated and controlled. The licensee based its operability assessment primarily on one isolated statement in the SER without considering several statements in the UFSAR which clearly showed that the temperature controller was designed to heat up the gas automatically to the preset value rather than depend on manual operation:

• UFSAR Section 6.2.5.2.1 stated that, once the recombiner was started by opening isolation valves and locally actuating the start switch, The gas temperature is raised by the heaters until the hydrogen-oxygen reaction starts. As the gas temperature in the reaction chamber approaches the preset point of 1325EF [Fahrenheit], the gas heater automatically reduces its power demand to maintain that preset temperature.

• Section 6.2.5.5 of the UFSAR further stated that the recombiner control panels include adequate automatic controls and alarms to allow the unattended operation of the recombiners, and that these controls include an automatic temperature controller for the regulation of the air temperature in the recombiner chamber, and

• Section 7.3.1.1.16 of the UFSAR stated that the recombiners are designed to operate automatically and unattended after manual startup.

These statements clearly show that the temperature controller was designed to heat up the gas automatically to the preset value rather than depend on manual operation.

• In the operability evaluations, the licensee did not consider that monitoring of the recombiner was further degraded by the loss of the annunciators. The sentence following the statement about local control and operation of the recombiner in the SER, stated, sufficient local alarms are provided to indicate if the hydrogen recombiners are not performing properly, and this information also is indicated in the main control room by a common trouble alarm. As discussed above, UFSAR Section 6.2.5.5 also stated that the recombiner control panels include adequate automatic controls and alarms to allow the unattended operation of the recombiners. The operating procedure only required that the recombiner be checked once each shift after it had stabilized. With no annunciators, the recombiner could have been tripped for about 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> before being discovered.

With the heaters tripped, the reaction chamber temperature would not have remained high enough for the hydrogen-oxygen recombination reaction to take place.

• The licensee did not consider the effect of the additional heat input from the hydrogen-oxygen reaction that would be taking place in a accident when it determined that the recombiner could be considered operable with the sluggish reaction chamber temperature controller. With that additional heat input, the sluggish controller would probably have a harder time limiting temperature rises and a heater breaker trip from high chamber temperature would be more likely.

• When the operating procedure was changed to direct manual operation of the temperature controller to gradually bring up reaction chamber temperature, the procedure writer did not consider the fact that the system would no longer be heated up automatically to the preset temperature of 1325EF as described in the UFSAR. This introduced new failure modes of the equipment due to misoperation. Section B.3.6.8 of the TS Basis for the recombiners stated, the only credible failure involves loss of power, blockage of the internal flow, missile impact, etc. The design basis of the system apparently did not consider human error probability and that probability was not evaluated as part of the procedure change.

The inspectors determined that, although the recombiner might also be considered inoperable during periods when one or two of the conditions described above existed, the combination of all three of the conditions simultaneously (erratic temperature controller causing heater breaker trips, lack of procedures and training for manual operation of the temperature controller, and lack of annunciation to indicate heater breaker trips) clearly made the 0A hydrogen recombiner incapable of meeting its safety function because it was degraded to the point where it would not operate reliably as described in the UFSAR and SER. The time period when all three of the conditions existed simultaneously was from at least March 21, 2004, through May 3, 2004, a period of at least 43 days. This was longer than the 30 day allowed outage time in the TS.

Analysis:

The inspectors determined that the finding associated with inoperability of the 0A hydrogen recombiner was due to a performance deficiency, caused by a combination of inadequate corrective actions and incorrect operability determinations, warranting a significance evaluation. The inspectors concluded that the finding was greater than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on June 20, 2003. The inspectors answered yes to minor question Number 4 because the finding was associated with the containment barrier integrity cornerstone attribute of risk important systems function and affected the cornerstone objective of providing reasonable assurance that the physical containment barrier would protect the public from radio nuclide releases caused by accidents or events. The function of the recombiners was to remove hydrogen from the containment, post accident, before it threatened containment integrity by reaching highly flammable concentrations. The finding also affected the cross-cutting areas of Human Performance, because incorrect operability determinations were made, and Problem Identification and Resolution, because the cause of the heater breaker trips was not identified and corrected until the recombiner had been inoperable longer than its allowed outage time.

The inspectors completed a significance determination of this issue using IMC 0609, Significance Determination Process (SDP), dated March 18, 2002. Using the Phase 1 screening worksheet, the inspectors answered yes to question 3 in the Containment Barriers column because the finding caused an actual reduction of the atmospheric pressure control function of the reactor containment. After consulting with the regional Senior Reactor Analyst, the inspectors conducted a Phase 2 analysis using IMC 0609 Appendix H, Containment Integrity Significance Determination Process. The finding was screened as Green because it did not affect the core damage frequency and failure of a hydrogen recombiner did not have a significant effect on the large early release frequency for a pressurized water reactor with a large dry containment. Therefore, this finding was considered to be of very low safety significance (Green) and was assigned to the Barrier Integrity cornerstone of both units (since the 0A hydrogen recombiner could serve either unit).

Enforcement:

Technical Specification 3.6.8 stated that two hydrogen recombiners shall be operable, in Modes 1 and 2. With one recombiner inoperable, the recombiner must be restored to operable status within 30 days or the unit must be placed in Mode 3 (hot standby) within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Contrary to the above, between March 21, 2004, and May 3, 2004, the 0A hydrogen recombiner was inoperable due to a combination of an erratic automatic reaction chamber temperature controller causing heater breaker trips, a lack of a procedure or training for operating the temperature controller manually, and a lack of annunciation to alert the operators to a trip of the heater breaker. During that time period both units operated in Mode 1 in excess of 30 days and were not placed in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of exceeding 30 days. The operating procedure was revised on May 3, 2004, and the erratic temperature controller was replaced and successfully tested on May 7, 2004. The annunciator problem was scheduled to be repaired in December 2004. The licensee entered the problems with the recombiner into its corrective action program as CRs 207859, 213227, 216732, 220805, and 229190.

Because this violation was of very low safety significance and it was entered into the licensees corrective action program, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy.

(NCV 05000456/2004004-02; 05000457/2004004-02)

.2 Other 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 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 completed five samples by reviewing the following operability evaluations and conditions:

• CR 210520 regarding storage of the Unit 1 curved wall hoist;

• CR 208767 regarding excessive air found during venting of ECCS piping;

• the effect on control room habitability analysis following the movement of several thousand gallons of sodium hypochloride into the plant protected area;

• the operability of the Units 1 and 2 miscellaneous electrical equipment room ventilation systems following several, room high temperature events; and

• CR 115863 regarding control room ventilation outside air damper being found installed backwards.

b. Findings

No findings of significance were identified.

1R16 Operator Workarounds

.1 Review of Selected Operator Workarounds

a. Inspection Scope

The inspectors reviewed whether ongoing issues with the operation of the Unit 1 containment leak detection sump constituted an operator workaround. Specifically, due to blockage in the sumps weir slot, the sump required frequent flushing in order to maintain its operability. The blockage had resulted in frequent, false indications of increased containment leakage, resulting in nuisance alarms that potentially challenged the control room staff.

The inspectors reviewed the UFSAR, TS, and the documents listed in the Attachment, as well as interviews with operators, and determined that the issue was not an operator workaround. Although the sump was the primary method of detection, the operators had other indications of containment leakage which were operable and credited in the TS. The inspectors verified that minor issues identified during this inspection were entered into the licensees corrective action program. This inspection was considered to be one sample of the operator workarounds inspection requirement.

b. Findings

No findings of significance were identified.

.2 Semiannual Review of Operator Workarounds

a. Inspection Scope

The inspectors completed a semi-annual review of the cumulative effects of operator workarounds. The inspectors verified that the workarounds did not have a significant effect on the reliability, availability, or the ability to correctly operate mitigating systems and that they would not significantly increase operator response time to transients and accidents. The inspectors also verified that the licensee had plans and schedules established to correct the conditions in a reasonable time. In addition to operator workarounds, the inspectors reviewed operability evaluations, operator challenges, and temporary modifications for cumulative effects. The inspectors reviewed the documents listed in the Attachment as part of this inspection. This review represented one inspection sample.

b. Findings

No findings of significance were identified.

1RST Post-Maintenance and Surveillance Testing - Pilot (71111.ST)

a. Inspection Scope

The inspectors reviewed post-maintenance and surveillance testing activities associated with important mitigating, barrier integrity, and support systems to ensure that the testing adequately verified system operability and functional capability. For post-maintenance testing, the inspectors used the appropriate sections of the TS and UFSAR, as well as the WOs for the work performed, to evaluate the scope of the maintenance and to verify that the post-maintenance testing was performed adequately, demonstrated that the maintenance was successful, and that operability was restored.

For surveillance testing, the inspectors verified that the testing met the TS, the UFSAR, and licensee procedural requirements, and demonstrated that the equipment was capable of performing its intended safety functions. The inspectors verified 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 was met; and that the results of the tests were properly reviewed and recorded. The activities were selected based on their importance in verifying mitigating systems capability and barrier integrity. The inspectors verified that minor issues identified during the inspection were entered into the licensees corrective action program. Documents reviewed as part of this inspection are listed in the

.

Note that this inspection is a pilot for a proposed consolidated procedure combining the previous Post-Maintenance Testing (71111.19) and Surveillance Testing (71111.22)procedures.

Four samples were completed by observing post-maintenance testing after the following activities:

• planned maintenance on the 1A condensate/condensate booster pump;

• repair of a speed sensing circuit on the 2B DG;

• completion of a planned maintenance overhaul on the 2B DG; and

• troubleshooting and replacement of a start interlock relay on the 2A AF pump.

Four samples were completed by observing and evaluating the following surveillance tests:

• 2B solid state protection system bimonthly testing;

• Unit 1 main steam safety relief valve lift testing;

• 2B DG monthly operability testing; and

• 2A AF pump quarterly testing (this test failed due to failure of the pump to start from the main control room).

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed a temporary modification involving installation of a jumper to simulate that the feedwater isolation test reset switch on panel 2PA11J was in the normal position. The inspectors verified the change did not have an unanalyzed affect on the safety functions of important safety systems. As part of this inspection, the inspectors reviewed the 10 CFR 50.59 screening, appropriate UFSAR sections, and the TS, to verify that system operability/availability was not affected. The inspectors verified that the installation was consistent with the design documents, that the installation was properly flagged, and that the appropriate post-installation testing was accomplished.

Documents reviewed as part of this inspection are listed in the Attachment. This inspectors completed one sample of this inspection requirement.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors observed operator performance during an evaluated simulator drill. The inspectors observed event classification, NRC notifications, and other aspects of drill performance, to identify weaknesses and ensured that the licensee evaluators had also noted the same weaknesses. The inspectors verified that deficiencies noted during the drill, by either the inspectors or licensee evaluators, were entered into the licensees corrective action program. The inspectors also attended the post drill critique for the simulator crew. Documents reviewed as part of this inspection are listed in the

. This activity constituted one inspection sample.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

.1 Review of Licensee Performance Indicators for the Occupational Exposure Cornerstone

a. Inspection Scope

The inspectors reviewed the licensees records to determine if any occupational exposure control cornerstone performance indicator (PI) event had been identified during the previous five calender quarters (none were identified). If PI events had been identified, the inspectors would have determined whether or not the conditions surrounding the events had been evaluated and whether or not identified problems had been entered into the corrective action program for resolution. This review represented one sample.

b. Findings

No findings of significance were identified.

2. Plant Walkdowns and Radiation Work Permit (RWP) Reviews

a. Inspection Scope

The inspectors walked down and surveyed (using an NRC survey meter) selected areas in the Unit 1 and Unit 2 auxiliary buildings to verify that the prescribed RWP, procedure, and engineering controls were in place, that licensee surveys and postings were complete and accurate, and that air samplers were properly located. This represented one sample.

b. Findings

No findings of significance were identified.

2OS3 Radiation Monitoring Instrumentation and Protective Equipment (71121.03)

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed the UFSAR to identify applicable radiation monitors associated with transient high and very high radiation areas including those used in remote emergency assessment. This represented one sample.

The inspectors identified the types of portable radiation detection instrumentation used for job coverage of high radiation area work, other temporary area radiation monitors currently used in the plant, continuous air monitors associated with jobs with the potential for workers to receive 50 mrem committed effective dose equivalent (CEDE),whole body counters, and the types of radiation detection instruments utilized for personnel release from the radiologically controlled area. This represented one sample.

The inspectors verified calibration, operability, and alarm setpoint (if applicable) of the following instruments:

• IPM-8 Whole Body Frisking Monitor;

• .

Eberline Model 6112 Teletector;

• Eberline PM-7 Portal Monitors; and

• Bicron Model RSO-50E Ionization Chamber.

The inspectors determined what actions were taken when, during calibration or source checks, an instrument was found significantly out of calibration (greater than 50 percent)and determined possible consequences of instrument use since last successful calibration or source check. The inspectors also reviewed the licensees 10 CFR Part 61 source term reviews to determine if the calibration sources used are representative of the plant source term and alarm setpoints of instruments used for personnel release reflected plant source term. This represented one sample.

b. Findings

No findings of significance were identified.

.2 Problem Identification and Resolution

a. Inspection Scope

The inspectors reviewed a Check-In Self-Assessment Report on radiation monitoring instrumentation and protective equipment to verify that identified problems were entered into the corrective action program for resolution. Event reports involving internal exposures >50 mrem CEDE were reviewed to determine if the affected personnel were properly monitored utilizing calibrated equipment and if the data was analyzed and internal exposures properly assessed in accordance with licensee procedures. This represented one sample.

The inspectors reviewed CRs related to exposure significant radiological incidents that involved radiation monitoring instrument deficiencies since the last inspection in this area. Staff members were interviewed and corrective action documents were reviewed to verify that follow-up activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk. This represented one sample.

The inspectors determined if the licensees self-assessment activities were identifying and addressing repetitive deficiencies or significant individual deficiencies in problem identification and resolution. This represented one sample.

b. Findings

No findings of significance were identified.

.3 Radiation Protection Technician Instrument Use

a. Inspection Scope

The inspectors verified the calibration expiration and source response check currency on radiation detection instruments staged for use and observed radiation protection technicians for appropriate instrument selection and self-verification of instrument operability prior to use. This represented one sample.

b. Findings

No findings of significance were identified.

.3 Self-Contained Breathing Apparatus (SCBA) Maintenance and User Training

a. Inspection Scope

The inspectors reviewed the status and surveillance records of SCBAs staged and ready for use in the plant and inspected the licensees capability for refilling and transporting SCBA air bottles to and from the control room and operations support center during emergency conditions. The inspectors determined if control room operators and other emergency response and radiation protection personnel were trained and qualified in the use of SCBAs (including personal bottle change-out). The inspectors verified that individuals on each control room shift crew, and individuals from designated department were currently assigned emergency duties (e.g., onsite search and rescue duties). This represented one sample.

The inspectors reviewed the qualification documentation for personnel designated to perform maintenance on the vendor-designated vital components, and the vital component maintenance records over the past 5 years for several SCBA units currently designated as ready for service. The inspectors also ensured that the required, periodic air cylinder hydrostatic testing was documented and up to date, and that the Department of Transportation required retest air cylinder markings were in place for these units. The inspectors reviewed the onsite maintenance procedures governing vital component work including those for the low-pressure alarm and pressure-demand air regulator and licensee procedures, and the SCBA manufacturers recommended practices to determine if there were inconsistencies between them. This represented one sample.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

Cornerstones: Mitigating Systems and Barrier Integrity Reactor Safety Strategic Area

a. Inspection Scope

The inspectors reviewed the documents listed in the Attachment to verify that the licensee had corrected reported PI data, in accordance with the criteria in NEI [Nuclear Energy Institute] 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 2. The data reported by the licensee was compared to a sampling of control room logs, CRs, and other sources of data generated since the last verification. The inspectors verified that minor issues identified during the inspection were entered into the licensees corrective action program. The inspectors completed four samples by verifying the following PIs:

Unit 1

• safety system unavailability - emergency AC [alternating current] power system for the period of April 1, 2003, through March 31, 2004; and

• reactor coolant system leakage for the period of April 1, 2003, through March 31, 2004.

Unit 2

• safety system unavailability - emergency AC power system for the period of April 1, 2003, through March 31, 2004; and

• reactor coolant system leakage for the period of April 1, 2003, through March 31, 2004.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Additionally, the inspectors reviewed all new CRs on a daily basis as part of the semiannual trending review. Minor issues entered into the licensees corrective action program as a result of the inspectors observations are generally denoted in the Attachment. These activities were part of normal inspection activities and were not considered separate samples.

b. Findings

No finding of significance were identified.

.2 Semiannual Review for Trends

a. Scope

The inspectors reviewed all CRs (approximately 2500) generated during the time period of December 2003 through May 2004 in an attempt to identify potential trends. This inspection was part of the requirements of Inspection Procedure 71152 for monitoring plant status but was not considered an inspection procedure sample. Documents reviewed which indicated previously unrecognized trends are listed in the Attachment.

The inspectors verified that minor issues identified during this inspection were entered into the licensees corrective action program. The screening was accomplished as follows:

• CRs dealing with company policies, administrative issues, and other minor issues were eliminated as being outside the scope of this inspection;

• CRs dealing with instrument calibration trends were eliminated because that program was recently evaluated as part of the biennial Problem Identification and Resolution Inspection and found to be acceptable;

• the remaining CRs were sorted into broad categories as part of the daily screening;

• for the semiannual inspection, the CRs in the broad categories were further sorted into groups involving the same equipment, the same issue, or the same program;

• single CRs with no repeat occurrences or common issues were eliminated;

• the remaining groups were screened for potential common cause issues and considered potential trends;

• the inspectors eliminated groups of CRs that discussed NRC-identified trends from previous inspection activities;

• the inspectors eliminated groups of CRs that discussed strictly programmatic problems because the inspection requirement was primarily for equipment problems and human performance issues;

• the inspectors removed groups of CRs that discussed security issues, those may be reviewed and documented as necessary in a separate report during a future inspection by a security specialist;

• the inspectors eliminated groups of CRs where their review indicated that duplicate CRs had been written for the same event or failure;

• the inspectors eliminated groups of CRs where a sudden increase in the number of CRs generated was due to a special licensee initiative to specifically look for issues in a certain area;

• the inspectors obtained lists of all licensee common cause investigations initiated in the last year, all CRs in which the title indicated a trend or potential trend, and all systems in the maintenance rule (a)(1) status, these were considered licensee-identified trends, and CRs associated with those issues were removed for possible future reviews of the effectiveness of corrective actions for those trends;

• the remaining groups, considered potential unidentified trends, were provided to the licensee for discussion in case there was extenuating information that the inspectors were not aware of; and

• groups of CRs remaining after all of the above screening were considered trends which the licensee had failed to identify.

b. Finding and Observations One finding of very low safety significance (Green) involving a NCV of NRC requirements was identified. However, that finding is documented in detail in Section 1R15.1 of this report.

The inspectors determined that licensee employees were writing CRs with a low threshold, that employees at all levels of the organization were writing CRs, and that CRs were written for all issues of significance. The largest group of CRs were written for employee-identified industrial safety issues, one indication of a safety conscious work environment.

The inspectors determined that the licensee had identified the majority of trends. The licensee had initiated about 40 common cause analysis actions for identified trends in the last year and had written about 40 other CRs to evaluate other trends or potential trends to determine if a common cause evaluation was necessary. The licensee-identified trends were identified by a combination of the work groups involved with the issues, department or station corrective action program coordinators, department managers, and the nuclear oversight group, indicating that multiple groups were looking for trends.

The inspectors identified the following trends that had not been previously identified and/or adequately assessed by the licensee:

• Repeated problems with reaction chamber heater breakers tripping and annunciators being inoperable on the 0A hydrogen recombiner (CRs 207859, 213227, and 216732). On March 3, April 23, April 27, and May 3, 2004, the reaction chamber heater breaker tripped during running of the 0A hydrogen recombiner. In addition, for the last three of the four trips, neither the local nor main control room annunciators for the recombiner worked, so that operators were not always immediately aware of a problem. On May 7, 2004, a problem was discovered with the temperature controller for the heater, and it was replaced and successfully tested. The inspectors determined that the problem with the temperature controller was the most probable cause for all four of the failures. The annunciator problem was scheduled to be repaired in December 2004. The licensee documented each failure in CRs but did not classify the problems as an adverse trend or initiate a common cause analysis. The inspectors determined that this issue was more than minor and that the hydrogen recombiner was inoperable for longer than the allowed outage time in the TSs. As a result of this inspection, the licensee initiated CR 229190 to further evaluate this issue. This issue, and the associated finding, was discussed in detail in Section 1R15.1 of this report.

• Repeated problems with the cranking time delay relay on the 0B diesel-driven fire pump (CRs 79011; 129245; and 188766). On October 15, 2001, October 28, 2002, and December 1, 2003, the 0B fire pump failed annual tests of the cranking system. In each case the problem was found to be with a time delay relay and the relay was replaced each time. Although the licensee referenced the earlier failures in each subsequent CR, it did not classify the issue as an adverse trend nor did it initiate a common cause analysis to evaluate why the same relay was failing repeatedly. This was considered a minor issue in that the pump was degraded but still available and the licensee demonstrated that the engine would have reliably started despite the cranking problems. As a result of this inspection, the licensee initiated CR 229448 to review the issue as a potential adverse trend.

• Blocked incore detector thimble tubes on both units (CRs 131365, 185036, 187512, 193763, 195016, and 213819). There have been numerous blocked incore detector thimbles discovered in the last two operating cycles on both units. Efforts to replace thimble tubes during refueling outages were not effective, in that, many of the replaced tubes quickly became reblocked in the next operating cycle. The licensee had not initiated a common cause analysis for the repeated problems. This was considered a minor issue because the number of blocked tubes never reached the threshold where adequate core monitoring was not possible and no midcycle unit shutdowns were required. In addition, although the licensee had not identified the issue as an adverse trend, it had identified that earlier corrective actions had not been effective and had planned further corrective actions for the next refueling outages on both units.

As a result of this inspection, the licensee initiated CR 229041 to review the issue as a potential adverse trend.

.3 Annual Sample

Open CRs Older Than 2 Years Introduction The inspectors selected CRs that had action assignments that remained open for greater than two years for review of the licensees problem identification and resolution program. This sample was selected to verify that the licensee was giving adequate priority to timely completion of corrective actions. Documents reviewed as part of this inspection are listed in the Attachment. This activity constituted one sample of this inspection requirement.

a.

Prioritization and Evaluation of Issues

(1) Inspection Scope The inspectors considered the licensees evaluation and disposition of performance issues, and application of risk insights for prioritization of issues.

(2) Issues The inspectors determined that licensee corrective actions were based on a qualitative assessment of risk. For the issues reviewed, the inspectors did not find any discrepancies with the apparent risk and the categorization assigned by the licensee.

Pending corrective actions did not impact the immediate operability of associated equipment.

b.

Effectiveness of Corrective Actions

(1) Inspection Scope The inspectors reviewed multiple CRs to determine if the CRs addressed generic implications and that corrective actions were appropriately focused to correct the problem.

(2) Issues The inspectors determined that completed corrective actions identified in the CRs appeared to be adequate and were focused on the apparent cause of each condition. In many cases (for example CRs 3316 and 102884) the pending corrective actions addressed followup assessments (i.e., Effectiveness Reviews) to verify the adequacy of completed corrective actions.

4OA3 Event Followup

The inspectors completed two inspection samples in this area.

.1 Licensee Event Report Review

(Closed) LER 05000456/2004-001-00; 05000457/2004-001-00: Licensed Maximum Power Level Exceeded Due to Inaccuracies in Feedwater Ultrasonic Flow Measurements This event was previously discussed in IR 05000456/2004003; 05000457/2004003, Section 4OA3.4, and was dispositioned as a licensee-identified NCV in that report. At the time of that report, the LER had not yet been issued. The inspectors reviewed the LER and did not identify any new concerns.

.2 Illinois Seismic Event

a. Inspection Scope

On June 28, 2004, the central Illinois area experienced an earthquake of 4.5 on the Richter Scale centered 10 miles northwest of Ottawa, Illinois which was about 35 miles northwest of the Braidwood facility. Plant personnel felt the event but no seismic annunciators or other unusual responses were observed. The inspectors responded to the site and performed the following activities:

• interviewed operations personnel regarding their actions;

• reviewed control room indications;

• reviewed log entries;

• walked down safety-related and other risk-significant areas of the plant; and

• reviewed licensee procedure requirements for response to a seismic event.

Documents reviewed as part of this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified. No plant damage was observed by either plant personnel or the inspectors.

4OA4 Cross-Cutting Aspects of Findings

.1 The finding described in Section 1R01.1 of this report had, as one of its causes, a

human performance deficiency, in that, operators failed to identify loose scaffold material in the Unit 2 transformer material exclusion area despite numerous documented opportunities where the area was walked down using a procedure that specifically called for looking for that type of material.

.2 The finding described in Section 1R01.1 of this report also had, as another one of its

causes, a problem identification and resolution deficiency, in that, the licensee corrective actions following two LOOP events and an NCV due to loose material near the transformer yards were not adequate to prevent recurrence of unauthorized loose material being in the Unit 2 transformer year during several periods of high winds and tornado watches.

.3 The finding described in Section 1R15.1 of this report had, as one of its causes, human

performance deficiencies, in that, the Shift Manager and Design Engineering Manager failed to consider all of the design features described in the UFSAR and SER when evaluating the operability of the 0A hydrogen recombiner. As a result, the recombiner was improperly determined to be operable when, in fact, it was not.

.4 The finding described in Section 1R15.1 of this report also had, as another one of its

causes, a problem identification and resolution deficiency, in that, the licensee corrective actions following identification of problems with the temperature controller and the annunciators of the 0A hydrogen recombiner were not completed in a timely manner.

As a result, the recombiner was inoperable for longer than the allowed outage time in the TS.

4OA5 Other

Offsite Power System Operational Readiness (Temporary Instruction (TI) 2515/156)

a. Inspection Scope

The inspectors performed an operational readiness review of the offsite power system (OPS) in response to TI 2515/156, Offsite Power System Operational Readiness.

The inspectors reviewed licensee maintenance records, event reports, corrective action documents and procedures, and interviewed station engineering, maintenance, and operations staff. Specifically, the inspectors gathered and reviewed licensee data supporting the following NRC requirements:

• Appendix A to 10 CFR Part 50, General Design Criterion 17, Electrical Power Systems, to minimize the likelihood of losing offsite power on loss of the generating unit;

• Appendix B to 10 CFR Part 50, Criterion III, Design Control, to confirm the design interface between the nuclear power plant (NPP) and the regional transmission operator (RTO);

• Criterion XVI, Corrective Actions, to confirm the licensees assessment of the industry operating experience from the August 14, 2003 grid event;

• licensee TS for determining operability of the OPS;

• the licensees assumptions used in the station blackout (SBO) analysis performed per 10 CFR 50.63, Loss of All Alternating Current Power, to determine an acceptable coping time; and

• the licensees requirements for assessing risk when performing work on the OPS or the emergency onsite power systems per 10 CFR 50.65(a)(4).

The inspectors also assessed the licensees implementation of applicable operating experience as well as corrective action documents to ensure issues were being identified at an appropriate threshold, assessed for significance, and appropriately dispositioned. The inspectors verified that minor issues identified during this inspection were entered into the licensees corrective action program. Documents reviewed for this TI are listed in the Attachment. This activity was outside of the baseline inspection program and was therefore not considered a sample. The TI is considered complete for Unit 1 and Unit 2.

b. Observations and Findings

No findings of significance were identified. No immediate operability issues were identified during the inspection. In accordance with the TI 2515/156 reporting requirements, the inspectors provided the required data in the work sheets provided with the TI to the headquarters staff for further analysis.

4OA6 Meetings

.1 Exit Meeting

The inspectors presented the inspection results to Mr. T. Joyce and other members of licensee management at the conclusion of the inspection on July 7, 2004. 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

An interim exit was conducted for:

• Radiation Protection inspection with Mr. M. Pacilio on May 14, 2004.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. Joyce, Site Vice President

K. Polsen, Plant Manager

G. Dudek, Operations Director

C. Dunn, Site Engineering Director

R. Gilbert, Nuclear Oversight Manager

J. Moser, Radiation Protection Manager

E. Stefan, Acting Regulatory Assurance - NRC Coordinator

E. Wriggly, Maintenance Director

Nuclear Regulatory Commission

S. Burgess, Senior Reactor Analyst

A. Stone, Chief, Reactor Projects Branch 3

LIST OF ITEMS

Opened

05000457/2004004-01 NCV Failure to Secure or Remove Loose Scaffold Material in the Unit 2 Transformer Yard (Section 1R01.1)

05000456/2004004-02; NCV 0A Hydrogen Recombiner Inoperable for Longer Than

05000457/2004004-02 TS Allowed Outage Time (Section 1R15.1)

Closed

05000457/2004004-01 NCV Failure to Secure or Remove Loose Scaffold Material in the Unit 2 Transformer Yard (Section 1R01.1)

05000456/2004004-02; NCV 0A Hydrogen Recombiner Inoperable for Longer Than

05000457/2004004-02 TS Allowed Outage Time (Section 1R15.1)

05000456/2004-001-00; LER Licensed Maximum Power Level Exceeded Due to

05000457/2004-001-00 Inaccuracies in Feedwater Ultrasonic Flow Measurements (Section 4OA3)

Discussed

05000456/2000005-01 NCV Failure to Follow Adverse Weather Requirements (Section 1R01.1)

05000457/1996-001-00 LER Inadequate Control of Staged Roofing Materials Leads to a Loss of Offsite Power due to a Loss of Both Unit 2 Station Auxiliary Transformers (Section 1R01.1)

Attachment

05000456/1998-003-00 LER Loss of Offsite Power Event due to an Electrical Fault Caused by Material Dislodged by High Winds (Section 1R01.1)

Attachment