IR 05000266/2004006

IR 05000266-04-006, IR 05000301-04-006, on 07/01/2004 - 09/30/2004, Point Beach Nuclear Plant, Units 1 and 2, NRC Integrated Report, Operator Workarounds

ML042960320
Person / Time
Site:	Point Beach
Issue date:	10/20/2004
From:	Reynolds S Division Reactor Projects III
To:	Koehl D Nuclear Management Co
References
IR-04-006
Download: ML042960320 (39)

Text

ber 20, 2004

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000266/2004006; 05000301/2004006

Dear Mr. Koehl:

On September 30, 2004, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Point Beach Nuclear Plant, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on October 1, 2004, with Mr. James McCarthy 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 finding of very low safety significance was identified. The finding did not involve a violation of NRC requirements.

In addition to the routine NRC inspection and assessment activities, Point Beach performance is being evaluated quarterly as described in the Annual Assessment Letter - Point Beach Nuclear Plant, dated March 4, 2004. Consistent with Inspection Manual Chapter (IMC) 0305, Operating Reactor Assessment Program, plants in the multiple/repetitive degraded cornerstone column of the Action Matrix are given consideration at each quarterly performance assessment review for (1) declaring plant performance to be unacceptable in accordance with the guidance in IMC 0305; (2) transferring to the IMC 0350, Oversight of Operating Reactor Facilities in a Shutdown Condition with Performance Problems, process; and (3) taking additional regulatory actions, as appropriate. On July 29, 2004, the NRC reviewed Point Beach operational performance, inspection findings, and performance indicators during the third quarter of 2004. Based on this review, we concluded that Point Beach is operating safely. We determined that no additional regulatory actions, beyond the already increased inspection activities and management oversight, are currently warranted. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Steven A. Reynolds, Acting Director Division of Reactor Projects Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27

Enclosure:

Inspection Report 05000266/2004006; 05000301/2004006 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-266; 50-301 License Nos: DPR-24; DPR-27 Report No: 05000266/2004006; 05000301/2004006 Licensee: Nuclear Management Company, LLC Facility: Point Beach Nuclear Plant, Units 1 and 2 Location: 6610 Nuclear Road Two Rivers, WI 54241 Dates: July 1 through September 30, 2004 Inspectors: P. Krohn, Senior Resident Inspector M. Morris, Resident Inspector R. Alexander, Radiation Specialist J. Giessner, Reactor Engineer A. Klett, Reactor Engineer Approved by: P. Louden, Chief Branch 5 Division of Reactor Projects

SUMMARY OF FINDINGS

IR 05000266/2004006, 05000301/2004006; 07/01/2004 - 09/30/2004; Point Beach Nuclear

Plant, Units 1 & 2; Operator Workarounds.

This report covers a 3-month period of baseline resident inspection and an announced radiation protection (71122) inspection for the Point Beach Nuclear Plant, Units 1 and 2. The inspections were conducted by five inspectors: a radiation specialist inspector, two resident inspectors, and two reactor engineers assisting the resident inspectors. One Green finding that was not a violation of NRC requirements and one unresolved item (URI) 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. 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-Revealing Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified a workaround regarding the operation of the Unit 1 residual heat removal (RHR) system heat exchanger bypass flow control valve in automatic mode during a shutdown loss-of-coolant-accident (LOCA). The primary cause of this finding was related to the cross-cutting area of problem identification and resolution in two respects. First, the initial extent-of-condition review did not consider the impact of the issue on shutdown plant operations. Second, following initial instrumentation and control (I&C) troubleshooting efforts, a corrective action item was not assigned to operations personnel to evaluate the issue as a potential operator workaround (OWA). This contributed to a 3-month delay in completing the evaluation.

The finding is greater than minor because it affected the equipment performance attribute of the Reactor Safety Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events. The finding was considered to be of very low safety significance (Green) because it did not degrade short term (safety injection (SI)) decay heat removal capability or reactivity control; result in a design or qualification deficiency or an actual loss of safety function; or involve internal or external initiating events. The finding did not involve a violation of regulatory requirements. The licensee has entered this finding into its corrective action program. In addition, the finding was reviewed by the licensees Operator Workaround Committee and the Committee classified the problem as an operator challenge in accordance with site procedures. (Section 1R16.1)

• To Be Determined. The inspectors identified an Unresolved Item concerning the effects of supplying power from a 125-volt direct current (VDC) safety-related battery to Units 1 and 2 safe shutdown instrumentation necessary for monitoring reactor decay heat removal without a battery charger being aligned to the associated direct current (DC)bus. The issue was corrected with a procedure revision and did not represent an immediate safety concern; however, it will be considered a URI pending NRC review of the licensees extent-of-condition and potential impact evaluations, actions not completed by the end of this inspection period. (Section 4OA2.1)

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at full power and remained there until August 12, 2004, when power was reduced to 98 percent because of problems with the feedwater leading edge flow meter (LEFM). Unit 1 returned to full power later the same day and remained there until August 19 when power was reduced to 95 percent for turbine-driven auxiliary feedwater (AFW)pump testing. Unit 1 returned to full power on August 20 and remained there until August 29 when power was reduced to 98 percent for recurring LEFM problems. Unit 1 returned to full power the same day and remained there until September 4 when power was again reduced to 98 percent for LEFM problems. Later on September 4, power was reduced to 67 percent for turbine stop valve testing. Unit 1 power was increased to 98 percent on September 5 and returned to 100 percent on September 10 when the LEFM was repaired. Unit 1 remained at full power through the end of the inspection period.

Unit 2 began the inspection period at full power and remained there until July 24, 2004, when power was reduced to 68 percent for crossover steam dump, turbine stop valve, governor valve, and atmospheric steam dump testing. Unit 2 returned to full power on July 25 and remained there until August 13 when power was reduced to 91 percent for repair of the fifth stage B feedwater heater. Unit 2 returned to full power later the same day and remained there until the end of the inspection period with the exception of brief periods of operation at 98 percent power on August 20 and 27 for AFW pump testing and on September 9 for a turbine-driven AFW pump oil change and subsequent post-maintenance test.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R04 Equipment Alignment

.1 Partial System Walkdowns

b. Inspection Scope

The inspectors performed three partial walkdowns of accessible portions of risk-significant systems to evaluate the operability of the selected systems. The inspectors utilized valve and electrical breaker checklists (CLs), tank level books, plant drawings, and selected operating procedures to determine if the components were properly positioned and supported the systems as needed. The inspectors also examined the material condition of the components and observed operating equipment parameters to determine if there were any obvious deficiencies. The inspectors reviewed completed work orders (WOs) and calibration records associated with the systems to determine if those documents revealed issues that could affect component or train function. The inspectors used the information in the appropriate sections of the Final Safety Analysis Report (FSAR) to determine the functional requirements of the system. Documents reviewed during this inspection are listed in the attachment to this report. These observations constituted three quarterly inspection samples.

The inspectors verified the alignment of the following systems:

• Unit 1 Condensate and Feedwater System on September 13, 2004;

• Unit 1 and 2 Common Sections of the Chemical and Volume Control (CV)

System on September 28, 2004; and

• Units 1 and 2 125-VDC Batteries on September 22, 2004.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Walkdown of Selected Fire Zones

a. Inspection Scope

The inspectors conducted walkdowns 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 10 fire areas for inspection based on the areas overall fire risk contribution, as documented in the licensees Individual Plant Examination of External Events, the areas potential to impact equipment which could initiate a plant transient, or the areas impact on the plants ability to respond to a security event. The inspectors used the documents listed in the attachment to this report to determine if fire hoses and extinguishers were in their designated locations and available for immediate use, fire detectors and sprinklers were unobstructed, transient material loading was within the analyzed limits, and fire doors, dampers, and penetration seals were in satisfactory condition. These observations constituted 10 quarterly inspection samples.

The following areas were inspected by walkdowns:

• Fire Zone 783, G-04 Radiator Room;

• Fire Zone 770, G-03 Diesel Room;

• Fire Zone 773, G-03 Switchgear Room;

• Fire Zone 775, G-04 Diesel Room;

• Fire Zone 777, G-04 Switchgear Room;

• Fire Zone 552, Service Water (SW) Pump Room;

• Fire Zone 553, Circulating Water (CW) Pump Room;

• Fire Zone 554, CW Pump House Corridor;

• Fire Zone 555, CW Pump House Valve Gallery; and

• Fire Zone 691, Warehouse #2.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

.1 External Flood Protection

a. Inspection Scope

During the week of September 20, 2004, the inspectors reviewed external flooding design bases documents, flooding mitigation equipment, risk analyses, and current configurations and strategies to determine the licensees ability to mitigate external flooding hazards. The inspectors walked down or reviewed documents in the following areas to assess the overall readiness of flood protection barriers and equipment:

• CW Pump House and Wave Barrier Locations;

• Emergency Diesel Generator 3 and 4 Building;

• Gas Turbine and Switchyard grounds;

• Main Transformer areas; and

• Cable Manholes 1-10, 14-20, Z-066A-D, and Z-067A.

The inspectors focused on the material condition of flood protection equipment and flood barriers. The inspectors reviewed alarm response procedures and licensee efforts to determine lake levels and monitor manhole conditions. Procedural actions to mitigate potential flooding were compared to the analysis of record. The inspectors reviewed several corrective action program documents (CAPs) associated with external flooding concerns as well as current and pending corrective actions (CAs) to address submerged cables. This included a review of design changes associated with installing a submersible pump in safety-related manholes 1 and 2. This observation constituted one quarterly inspection sample.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

a. Inspection Scope

On August 31, 2004, the inspectors observed the performance of the operating crew during simulator training. The inspectors also reviewed an unexpected simulator response during the scenario and the simulator configuration to determine if simulator modeling was reflective of actual plant conditions. This observation constituted one quarterly inspection sample.

The inspectors evaluated crew performance in the areas of:

• clarity and formality of communications;

• understanding of the interactions and function of the operating crew during an emergency;

• prioritization, interpretation, and verification of actions required for emergency procedure use and interpretation;

• oversight and direction from supervisors; and

• group dynamics.

Crew performance in these areas was compared to licensee management expectations and guidelines as presented in Nuclear Plant Procedures Manual Procedure (NP) 2.1.1, Conduct of Operations, Revision 1.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors performed an issue/problem-oriented review of the systems listed below, completing two maintenance effectiveness inspection samples. The inspectors reviewed repetitive maintenance activities to assess maintenance effectiveness, including maintenance rule activities, work practices, and common cause issues.

Inspection activities included, but were not limited to, the licensee's categorization of specific issues, including evaluation of performance criteria, appropriate work practices, identification of common cause errors, extent of condition, and trending of key parameters. Additionally, the inspectors reviewed implementation of the Maintenance Rule (10 Code of Federal Regulations (CFR) 50.65) requirements, including a review of scoping, goal-setting, performance monitoring, short-term and long-term CAs, functional failure determinations associated with reviewed CAPs, and current equipment performance status.

For the systems reviewed, the inspectors reviewed significant WOs and CAPs to verify that failures were properly identified, classified, and corrected, and that unavailability time had been properly calculated. The inspectors reviewed documents listed in the attachment to this inspection report to determine if minor discrepancies in the licensees maintenance rule reports were corrected. These observations constituted two quarterly inspection samples.

Specific components and systems reviewed were:

• CV System; and

• Crossover Steam Dump System

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessment and Emergent Work Evaluation

a. Inspection Scope

The inspectors reviewed risk assessments for the following maintenance activities, completing risk assessment and emergent work control inspection samples. These observations constituted seven quarterly inspection samples.

• unavailability of the engineered safeguard systems for planned maintenance and testing during the week of July 18, 2004;

• unavailability of the P-32, SW pumps for planned maintenance and testing during the week of July 25, 2004;

• unavailability of the 1P-29, turbine-driven AFW pump for planned maintenance during the week of August 15, 2004;

• unavailability of the containment recirculation fans for planned maintenance during the week of August 22, 2004;

• unavailability of the White 125-VDC inverter for planned maintenance during the week of August 29, 2004;

• unavailability of 480-volt and 4160-volt switchgear relays for planned testing during the week of September 5, 2004; and

• unavailability of the RHR pump motor transfer switch for planned maintenance during the week of September 12, 2004.

During these reviews, the inspectors compared the licensees risk management actions to those actions specified in the licensees procedures for the assessment and management of risk associated with maintenance activities. The inspectors assessed whether 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 inspectors used the licensees daily configuration risk assessment records, observations of shift turnover meetings, and observations of daily plant status meetings to determine if the equipment configurations had been properly listed, that protected equipment had been identified and was being controlled where appropriate, and that significant aspects of plant risk were communicated to the necessary personnel. Documents reviewed during this inspection are listed in the attachment to this report.

b. Findings

No findings of significance were identified.

1R14 Personnel Performance During Non-Routine Plant Evolutions and Events

.1 Unit 2 Power Reduction for Removal of the 5B Feedwater Heater from Service

a. Inspection Scope

On August 13, 2004, the inspectors observed a Unit 2 power reduction to 90 percent for removal of the shell side of the 5B feedwater heater from service. The inspectors observed operator procedure use and adherence, communications, control of equipment, diagnosis of a drain valve actuator that was not properly connected to the stem, and return to full power operations. This observation constituted one inspection sample.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

During this inspection period, the inspectors reviewed the following operability evaluations:

• Calculation N-94-042 Used Incorrect Data for SI Pump Motors;

• Auxiliary Feedwater Pump Recirculation Air-Operated Valves Not Set Up In Conformance With Calculations;

• Residual Heat Removal Cut-In Conditions Not Achievable in Assumed Time;

• Inservice Test (IT) 10 Acceptance Criteria Does Not Ensure Adequate Auxiliary Feedwater Without Operator Action;

• Containment Fan Motor 2W-001-B1-M, RHR Motor 1P-010B-M, and Safety Injection Motor 1P-015A-M, No Environmental Qualification; and

• Steam Generator Blowdown Tank Rupture Disk Not Code Stamped.

These observations constituted six quarterly inspection samples.

The inspectors reviewed the technical adequacy of the operability evaluations against Technical Specifications (TSs), FSAR, and other design information; determined whether compensatory measures, if needed, were taken; determined whether the evaluations were consistent with procedure NP 5.3.7, Operability Determinations; and determined whether critical design assumptions had been correctly translated into as-built field configurations. The inspectors also reviewed CAPs to determine if licensee personnel identified issues at an appropriate threshold and entered them into the corrective action program in accordance with station procedures. Documents reviewed during this inspection are listed in the attachment to this report.

b. Findings

No findings of significance were identified.

1R16 Operator Workarounds (OWAs)

.1 Unit 1 RHR Heat Exchanger Bypass Valve Drifts Open While in Automatic

a. Inspection Scope

During the weeks of September 13 and 20, 2004, the inspectors reviewed the operational effects of the Unit 1 RHR heat exchanger bypass flow control valve, 1RH-626, drifting from 0 to 40 percent open while in the automatic mode of operation.

The inspectors interviewed selected operations and I&C personnel; evaluated manual and automatic valve control modes during operating and shutdown plant conditions; and reviewed corrective action program records, the procedure associated with placing the RHR system in operation, and selected emergency and abnormal operating procedures (AOPs) to determine if the licensee had considered all potential operational impacts.

Documents reviewed during this inspection are listed in the attachment to this report.

This observation constituted one inspection sample.

b. Findings

Introduction.

The inspectors identified a finding having very low safety significance (Green) regarding a workaround in the operation of the Unit 1 RHR heat exchanger bypass flow control valve in the automatic mode of operation during a shutdown LOCA.

The finding did not involve a violation of regulatory requirements.

Description.

During inservice testing in June and July 2004 with Unit 1 at full power, the RHR heat exchanger bypass flow control valve, 1RH-626, drifted from 0 to 40 percent open while in the automatic mode of operation. The licensee reasoned that since the valve had demonstrated controllability in manual during the inservice tests and was maintained in the manual/shut position per SI system CL 7A, it remained operable during power operations. Although I&C personnel initiated troubleshooting efforts following the June failure, a corrective action was not assigned to evaluate the 1RH-626 controller issue as a potential OWA.

In addition, the inspectors determined that the licensee had not considered the possible effects of the controller issue during shutdown modes of plant operation. The inspectors reviewed operating procedure (OP) 7A, Placing Residual Heat Removal System In Operation, and noted that Step 5.2.14.c allowed operators to place 1RH-626 in the automatic mode of operation, if desired. The inspectors also determined that safety-related shutdown emergency procedure (SEP) 1 Unit 1, Degraded RHR System Capability, Step 14.c; SEP 2.2 Unit 1, Shutdown LOCA With RHR Aligned For Decay Heat Removal, Steps 11.e and 13.a; and SEP 2.3 Unit 1, Cold Shutdown LOCA, A, Step A7, directed 1RHR-626 to be shut, an action that could be complicated and inhibited with the valve drifting from 0 to 40 percent open while in the automatic mode of operation. The inspectors determined that the drifting of 1RH-626 from 0 to 40 percent open in the automatic mode of operation was an OWA in two respects. First, the issue had the potential to complicate emergency response for a shutdown LOCA in that an operator could encounter difficulty in closing 1RH-626 while in automatic and be forced to take the controller to manual to shut the valve, an additional and unplanned action. Second, the issue had the potential to complicate normal plant operations in that if adjustments were made to the A or B RHR heat exchanger outlet flow control valves, 1RH-624 and 1RH-625, while operators were controlling reactor coolant system temperature via RHR cooling, additional operator action would be required to adjust 1RH-626 so as to keep total RHR system flow constant as the primary flow rate through the RHR heat exchangers was varied.

Analysis.

The inspectors determined that there were two performance deficiencies associated with the RHR heat exchanger bypass flow control valve, 1RH-626, drifting from 0 to 40 percent open while in the automatic mode of operation that warranted a significance evaluation. First, although the licensee assessed the impact of the issue during power operations in June 2004, the licensee did not evaluate potential impacts on shutdown plant operations until questioned by the inspectors in September 2004.

Second, although I&C personnel had performed troubleshooting efforts following the initial failure in June 2004, a corrective action item was not assigned to operations personnel to evaluate the 1RH-626 controller issue as a potential OWA.

The inspectors concluded that the finding was more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on June 20, 2003, because it affected the equipment performance attribute of the Reactor Safety Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events. The inspectors determined that the issue also affected the cross-cutting area of problem identification and resolution in two respects. First, the initial extent-of-condition review did not consider the impact of the issue on shutdown plant operations. Second, following initial I&C troubleshooting efforts, a corrective action item was not assigned to operations personnel to evaluate the issue as a potential OWA. This contributed to a 3-month delay in completing the evaluation.

The inspectors completed a significance determination of this issue using IMC 0609, "Significance Determination Process," dated March 21, 2003, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations," dated September 10, 2004. The inspectors determined that the finding did not degrade short term decay heat removal capability (SI) or reactivity control; result in a design or qualification deficiency or an actual loss of safety function; or involve internal or external initiating events. Therefore, the finding was considered to be of very low safety significance (Green).

Enforcement.

Because the operators always had the ability to maintain positive control of 1RH-626 by switching from the automatic to the manual mode of operation during a shutdown LOCA, the inspectors determined that no violation of regulatory requirements occurred since the intended function of shutting 1RH-626 as described in SEP 1, SEP 2.2, and SEP 2.3 could still be accomplished. This issue was considered a finding of very low safety significance (FIN 05000266/2004006-01). The licensee entered the finding into its corrective action program as CAP057507, 1RH-626, HX-11A/B RHR Bypass Flow Control, Fails to Operate in Auto, and received review by the station Operator Workaround Committee who classified the problem as an operator challenge in accordance with plant procedures.

1R19 Post-Maintenance Testing (PMT)

a. Inspection Scope

During this inspection period, the inspectors completed six quarterly inspection samples, composed of the following PMT activities:

• Containment spray pump 1P-14A following oil change on September 15, 2004;

• Containment spray pump 1P-14B following oil change on September 15, 2004;

• Units 1 and 2 Periodic Check (PC) 23 Part 5, charging pump maintenance on August 9, 2004;

• Unit 1 RHR heat exchanger bypass flow control valve, 1RH-626, following valve drifting in the open direction while in automatic on August 20, 2004;

• G-05 gas turbine following annual maintenance on September 29, 2004; and

• Unit 1 turbine cross-under piping manway following Furmanite repair on September 27, 2004.

Documents reviewed during this inspection are listed in the attachment to this report.

During completion of the inspection samples, the inspectors observed in-plant activities and reviewed procedures and associated records to determine if:

• testing activities satisfied the test procedure acceptance criteria;

• effects of the testing had been adequately addressed prior to the commencement of the testing;

• measuring and test equipment calibration was current;

• test equipment was used within the required range and accuracy;

• applicable prerequisites described in the test procedures were satisfied;

• affected systems or components were removed from service in accordance with approved procedures;

• testing activities were performed in accordance with the test procedures and other applicable procedures;

• jumpers and lifted leads were controlled and restored, where used;

• test data/results were accurate, complete, and valid;

• test equipment was removed after testing;

• equipment was returned to a position or status required to support the operability of the system in accordance with approved procedures; and

• all problems identified during the testing were appropriately documented in the corrective action program.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

During this inspection period, the inspectors completed inspection samples, composed of surveillance testing activities associated with the following plant documents:

• Health Physics Implementing Procedure (HPIP) 11.54 on August 27, 2004;

• Operator logs for use of TSs and parametric values, on August 26, 2004;

• Instrumentation and Control Procedure (ICP) 2ICP 2.013 on August 18, 2004; and

• Routine Maintenance Procedure (RMP) 9307-3, Power Shield Test Procedure, on September 1, 2004.

Documents reviewed during this inspection are listed in the attachment to this report.

These observations constituted four quarterly inspection samples.

During completion of the inspection samples, the inspectors observed in-plant activities and reviewed procedures and associated records to determine if:

• preconditioning occurred;

• effects of the testing had been adequately addressed by control room personnel or engineers prior to the commencement of the testing;

• acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis;

• plant equipment calibration was correct, accurate, properly documented, as-left setpoints were within required ranges, and the calibration frequency was in accordance with TSs, FSAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

• test equipment was used within the required range and accuracy;

• applicable prerequisites described in the test procedures were satisfied;

• test frequency met TS requirements to demonstrate operability and reliability;

• the tests were performed in accordance with the test procedures and other applicable procedures;

• jumpers and lifted leads were controlled and restored, where used;

• test data/results were accurate, complete, within limits, and valid;

• test equipment was removed after testing;

• where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component declared inoperable;

• where applicable for safety-related instrument control surveillance tests, reference setting data have been accurately incorporated in the test procedure;

• prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

• equipment was returned to a position or status required to support the performance of its safety functions; and

• all problems identified during the testing were appropriately documented and dispositioned in the corrective action program.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors conducted in-plant observations of physical changes to the plant and equipment and performed in-office reviews of documentation to evaluate the temporary modification (TM) detailed below. The inspectors reviewed design basis documents (DBDs) and safety evaluation screenings to ensure that the modifications were consistent with applicable documents, drawings, and procedures. The inspectors also reviewed the post-installation results to confirm that any impacts of the TM on permanent and interfacing systems were adequately verified. This observation constituted one inspection sample.

The inspectors reviewed the following TM:

• Installation of Submersible Sump Pumps in Manholes 1, 2, 3, 10, 14, 16, and 19.

b. Findings

No findings of significance were identified.

Emergency Preparedness

1EP6 Drill Evaluation

.1 Emergency Plan Procedure Training Drills

a. Inspection Scope

During the week of August 4, 2004, the inspectors observed a training drill involving Emergency Action Levels (EALs) and Emergency Plan Implementing Procedures (EPIPs). The inspectors observed classifications, notifications, facility activations, and facility critiques. The inspectors performed observations in the Control Room (simulator), Technical Support Center, and Emergency Operations Facility during the drill. The inspectors also observed the training of new Emergency Response Organization personnel. This observation constituted one inspection sample.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Public Radiation Safety

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

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed the 2003 Annual Monitoring Report (which included information relative to the stations radiological effluent releases) to determine if the program was implemented as described in Radiological Effluent TSs (RETS)/Offsite Dose Calculation Manual (ODCM) and to determine if ODCM changes were made in accordance with Regulatory Guide 1.109 and NUREG-0133. The inspectors reviewed the Annual Monitoring Report and ODCM to determine if any changes to the design and/or operation of the radioactive waste systems changed the dose consequence to the public. The inspectors also reviewed technical and/or 10 CFR 50.59 evaluations performed, when required, for any such modifications and determined whether radioactive liquid and gaseous effluent radiation monitor setpoint calculation methodology changed since completion of the modifications. The inspectors determined if anomalous results reported in the current Annual Monitoring Report, if any, were adequately resolved.

The inspectors reviewed the RETS/ODCM to identify effluent radiation monitoring systems and flow measurement devices, any effluent radiological occurrence performance indicator (PI) incidents in preparation for onsite follow-up, and the FSAR description of all radioactive waste systems.

These reviews represented one inspection sample.

b. Findings

No findings of significance were identified.

.2 Onsite Inspection - Walkdown of Effluent Control Systems, System/Program

Modifications, Air Cleaning System Surveillances, and Instrument Calibrations

a. Inspection Scope

The inspectors walked down the major components of the gaseous and liquid release systems (e.g., radiation and flow monitors, demineralizers and filters, tanks, and vessels) to observe current system configuration with respect to the description in the FSAR, ongoing activities, and to assess equipment material condition.

The inspectors reviewed the licensees technical justification for any changes made by the licensee to the ODCM, as well as to the liquid or gaseous radioactive waste system design, procedures, or operation since the last inspection to determine whether the changes affected the licensees ability to maintain effluents as-low-as-is-reasonably-achievable and whether changes made to monitoring instrumentation resulted in non-representative monitoring of effluents. Additionally, the inspectors reviewed the licensees evaluations related to the abandonment of the waste water retention pond (a former 10 CFR Part 20 liquid release path).

The inspectors reviewed air cleaning system surveillance test results to ensure that the system was operating within the licensees acceptance criteria. Specifically, the inspectors reviewed the most recent results of the Ventilation Filter Testing Program for the Control Room Emergency Filtration System to verify that test methodology, frequency and test results met TS requirements. The inspectors reviewed and discussed the test results of in-place high efficiency particulate air filter and charcoal adsorber penetration tests, laboratory tests of charcoal adsorber methyl iodide penetration, and in-place combined high efficiency particulate air filter and charcoal adsorber train pressure drop tests for the system with radiation protection and system engineering staff.

The inspectors reviewed records of instrument calibrations performed since the last inspection for each point-of-discharge effluent radiation monitor and flow measurement device, and reviewed any completed system modifications and the current effluent radiation monitor alarm setpoint value for conformance with RETS/ODCM requirements. The inspectors also reviewed calibration records of radiation measurement (i.e., chemistry counting room) instrumentation associated with effluent monitoring and release activities and the quality control records for those instruments.

These reviews represented four inspection samples.

b. Findings

No findings of significance were identified.

.3 Onsite Inspection - Effluent Release Packages, Abnormal Releases, Dose Calculations,

and Laboratory Quality Control and Assurance

a. Inspection Scope

As there were no routine radioactive liquid releases conducted during the on-site inspection, the inspectors reviewed several radioactive liquid waste release permits for previous releases, including the projected doses to members of the public, to determine if appropriate treatment equipment was used and radioactive liquid waste was processed and released in accordance with RETS/ODCM and procedure requirements.

Additionally, as there were no routine radioactive gaseous releases conducted during the on-site inspection, the inspectors reviewed several radioactive gaseous effluent release permits for previous releases, to determine if appropriate treatment equipment was used and radioactive gaseous effluent was processed and released in accordance with RETS/ODCM and procedure requirements.

The licensee did not identify any abnormal releases or releases made with inoperable effluent radiation monitors, since the last inspection in this area. As such, the inspectors were unable to review the licensees actions for such releases.

The inspectors reviewed a selection of monthly, quarterly, and annual dose calculations to ensure that the licensee properly calculated the offsite dose from radiological effluent releases and to determine if any annual RETS/ODCM (i.e., Appendix I to 10 CFR Part 50) limits were exceeded.

The inspectors reviewed the results of the interlaboratory comparison program to determine the quality of radioactive effluent sample analyses performed by the licensee.

The inspector reviewed the licensees quality control evaluation of the interlaboratory comparison test and associated corrective actions for any deficiencies identified. The inspector reviewed the licensees assessment of any identified bias in the sample analysis results and the overall effect on calculated projected doses to members of the public. In addition, the inspectors reviewed the results from the licensees Quality Assurance audits to determine whether the licensee met the requirements of the RETS/ODCM.

These reviews represented four inspection samples.

b. Findings

No findings of significance were identified.

.4 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed any available licensee self-assessments, audits, and special reports related to the radioactive effluent treatment and monitoring program since the last inspection to determine if identified problems were entered into the corrective action program for resolution. The inspectors also assessed whether the licensee's self-assessment program was capable of identifying repetitive deficiencies or significant individual deficiencies in problem identification and resolution.

The inspectors also reviewed corrective action reports from the radioactive effluent treatment and monitoring program since the previous inspection, interviewed staff, and reviewed documents to determine if the following activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk:

• Initial problem identification, characterization, and tracking;

• Disposition of operability/reportability issues;

• Evaluation of safety significance/risk and priority for resolution;

• Identification of repetitive problems;

• Identification of contributing causes;

• Identification and implementation of effective corrective actions;

• Resolution of Non-Cited Violations tracked in the corrective action program; and

• Implementation/consideration of risk significant operational experience feedback.

These reviews represented one inspection sample.

b. Findings

No findings of significance were identified.

4OA1 PI Verification

Cornerstones: Mitigating Systems and Public Radiation Safety

.1 Reactor Safety Strategic Area - Mitigating Systems Cornerstone

a. Inspection Scope

The inspectors reviewed the licensees recent PI submittal, using PI definitions and guidance contained in Revision 2 of Nuclear Energy Institute document 99-02, "Regulatory Assessment Performance Indicator Guideline," to determine the accuracy of the PI data. The inspectors reviewed selected applicable conditions and data from logs, licensee event reports, and corrective action program documents from July 2002 through June 2004. The inspectors independently re-performed calculations where applicable. The inspectors compared that information to the information required for each PI definition in the guideline, to ensure that the licensee reported the data accurately.

These observations constituted six inspection samples. The following PIs were reviewed:

Unit 1

• Emergency Alternating Current Power System Unavailability

• Heat Removal System Unavailability

• RHR System Unavailability Unit 2

• Emergency Alternating Current Power System Unavailability

• Heat Removal System Unavailability

• RHR System Unavailability

b. Findings

No findings of significance were identified.

.2 Radiation Protection Strategic Area - Public Radiation Safety

a. Inspection Scope

The inspector sampled the licensees submittals for the PI and period listed below. The inspector used PI definitions and guidance contained in Revision 2 of Nuclear Energy Institute document 99-02, Regulatory Assessment Performance Indicator Guideline, to determine the accuracy of the PI data. This observation constituted one inspection sample. The following PI was reviewed:

• RETS/ODCM Radiological Effluent Occurrence Since no reportable occurrences were identified by the licensee for the 2nd quarter 2003 through the 2nd quarter 2004, the inspector compared the licensees data and reviewed corrective action program documents generated during the time period to identify any potential occurrences such as unmonitored, uncontrolled or improperly calculated effluent releases that may have impacted offsite dose. Also, the inspector evaluated the licensees methods for determining offsite dose and selectively verified that liquid and gaseous effluent release data and associated offsite dose calculations performed since this indicator was last reviewed were accurate.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Resident Inspector Review of a Safe Shutdown Procedure That Directed Alignment of

Instrumentation to a DC Bus Without a Battery Charger

a. Inspection Scope

During the week of September 20, 2004, the inspectors reviewed the thoroughness and adequacy of licensee actions to correct AOP 10A, Safe Shutdown - Local Control, which aligned Units 1 and 2 safe shutdown instrumentation to a 125-VDC bus that did not have a battery charger available to support the selected instrumentation. The inspectors also reviewed the initial corrective action program screening committees assessment of the issue and the safe shutdown strategy for fires in the main control, cable spreading, and 4160-volt switchgear rooms. This observation constituted one resident inspector sample.

b. Findings and Observations

Introduction.

The inspectors identified a URI concerning the effects of supplying power from a 125-VDC safety-related battery to Units 1 and 2 safe shutdown instrumentation necessary for monitoring reactor decay heat removal without a battery charger being aligned to the associated DC bus. The issue did not represent an immediate safety concern and is considered a URI pending regulatory review of the licensees extent-of-condition and potential impact evaluations, actions not completed by the end of this inspection period.

Description.

Based on an inspector question concerning the adequacy of procedure feedback request OPS-2004-01454 on September 15, operations personnel performed a second and more detailed review of AOP 10A, Safe Shutdown - Local Control, and identified a previously missed issue. Namely, that the normal battery chargers (D107 and D108) for DC buses D03 (white 125-VDC instrument bus) and D04 (yellow 125-VDC instrument bus) would be affected by a postulated fire in the main control, cable spreading, and 4160-volt switchgear rooms such that the normal chargers would not be available. Specifically, when battery chargers would be re-aligned in AOP 10A, Step 48, the one available swing battery charger (D109) would be aligned to D03 leaving no charger available to be aligned to D04. In addition, AOP-10A, C, Step C8 aligned power selector switch C-207 to the backup position.

Aligning C-207 to the backup position meant that the battery for the yellow 125-VDC instrument bus, D04, would be discharging over time while supplying shutdown instrumentation associated with DY-14, a safe shutdown panel inverter. Eventually, the safe shutdown instrumentation associated with DY-14 would become inoperable as the voltage of the battery supplying D04 decreased and the battery became depleted.

Operators could select another safe shutdown inverter, DY-13, associated with D03 and the swing battery charger but AOP-10A did not direct this action.

The licensee initiated CAP059262 to document the alignment of safe shutdown instrumentation to a 125-VDC bus without a battery charger and issued temporary procedure change 2004-0762 on September 16, to correct the procedural error. The inspectors noted that the CAP was assigned a B significance level indicating that the licensee considered the issue a condition adverse to quality typically resulting in moderate impact to the plant or organization. The inspectors reviewed the CAP screening committees dispositioning of CAP059262 and noted that the CAP was closed to completed actions per the September 17 managers meeting. The inspectors reviewed selected drawings and the safe shutdown analysis report for fire scenarios in the main control, cable spreading, and 4160-volt switchgear rooms and noted that in closing CAP059262 to the temporary procedure change the licensee had failed to identify and assess:

• the specific safe shutdown instrumentation powered from DY-14, instrumentation that had the potential to degrade and become inoperable over time. Specifically, the inspectors determined that DY-14 provided instrument power to the Unit 1 and 2 B steam generator wide range level instruments, the B reactor coolant system (RCS) loop wide range T-cold temperature instrument, and the B RCS loop wide range T-hot temperature instrument.

• that the safe shutdown strategy for a fire in the main control, cable spreading, and 4160-volt switchgear rooms was to remove reactor decay heat by using the B reactor coolant loops, the 'B' steam generators, and the unit specific turbine-driven AFW pumps. In closing the CAP, the licensee did not evaluate:

1) whether the D04 battery would deplete to the extent that DY-14 instrumentation would became inaccurate, suspect, or inoperable before RHR cooling was placed inservice, or 2) whether the local operator would have difficulty controlling, monitoring, and maintaining reactor decay heat removal via the 'B' RCS loop and steam generator.

• the extent-of-condition of the issue in terms of other safe shutdown procedure actions directing operators to perform steps potentially in conflict with safe shutdown strategies.

• the effects on past operability and whether a successful safe shutdown of Units 1 and 2 for a fire in the main control, cable spreading, or 4160-volt switchgear rooms could have been achieved.

On September 17 and 20, the inspectors discussed closure of CAP059262 with a licensee fire protection engineer and the performance improvement manager. Following the inspectors observations, the CAP was re-screened on September 20 and a condition evaluation to include extent-of-condition was assigned.

Since the licensee had not finished an extent-of-condition review or evaluated the potential impact of powering safe shutdown instrumentation from DC power sources without an associated battery charger by the end of this inspection period, this issue will be considered a URI pending NRC review of the licensee evaluations (URI 05000266/2004006-02; 05000301/2004006-02). A preliminary discussion with licensee representatives indicated that this issue did not represent an immediate safety concern. The licensee entered the issue into its corrective action program as CAP059262, Question PI&R Question regarding OPS Procedure Feedback.

4OA3 Event Follow-up

.1 (Closed) Licensee Event Response (LER) 05000301/2004002-00: Concerns With Diver

Safety Result in Manual Reactor Trip.

On May 15, 2004, Unit 2 was manually tripped from full power when a divers tether and air and communication lines became entangled while the diver was inspecting the circulating system (CW) intake structure for winter damage. This event was initially discussed in Section 4OA2.5 of the most recent integrated report, Inspection Report 05000266/2004003; 05000301/2004003.

As discussed in the LER and a root cause evaluation, the licensee determined that the primary causes of this event were unclear and inconsistent communications and inadequate supervisory oversight. Specifically, diving operations had come to be viewed as routine, not all personnel involved with the diving operation understood the scope of the work to be performed, the WO associated with the diving activities lacked specificity concerning the portions of the intake crib to be inspected and the associated precautions, and the pre-job brief for the diving evolution did not emphasize the restricted areas within the intake crib. In addition, the intake crib inspection procedure was considered inadequate due to its general nature, the oversight by the diving liaison was inadequate during the critical time when the diver was entering the north area of the intake crib, and the diving activity communications were inadequate in preventing the diver from entering a hazardous area.

The inspectors determined that this issue affected the cross-cutting area of human performance in that:

(1) plant personnel were complacent as shown in the treatment of the diving operation as a routine job,

(2) communications were unclear and inconsistent throughout the diving evolution,

(3) the procedure directing the intake crib inspection was not followed at all times and was determined to be unclear,

(4) management oversight of the diving was insufficient, and

(5) there were several instances of excessive slack in the divers tending lines. The inspectors noted that this event was similar to one in October 2000 when Unit 1 was manually tripped due to concerns for the safety of a diver inspecting the CW forebay. The corrective actions from this were to improve communications and develop a diving control procedure with detailed responsibilities for providing support, communications, and notifications.

This LER was reviewed by the inspectors and no findings of significance were identified.

The licensee entered the issue in the corrective action program as CAP056731, Unit 2 Manual Trip. This LER is closed. This event did not constitute a violation of NRC requirements.

4OA4 Cross-Cutting Aspects of Findings

.1 A finding described in Section 1R16.1 of this report had, as its primary cause, a problem

identification and resolution deficiency in two respects. First, the initial extent-of-condition review did not consider the impact of the issue on shutdown plant operations. Second, following initial I&C troubleshooting efforts, a corrective action item was not assigned to operations personnel to evaluate the issue as a potential OWA.

This contributed to a 3-month delay in completing the evaluation.

.2 A Unit 2 manual reactor trip due to diver safety concerns described in Section 4OA3.1 of

this report, had, as primary causes, human performance deficiencies in that:

(1) plant personnel were complacent as shown in the treatment of the diving operation as a routine job,

(2) communications were unclear and inconsistent throughout the entire diving evolution,

(3) the procedure directing the intake crib inspection was not followed at all times and was determined to be unclear,

(4) management oversight of the diving was insufficient, and

(5) there were several instances of excessive slack in the divers tending lines.

4OA5 Other Activities

Review of Institute of Nuclear Power Operations Report The inspectors completed a review of the interim report for the Institute of Nuclear Power Operations, March 2004 Evaluation, dated May 10, 2004.

4OA6 Meetings

.1 Exit Meeting

On October 1, 2004, the resident inspectors presented the inspection results to Mr. Jim McCarthy and other members of the Point Beach staff, who acknowledged the findings.

The licensee did not identify any information, provided to or reviewed by the inspectors, as proprietary.

.2 Interim Exit Meeting

An interim exit was conducted for:

• Radiation Protection (RETS/ODCM) inspection with Mr. J. McCarthy on July 30, 2004. A telephonic re-exit was conducted with Messrs. J. McCarthy and S. Thomas on August 20, 2004, to discuss follow-up question results relative to the licensees ventilation filter testing program.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

J. Brander, Maintenance Manager

B. Carberry, Radiation Protection - ALARA

G. Casadonte, Fire Protection Coordinator

J. Connolly, Regulatory Affairs Manager

G. Correll, Chemistry Department Manager

R. Davenport, Production Planning Manager

B. Dungan, Operations Manager

C. Hill, Assistant Operations Manager

M. Holzmann, Nuclear Oversight Manager

R. Hopkins, Internal Assessment Supervisor

C. Jilek, Maintenance Rule Coordinator

T. Kendall, Program Engineering

D. Koehl, Site Vice-President

B. Kopetsky, Security Coordinator

C. Krause, Senior Regulatory Compliance Engineer

R. Ladd, Fire Protection Engineer

J. McCarthy, Site Director of Operations

R. Milner, Business Planning Manager

T. Petrowsky, Design Engineer Manager

M. Ray, Emergency Preparedness Manager

C. Richardson, Design Engineer

J. Schroeder, Service Water System Engineer

J. Schweitzer, Site Engineering Director

J. Shaw, Plant Manager

G. Sherwood, Engineering Programs Manager

C. Sizemore, Training Manager

P. Smith, Operations Training Supervisor

W. Smith, Site Assessment Manager

J. Strharsky, Planning and Scheduling Manager

S. Thomas, Radiation Protection Manager

Nuclear Regulatory Commission

H. Chernoff, Point Beach Project Manager, NRR

P. Louden, Chief, Reactor Projects, Branch 5

Attachment

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000301/2004002-00 LER Concerns With Diver Safety Result in Manual Reactor Trip (Section 4OA3.1)

05000266/2004006-01 FIN Unit 1 Residual Heat Removal Heat Exchanger Bypass Valve Drifts Open While in Automatic (Section 1R16.1)

05000266/2004006-02; URI Resident Inspector Review of a Safe Shutdown

05000301/2004006-02 Procedure That Directed Alignment of Instrumentation to a Direct Current Bus Without a Battery Charger (Section 4OA2.1)

Closed

05000301/2004002-00 LER Concerns With Diver Safety Result in Manual Reactor Trip (Section 4OA3.1)

05000266/2004006-01 FIN Unit 1 Residual Heat Removal Heat Exchanger Bypass Valve Drifts Open While in Automatic (Section 1R16.1)

Discussed

None.

Attachment