IR 05000266/2004002
| ML041280141 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 05/06/2004 |
| From: | Reynolds S Division Reactor Projects III |
| To: | Vanmiddlesworth G Nuclear Management Co |
| References | |
| IR-04-002 | |
| Download: ML041280141 (60) | |
Text
SUBJECT:
POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000266/2004002; 05000301/2004002
Dear Mr. Van Middlesworth:
On March 31, 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 April 5, 2004, with you and 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, three NRC-identified findings of very low safety significance were identified, two of which involved a violation of NRC requirements. 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 these violations as Non-Cited Violations consistent with Section VI.A.1 of the NRC Enforcement Policy.
Additionally, two licensee-identified violations are listed in Section 4OA7 of this report.
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 Point Beach Nuclear Plant facility.
Gary Van Middlesworth -2-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 January 15, February 24, and March 22, 2004, the NRC reviewed Point Beach operational performance, inspection findings, and performance indicators for the first quarter of 2004. Based on this review, we concluded that Point Beach performance, while not clearly demonstrating improvement, did not represent unsafe operations. 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, its enclosure, and any response you submit 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 05000266/2004002; 05000301/2004002 w/Attachment: Supplemental Information See Attached Distribution
See Previous Concurrences DOCUMENT NAME: S:\ADMIN\Karen's Docs\ML041280141.wpd To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy OFFICE RIII RIII RIII NAME MKunowski:dtp* PLouden* SReynolds DATE 04/30/04 04/30/04 05/06/04 OFFICIAL RECORD COPY
Gary Van Middlesworth -3-
REGION III==
Docket Nos: 50-266; 50-301 License Nos: DPR-24; DPR-27 Report No: 05000266/2004002; 05000301/2004002 Licensee: Nuclear Management Company, LLC Facility: Point Beach Nuclear Plant, Units 1 and 2 Location: 6610 Nuclear Road Two Rivers, WI 54241 Dates: December 28, 2003, through March 31, 2004 Inspectors: P. Krohn, Senior Resident Inspector M. Morris, Acting Senior Resident Inspector R. Langstaff, Senior Reactor Inspector R. Alexander, Radiation Specialist D. Karjala, Resident Inspector B. Jorgensen, NRC Consultant M. Jordan, NRC Consultant Approved by: P. Louden, Chief Branch 7 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR 05000266/2004002, 05000301/2004002; 12/28/2003 - 03/31/2004; Point Beach Nuclear
Plant, Units 1 & 2; Fire Protection, Maintenance Risk Assessment and Emergent Work Evaluation.
This report covers a 3-month period of baseline resident inspection and announced radiation protection (71121) inspections for the Point Beach Nuclear Plant, Units 1 and 2, by seven inspectors: a senior reactor inspector, a radiation specialist inspector, two NRC consultant inspectors, and three resident inspectors. Two Non-Cited Violations (NCVs) and one Green finding 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-Revealing Findings
Cornerstone: Mitigating Systems
- Green.
The inspectors identified an NCV of the license for the failure of the licensee to install sprinkler heads in accordance with the applicable fire code in the component cooling water (CCW) pump area. Specifically, the sprinkler heads were located a greater distance below the ceiling than permitted by code.
This finding was more than minor because it was associated with the protection against external factors (i.e., fire) attribute of the mitigating systems reactor safety cornerstone and affected the cornerstone objective in that a fire protection feature (i.e., an automatic suppression system) was adversely affected. The finding was of very low safety significance because manual fire fighting and auxiliary feedwater (AFW) could be credited. This issue is a violation of a license condition and the applicable fire code which requires that sprinkler heads be located near the ceiling. (Section 4OA5)
Cornerstone: Barrier Integrity
- Green.
The inspectors identified an NCV of 10 CFR Part 50, Appendix B, Criterion III,
Design Control, having very low safety significance (Green) for failing to properly document a modification of the containment hatch interlock. The licensee failed to perform an engineering design change analysis for the Unit 1 personal containment hatch upper interlock cable when it was identified that original design specifications were not met. Specifically, the cable was replaced with a smaller cable prior to 2000 and again in 2000. When the cable broke in 2004, engineers replaced the cable with one that met the original design specifications, correcting the violation.
The inspectors determined that the finding was more than minor because it affected the barrier integrity reactor safety cornerstone objective attribute of maintaining functionality of containment design control. The finding was considered to be of very low safety significance because it did not result in an actual open pathway in the physical integrity of the reactor containment or actual reduction of the atmospheric pressure control function of the reactor containment. (Section 1R23.2)
Cornerstone: Emergency Preparedness
- Green.
The inspectors identified a finding of very low safety significance concerning an inadequate extent-of-condition review during safety-related procedure revisions associated with steam generator narrow range level setpoints, and the failure to recognize the impact of the setpoint changes on the Point Beach Emergency Plan. The primary cause of this finding was related to the cross-cutting area of human performance in four respects. First, at least four personnel, including a Shift Manager (SM) and two senior reactor operators (SROs), reviewed the procedure changes but failed to recognize the potential impact of the procedure changes on the emergency plan. Second, personnel associated with the corrective action process for the initial steam generator narrow range level density compensation issue failed to recognize the potential emergency plan impact and raise the issue to the attention of emergency preparedness personnel. Third, despite the emergency preparedness reviews completed prior to and during the 95003 supplemental inspection process, the licensee had not identified and evaluated the potential impacts of the discrepancy between the procedure setpoints and Emergency Action Level 3.1.1.4. Fourth, until identified by the inspectors, personnel involved with efforts to achieve regulatory compliance with eight emergency action levels (EALs) during January 2004, had not recognized or evaluated the potential impact of the discrepancy.
This finding was considered more than minor because it: (1) involved the procedure quality attribute of the emergency preparedness reactor safety cornerstone; and (2) if left uncorrected, it could become a more significant safety concern if the discrepancy in steam generator narrow range level setpoints prevented, or caused a delay in, declaring a general emergency during a loss of electrical power event. The finding was not considered a violation of regulatory requirements. (Section 4OA2.2)
Licensee-Identified Violations
Violations of very low significance, which were identified by the licensee have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.
REPORT DETAILS
Summary of Plant Status
Unit 1 began the inspection period at 100 percent power and remained there until February 21, 2004, when power was reduced to 65 percent for crossover steam dump and turbine stop valve testing. The unit returned to 98 percent power on February 22 and remained there until February 26 when it was returned to full power. The unit decreased power to 98 percent on March 4 for AFW pump testing and returned to full power on March 5. The unit remained at full power until March 20 when power coastdown began prior to the unit outage and ended this report period at 92 percent power.
Unit 2 began the inspection period at 100 percent power until February 7, when power was reduced to 65 percent for crossover steam dump and AFW pump testing. Unit 2 returned to full power on February 8. The unit decreased power to 98 percent on March 4 for AFW pump testing and returned to full power that day. The unit decreased power to 98 percent on March 11 for AFW pump testing and returned to full power that day. On March 30, after the licensee identified that nitrogen overpressure in a safety injection accumulator was less than the Technical Specification limit, reactor power was reduced to 82 percent before nitrogen was restored to the limit. Reactor power was returned to 100 percent that afternoon. The unit remained at full power until the end of this report period.
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 two 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 verify that 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 verify that there were no 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 two quarterly inspection samples.
The inspectors verified the alignment of the following systems:
- Ice Melt System
- Unit 2 Safety Injection (SI) System
b. Findings
No findings of significance were identified.
.2 Complete System Walkdowns
c. Inspection Scope
On March 10, 2004, the inspectors performed a complete system alignment inspection of Unit 1 and Unit 2 service water (SW) system. This system was selected because it was considered both safety-significant and risk-significant in the licensees probabilistic risk assessment. The inspection consisted of the following activities:
- a review of plant procedures (including selected abnormal and emergency procedures), drawings, and the FSAR to identify proper system alignment;
- a review of outstanding or completed temporary and permanent modifications to the system;
- a review of open corrective action program documents (CAPs) and WOs that could impact operability of the system; and
- a walkdown of mechanical and electrical components in the system to verify proper alignment, component accessibility, availability, and current condition.
The inspectors also reviewed selected documented issues to determine if they had been properly addressed in the licensees corrective action program. Documents reviewed during this inspection are listed in the attachment to this report. These inspection activities constituted one inspection sample.
b. Findings
No findings of significance were identified.
1R05 Fire Protection
.1 Walkdown of Selected Fire Zones
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 11 fire areas for inspection based on the areas overall fire risk contribution, as documented in the 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 appeared to be in satisfactory condition. These observations constituted 11 quarterly inspection samples.
The following areas were inspected by walkdowns:
- Fire Zone A31, Control Room;
- Fire Zone A24, 4160 Volts Vital Switchgear Room;
- Fire Zone A25, D06 Battery Room;
- Fire Zone A26, D05 Battery Room;
- Fire Zone A27, G-01 Diesel Generator Room;
- Fire Zone A28, G-02 Diesel Generator Room;
- Fire Zone A29, Air Compressor Room;
- Fire Zone A30, Cable Spreading Room;
- Fire Zone 311/A01-E, AFW Tunnel;
- Fire Zone A34, Technical Support Center; and
- Fire Zone 208/A01-D, Radwaste Solidification Area.
b. Findings
No findings of significance were identified.
.2 Annual Resident Inspector Observation of Unannounced Fire Drill
a. Inspection Scope
The inspectors observed an unannounced drill in the AFW pump room on March 10, 2004, to evaluate licensee personnels readiness and response capabilities to fight fires at the facility. The inspectors observed licensee performance in donning protective clothing/turnout gear and self-contained breathing apparatus, deploying firefighting equipment and fire hoses to the scene of the fire, entering the fire area in a deliberate and controlled manner, maintaining communications, checking for victims and propagation of fire and smoke into other plant areas, and using pre-planned firefighting strategies to evaluate the effectiveness of the brigade. The inspectors also observed control room activities to evaluate the effectiveness of command and control, and radio communications. The inspectors observed the post-drill critique to evaluate the effectiveness and thoroughness of self-identification of problems. Documents reviewed during this inspection are listed in the attachment to this report. This observation constituted one annual inspection sample.
b. Findings
No findings of significance were identified.
1R06 Flood Protection Measures - External Floods
a. Inspection Scope
During the week of February 23, 2004, the inspectors completed one internal flood protection quarterly inspection sample. The inspectors evaluated flood protection features, such as flood doors, door gaps, and subsoil drains, to determine if the features were in satisfactory physical condition, unobstructed, and capable of providing an adequate flood barrier. The inspectors reviewed design basis documents and risk analyses to determine plant vulnerabilities and protective features relating to potential flooding from external water sources. Documents reviewed during this inspection are listed in the attachment to this report.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification
a. Inspection Scope
On January 15, 2004, the inspectors observed the operating crew performance during simulator training. The inspectors also reviewed some of the changes to the simulator model against modifications made in the plant. 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 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 issue/problem-oriented reviews of the systems listed below, completing three maintenance effectiveness inspection samples. The inspectors reviewed repetitive maintenance activity 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 CFR 50.65) requirements, including a review of scoping, goal-setting, performance monitoring, short-term and long-term corrective actions, functional failure determinations associated with reviewed condition reports, and current equipment performance status.
For each system reviewed, the inspectors reviewed significant WOs and CAPs to determine if failures were properly identified, classified, and corrected, and that unavailable time had been properly calculated. The inspectors reviewed documents listed in the attachment to determine if minor discrepancies in the licensees maintenance rule reports were corrected.
Specific components and systems reviewed were:
- Residual Heat Removal (RHR) System
- Control Room Ventilation System
- Service Air 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 six quarterly inspection samples.
- unavailability of the SI and RHR motors and valves for planned maintenance testing on week of January 4, 2004;
- unavailability of the A SI pump discharge flow meter, and the reactor protection and safeguards analog rack steam generator level instrumentation for planned maintenance on week of January 18, 2004;
- unavailability of the G-02 emergency diesel generator (EDG) for planned maintenance on week of February 1, 2004;
- unavailability of the Unit 2 B CCW pump for planned maintenance on week of February 15, 2004;
- unrecognized entry into the next level of risk for planned maintenance due to a surveillance on B RHR Pump Discharge Pressure Transmitter, 1PT-629, during the week of February 29, 2004; and
- surveillance on B RHR Pump Discharge Pressure Transmitter, 1PT-629, during the week of March 7, 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 determined if the evaluation, planning, control, and performance of the work were done in a manner to reduce the risk and minimize the duration, where practical, and if 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 equipment configuration had been properly listed, protected equipment had been identified and was being controlled where appropriate, and 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 Unexpected Control Rod Motion During Installation of a Source Range Nuclear
Instrument (SRNI) Drawer
a. Inspection Scope
On January 28, 2004, the inspectors observed operator response to Unit 1 uncontrolled rod motion caused by an electrical short circuit during re-installation of the 1N-31 SRNI drawer. The inspectors reviewed the resulting Unit 1 plant transient which included automatic rod motion, loss of a safety-related inverter power supply, and loss of nine main control board indications. The inspectors interviewed selected personnel and reviewed control room operator action to stabilize plant conditions, perform Abnormal Operating Procedure AOP 6C, adhere to Technical Specification Action Condition (TSAC) entry and action requirements, maintain accurate log records, restore control board indications, and evaluate and control other ongoing engineering safeguards system maintenance. The inspectors also reviewed the ability of the licensee to identify electrical power in the SRNI cabinet and the use of past operating experience.
Documents reviewed during this inspection are listed in the attachment to this report.
This observation constituted one inspection sample.
b. Findings
No findings of significance were identified.
.2 Response to a Medical Event
a. Inspection Scope
On March 23, 2004, the inspectors observed the licensees response to a medical event involving a non-licensed operator assigned to a dedicated operator position. This observation constituted one inspection sample.
b. Findings
No findings of significance were identified.
.3 Power Reduction Due to an Out-of-Specification Unit 2 A SI Accumulator Level
Indication
a. Inspection Scope
On March 30, 2004, the inspectors observed a power reduction that was conducted after SI Accumulator T-34A was determined to be inoperable because the water volume exceeded the maximum limit of 1136 cubic feet allowed by TS 3.5.1. The operability of the SI accumulator level instruments were in question due to one of the two indicators being within the normal range (LT-938) and the other, which had recently been replaced under a modification, being off-scale high (LT-939). During troubleshooting activities, an ultrasonic detector revealed that the level was above the high scale indication, and the accumulator was declared out-of-service, due to the liquid volume being greater than allowed by TS 3.5.1. Accumulator water level was lowered by draining, which resulted in a decrease of the nitrogen cover gas below the TS minimum. A power reduction in preparation for reactor shutdown was then commenced, in accordance with normal plant procedures, because the nitrogen pressure could not be restored to the minimum limit within the time allotted by the TS. When pressure was restored to the TS minimum, the power reduction was stopped at 82 percent. Inspectors then observed the power increase to full load. Troubleshooting indicated that LT-938 gave a false low reading because of water in the dry reference leg. The water was drained from the reference leg and LT-938 was returned to service. Documents reviewed during this inspection are listed in the attachment to this report. This observation constituted one inspection sample. A potential licensee-identified violation associated with exceeding the TS 3.5.1 accumulator level limit will be dispositioned in the next NRC quarterly inspection report after review of the required 10 CFR 50.73 licensee event report. This report is due for submission to the NRC by the licensee in late May 2004.
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:
- EAL 6.1.1, Natural Destructive Phenomena: Earthquake
- Symptomatic Vibration of G-01 EDG Bearing;
- Unit 1 & 2 Submerged SI Pump Power Supply Cables; and
- Submerged 4160-Volt Cables to Train 'B' SI Motors These reviews constituted five quarterly inspection samples.
The inspectors reviewed the technical adequacy of the operability evaluations against TS, FSAR, and other design information; determined whether compensatory measures, if needed, were taken; and determined whether the evaluations were consistent with Procedure NP 5.3.7, Operability Determinations. 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.
.2 (Closed) Unresolved Item (URI) 05000266/2003009-06: This URI concerned the
installation of a nonsafety-related metallic part (worm gear) in the 1AF-4000, 1P-29 AFW Pump Discharge to B Steam Generator, motor-operated valve (MOV). This issue was previously discussed in Inspection Report 05000266/2003009; 05000301/2003009 (Section 15.2), and was identified by maintenance personnel during the last Unit 2 refueling outage. Initial material hardness testing indicated that the 1AF-4000 worm gear had about one-half of the material strength of the intended safety-related part. The inspectors reviewed the licensees engineering evaluation and material and fatigue property analyses to evaluate the ability of 1AF-4000 to have performed the intended safety function. The inspectors review of the licensees evaluation and analyses constituted one inspection sample.
In reviewing the licensees analyses, the inspectors considered the worm gear fatigue life, the number of strokes required of 1AF-4000 during the most limiting transients and design basis events, and whether a change in the failure rate had to be included in probabilistic risk assessment models. The inspectors reviewed vendor calculations concerning the worm gear fatigue life and determined that sufficient margin existed to ensure that the nonsafety-related worm gear would have been able to perform the intended safety-related function. Specifically, the inspectors evaluated and found acceptable licensee date that indicated the worm gear had a remaining fatigue life of 135 cycles, while the most limiting accident would have required 84 cycles. The inspectors also reviewed portions of NUREG/CR-6819, Volume 2, Common-Cause Failure Event Insights - Motor Operated Valves, and determined that the installation of the nonsafety-related worm gear would not have significantly changed the probabilistic risk assessment worm failure rate. This licensee-identified issue is dispositioned in Section 4OA7.
1R16 Operator Workarounds (OWAs)
.1 Cumulative Effect of OWAs
a. Inspection Scope
Using the OWA list effective during the week of January 21, 2004, the inspectors evaluated the cumulative effect of these workarounds on plant operations. The inspectors evaluated outstanding OWAs to determine the overall complexity and aggregate effects on operator performance. The inspectors also reviewed selected control room WO deficiency tags and OWA meeting minutes to determine if the licensee had conducted periodic reviews and considered the total impact of outstanding WOs on risk and plant operations. Documents reviewed during this inspection are listed in the attachment to this report. This observation constituted one inspection sample.
b. Findings
No findings of significance were identified.
.2 Selected OWAs
a. Inspection Scope
The inspectors reviewed OWAs with particular focus on the method by which instructions and contingency actions were communicated to and reviewed with on-shift licensed operators. Documents reviewed during this inspection are listed in the attachment to this report. These observations constituted five inspection samples.
The inspectors completed the samples by reviewing:
- CAP053486 relating to licensees procedures that had potential OWAs for avoiding a steam generator blowdown water hammer,
- CAP054483 relating to licensees procedures that had potential OWAs for having the boric acid blend totalizer in Manual,
- CAP054491 relating to licensees procedures that had potential OWAs having to make manual data entry into the plant process computer,
- CAP033205 which described an unexpected 125 Volts Direct Current Bus under/over voltage alarm concurrent with the start of SW Pump P-32F despite a previous modification to install time delay relays to resolve an OWA, and
- CAP002262 related to gas binding of SI pumps that resulted in a corrective action to establish periodic venting, and modifications to provide high point vents to facilitate frequent venting.
b. Findings
No findings of significance were identified.
1R17 Permanent Plant Modifications
a. Inspection Scope
During the weeks of March 8 and 15, 2004, the inspectors conducted a review of a modification that replaced the level transmitter 2LT-939 for SI accumulator 2T-34A. The purpose of the modification was to increase reliability and decrease uncertainty in the indicated level of the accumulator. The inspection activities included observing the review of the modification by the Design Review Board and in-office review of the design change CL, the 10 CFR 59.59 screening, the design document CL, and the drawing change requests. These activities constituted one inspection sample. The documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing (PMT)
.1 Safety-Related SW Isolation Valve Removed From Service Without Appropriate TS
Action Condition Entry Being Made
a. Inspection Scope
On January 12, 2004, the licensee identified that the operating crew had not entered the required TSAC when a safety-related water treatment system supply valve, SW-2817, was removed from service for scheduled replacement of the MOV actuator. During the weeks of January 17 and February 9, 2004, the inspectors reviewed PMT for the replacement to determine if the testing was adequate for the scope of the work performed and the equipment remained capable of performing the intended function.
The inspectors also reviewed the completed test data, WO documentation, and selected tagout series to ensure that applicable TSAC entries had been made and that data was complete, appropriately verified, and met the acceptance criteria requirements of the test procedure. Documents reviewed during this inspection are listed in the attachment to this report. This observation constituted one quarterly inspection sample.
b. Findings
A licensee-identified violation associated with PMT of the valve is dispositioned in Section 4OA7.
.2 Selected PMT Reviews
a. Inspection Scope
During this inspection period, the inspectors completed five quarterly inspection samples, composed of the following PMT activities:
- Containment Spray Pump 1P-14B Discharge Isolation Valve 1SI-860D on January 9, 2004,
- 1A05 (4160) and 1A04 (4160) Bus Voltmeters on Main Control Board,
- 2G-07 Motor Generator Set Voltage Regulator Replacement on January 9, 2004,
- K-3B Service Air Compressor PMT Failure and Rework on February 3, 2004, and
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 the following surveillance testing activities:
- G-05 Gas Turbine Instrument Calibration on January 11, 2004,
- Unit 1 Reactor Protection and Safeguards Analog Racks Flux Mismatch 18 Month Calibration on January 16, 2004,
- G-01 EDG Slow Start Test on January 25, 2004,
- G-02 EDG Repairs and the Testing and Return to Service on February 13, 2004,
- Containment Spray Pump and Valve Surveillance on January 9, 2004, and
- Unit 2 SI Accumulator T-34A Level Detector LT-939 return to service on March 18, 2004.
Documents reviewed during this inspection are listed in the attachment to this report.
These observations constituted seven 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 for in-service testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers Code, and reference values were consistent with the system design basis;
- 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
.1 Temporary Modifications (TMods)
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 TMods detailed below. The inspectors reviewed design basis documents 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 determine if the impacts, if any, of the TMods on permanent and interfacing systems were adequately evaluated by the licensee. Documents reviewed during this inspection are listed in the attachment to this report. These observations constituted two inspection samples.
The inspectors reviewed the following TMods:
- TMod Number 03-035; U1 - Facade Cable Tray Heating Tent. This TMod provided winter heating to the southwest corner of the Unit 1 facade.
- Unit 2 Pressurizer Level Transient on February 4, 2004; Installation of Trend Recorder.
b. Findings
No findings of significance were identified.
.2 Unit 1 Containment Hatch Interlock Cable Engineering Design Change Not Per
Procedure
a. Inspection Scope
During the week of March 22, 2004, the inspectors reviewed the circumstances associated with the replacement of the Unit 1 containment hatch interlock push-pull cable. The inspectors reviewed the existing plant configuration at the time of the event as well as the human performance, communications, procedure use and adherence, and the replacement of the cable in June 2000 to determine if the engineering design change process had been conducted in accordance with the licensees policies, procedures, and expectations. 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 an NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, having very low safety significance (Green), for failing to properly document a modification of the containment interlock. The cable subsequently parted on March 15, 2004, when the containment hatch was needed to be opened for a routine entry. This issue was considered to be NRC-identified because the licensee failed to identify that the design change had not been properly documented without the inspectors questions.
Description:
During a routine Unit 1 containment entry, the outer containment hatch did not operate correctly. The shift manager (SM) declared the containment hatch inoperable and entered TS 3.6.2.B, Containment Air Locks. The licensee investigated the containment hatch operating mechanism and discovered that the containment door interlock push-pull cable had parted. A WO was written to replace the cable. The licensee discovered that the installed cable was not the same as the cable identified in the drawings. The licensee reviewed the WO that had been used to install the cable in June 2000 and determined that the documentation was sufficient for the modification, based on procedure revisions in effect at the time of the installation. In CAP054869, Wrong Push Pull Cable on Containment Outer Door Personal Airlock, it states This was due to the result of an unauthorized mod (by todays definitions).... When questioned by the inspectors, the licensee indicated that the TMods procedure, NP (Nuclear Plant Procedures Manual) 7.3.1, did allow modifications to nonsafety-related procedures, during the time that the modification was made.
The inspectors identified that although Procedure NP 7.3.1, TMods, did allow modifications of some plant components using WOs, they were listed by CHAMPS ID systems. The component that was replaced did not meet the exception requirements and was therefore not installed in accordance with revisions of the plant engineering design change NP 7.2.6, Revision 1, Engineering Change Process, or NP 7.3.1, Revision 11, TMods, that were in effect at the time of the modification.
Analysis:
The inspectors determined that performing a plant modification without proper engineering design change controls was a performance deficiency warranting a significance evaluation in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on June 20, 2003. The inspectors determined that the finding was more than minor because it affected the barrier integrity reactor safety cornerstone objective attribute of maintaining functionality of containment design control.
The inspectors completed a significance determination of this issue using IMC 0609, SDP, dated March 21, 2003, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, dated March 18, 2002. The inspectors determined that the finding did not result in an actual open pathway in the physical integrity of the reactor containment, or actual reduction of the atmospheric pressure control function of the reactor containment. Therefore, the finding was considered to be of very low safety significance (Green).
Enforcement:
Appendix B, 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that design changes, including field changes, be subject to design control measures commensurate with those applied to the original design and be approved by the organization that performed the original design. Contrary to the above, on June 30, 2000, the Unit 1 containment interlock push-pull cable in the upper hatch was replaced without performing the required design modification in accordance with established plant procedures.
This violation was entered into the licensee's corrective action program as CAP054869, Wrong Push Pull Cable on Containment Outer Door Personal Airlock. 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. of the NRC Enforcement Policy. (NCV 05000301/2004002-01)
1EP6 Drill Evaluation
.1 Emergency Plan Procedure Training Drills
a. Inspection Scope
During the weeks of February 12 and 26, 2004, the inspectors observed the training drills involving the revised EALs and Emergency Plan Implementing Procedures (EPIPs). The inspectors observed classifications, notifications, facility activations, and facility critiques. The observations were in the Control Room (simulator), Technical Support Center, and Emergency Operations Facility. The inspectors also observed the training of new Emergency Response Organization personnel. These observations constituted two inspection samples.
b. Findings
No findings of significance were identified.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety (OS)
2OS1 Access Control to Radiologically Significant Areas (71121.01)
.1 Plant Walkdowns and Radiation Work Permit (RWP) Reviews
a. Inspection Scope
The inspectors reviewed licensee controls and surveys for a variety of radiologically significant work areas within radiation areas and high radiation areas (HRAs) in the plant, and reviewed work packages, which included associated licensee controls and surveys of these areas, to determine if radiological controls, including surveys, postings and barricades, were acceptable. In particular, the radiological controls for significant work areas on selected elevations of the auxiliary building and in the radwaste truckbay were evaluated.
Documents reviewed during this inspection are listed in the attachment to this report.
These reviews represented one inspection sample.
b. Findings
No findings of significance were identified.
.2 Problem Identification and Resolution
a. Inspection Scope
The inspectors reviewed seven corrective action reports related to access controls and HRA radiological incidents. Staff members were interviewed and corrective action documents were reviewed to determine if follow-up activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk based on the following:
- 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 NCVs tracked in the corrective action system; and
- Implementation/consideration of risk significant operational experience feedback.
The inspectors reviewed licensee documentation packages for all events related to the radiation safety performance indicator (PI) occurring since the last inspection to determine if any of these PI events involved dose rates >25 Roentgens/hour (R/hr) at 30 centimeters or >500 R/hr at 1 meter. If such PI events were identified, event documentation was evaluated to assess what barriers failed and to determine if there were any barriers left to prevent personnel access. Also, if PI events were identified, unintended exposures of >100 millirem total effective dose equivalent (or >5 rem shallow dose equivalent or >1.5 rem lens dose equivalent), were evaluated to determine if there were any regulatory overexposures or if there was a substantial potential for an overexposure.
Documents reviewed during this inspection are listed in the attachment to this report.
These reviews represented two inspection samples.
b. Findings
No findings of significance were identified.
.3 Job-In-Progress Reviews
a. Inspection Scope
The inspectors observed the following job that was being performed in radiologically significant areas for observation of work activities that presented the greatest radiological risk to workers:
- Lift and Loading of a Radioactive Waste Liner from the Decon Pit to the Shipping Cask on the Flatbed Trailer in the Truck Bay The inspectors reviewed radiological job requirements for this activity, including RWP requirements and work procedure requirements, and attended As-Low-As-Is-Reasonably-Achievable (ALARA) job briefings.
Job performance was observed with respect to these requirements to determine if radiological conditions in the work area were adequately communicated to workers through pre-job briefings and postings. The inspectors also reviewed the adequacy of radiological controls, including required radiation and contamination surveys, radiation protection job coverage, and contamination controls.
b. Findings
No findings of significance were identified.
.4 Radiation Worker Performance and Radiation Protection Technician Proficiency
a. Inspection Scope
The inspectors reviewed a variety of radiological problem reports, during or since the previous refueling outage, which found that the cause of the event was due to radiation worker errors or radiation protection technician errors, to determine if there was an observable pattern traceable to a similar cause, and to determine if this perspective matched the corrective action approach taken by the licensee to resolve the reported problems. These problems, along with planned and taken corrective actions, were discussed with the Radiation Protection Manager.
Documents reviewed during this inspection are listed in the attachment to this report.
These reviews represented two inspection samples.
b. Findings
No findings of significance were identified.
2OS2 ALARA Planning and Controls (71121.02)
.1 Inspection Planning
a. Inspection Scope
The inspectors reviewed procedures associated with maintaining occupational exposures ALARA and processes used to estimate and track work activity specific exposures to determine if the procedures and processes incorporated appropriate dose minimization practices and considerations.
These reviews represented one inspection sample.
b. Findings
No findings of significance were identified.
.2 Radiological Work Planning
a. Inspection Scope
The inspectors evaluated the licensees list of work activities ranked by estimated and actual exposure that were conducted during the fall 2003 Unit 2 refueling outage, (U2R26) and reviewed these work activities of highest exposure significance:
For these activities, the inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements to determine if the licensee had established procedures and engineering and work controls that were based on sound radiation protection principles in order to achieve occupational exposures that were ALARA. This also involved determining if the licensee had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances.
The inspectors compared the results achieved including dose rate reductions and person-rem used with the intended dose established in the licensees ALARA planning for these work activities. Reasons for inconsistencies between intended and actual work activity doses were reviewed. Additionally, the licensees post-job (work activity)reviews were evaluated to determine if identified problems were entered into the licensees corrective action program.
Documents reviewed during this inspection are listed in the attachment to this report.
These reviews represented three inspection samples.
b. Findings
No findings of significance were identified.
.3 Verification of Dose Estimates and Exposure Tracking Systems
a. Inspection Scope
The inspectors reviewed the assumptions and bases for the current 2004 annual collective exposure estimates, in order to evaluate the licensees methodology for estimating work activity-specific exposures and the intended dose outcome. Dose rate and person-hour estimates were evaluated for reasonable accuracy.
Documents reviewed during this inspection are listed in the attachment to this report.
These reviews represented one inspection sample.
b. Findings
No findings of significance were identified.
.4 Problem Identification and Resolution
a. Inspection Scope
The inspectors reviewed the corrective action program database to determine if identified problems with ALARA planning and controls were entered into the program for resolution and if they had been properly characterized, prioritized, and resolved. This included dose significant post-job (work activity) reviews for U2R26 and post-outage ALARA report critiques of exposure performance.
Documents reviewed during this inspection are listed in the attachment to this report.
These reviews represented one inspection sample.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
4OA1 PI Verification
Cornerstones: Initiating Events, Mitigating Systems, and Occupational Radiation Safety
.1 Reactor Safety Strategic Area - Initiating Events and Mitigating Systems Cornerstones
a. Inspection Scope
The inspectors reviewed the licensees recent PI submittal. The inspectors 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. The inspectors reviewed selected applicable conditions and data from logs, licensee event reports, and corrective action program documents from January 2002 through January 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 four inspection samples. The following PIs were reviewed:
Unit 1
- High Pressure SI System, Safety Systems Unavailability
- Unplanned Transients per 7000 Critical Hours Unit 2
- High Pressure SI System, Safety Systems Unavailability
- Unplanned Transients per 7000 Critical Hours
b. Findings
No findings of significance were identified.
.2 Radiation Safety Strategic Area - Occupational Radiation Safety Cornerstone
a. Inspection Scope
The inspectors sampled licensee submittals for the PIs listed below for the period of January 2003 to December 2003. To determine the accuracy of the PI data reported during that period, the inspectors used PI definitions and guidance contained in Revision 2 of Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline.
Documents reviewed during this inspection are listed in the attachment to this report.
This observation constituted one inspection sample. The following PI was reviewed:
Dual Unit
- Occupational Exposure Control Effectiveness The inspectors previously reviewed the one very high radiation area occurrence under this PI which occurred in October 2003 (see Inspection Report 05000266/2003009; 05000301/2003009, Section 2OS1.4). Since no additional reportable events were identified by the licensee for the 1st quarter through the 4th quarter of 2003, the inspectors compared the licensees data with the CAP database and the radiological controlled area exit electronic dosimetry transaction records for these time periods, to determine if there were no unaccounted for occurrences in the Occupational Radiation Safety PI. Additionally, the inspectors conducted walkdowns of accessible locked HRA and very high radiation area entrances to determine the adequacy of controls in place for these areas.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
.1 Untimely Response to Correct EALs and Achieve Regulatory Compliance
a. Inspection Scope
During the week of August 12, 2003, the NRC inspection procedure 95003 emergency preparedness/emergency planning team identified that eight Emergency Plan EALs had been changed that decreased the effectiveness of the Emergency Plan without prior NRC approval. The inspectors reviewed the timeliness of the licensees corrective actions to achieve regulatory compliance.
b. Issues This issue was documented by the licensee as CAP034784, NRC 95-003-1 Inspection Team Questions on EALs, on August 12, 2003. The CAP was erroneously categorized at the CAP screening meeting as a level C problem and was considered a legacy issue, an old issue for which corrective actions were already in-place. Because of this miscategorization and internal miscommunications, the licensee did not identify the need for a root cause evaluation (RCE) and implementation of corrective actions until early January 2004. The RCE was subsequently completed on January 12, 2004, one day before the pre-decisional enforcement conference to discuss the issue.
At the conference on January 13, the licensee discussed the RCE (RCE000241, Change of EAL Scheme Resulted in Apparent Violation); however, the actions taken as of that time were inadequate to correct the violation. After the pre-decisional enforcement conference, discussions were held between the NRC and the licensee regarding a schedule for revising the EALs and achieving compliance. Appropriate procedure revisions were implemented late on January 16.
.2 Steam Generator Narrow Range (SGNR) Level Setpoints Revised in Safety-Related
Procedures But Not In Emergency Plan General Emergency EAL 3.1.1.4
a. Inspection Scope
During the weeks of January 18 and February 29, 2004, the inspectors reviewed the adequacy and thoroughness of corrective actions associated with a previously identified NRC issue concerning the failure to account for the impact of varying water density differences on the SGNR level detector variable leg, when transitioning from hot to cold plant conditions. Specifically, the inspectors evaluated the ability of the licensee to perform adequate extent-of-condition reviews and recognize the impact of safety-related procedure changes on the Point Beach Emergency Plan. This observation constituted one inspection sample.
b. Findings
Introduction:
A Green finding was identified concerning an inadequate extent-of-condition review during safety-related procedure revisions associated with SGNR level setpoints, and the failure to recognize the impact of the setpoint changes on the Point Beach Emergency Plan. The finding was not considered a violation of regulatory requirement.
Description:
This SGNR level setpoint issue had previously been determined to be of very low risk significance (Green) and was dispositioned as an NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, in Inspection Report 05000266/2002010; 05000301/2002010, Section 1R20.1. In addition, Inspection Report 05000266/2002006; 05000301/2002006, Section 4OA2.1, discussed the observation that the licensees initial extent of-condition review had identified that only the control room daily log sheet required revisions. The inspectors subsequently reviewed the rigor of the review and identified that the SGNR setpoints used in safety-related shutdown emergency procedure (SEP) 3.0, Loss of All AC [Alternating Current] Power to a Shutdown Unit - Unit 1, Revision 12, and SEP 3.0, Loss of All AC Power to a Shutdown Unit - Unit 2, Revision 13, created the possibility of uncovering the secondary side of the top of the steam generator U-tubes, thereby impacting the ability to remove reactor decay heat. Following the inspectors observation, the licensee re-performed the extent-of-condition review and identified 12 other safety-related procedures requiring revisions. The inspectors concluded that the licensee's initial extent of condition review concerning the density compensation issue had not been sufficiently rigorous to identify the full impact of the issue on plant operations, and that the apparent cause had been associated with a failure in the internal communication process.
In monitoring the licensees corrective actions to achieve regulatory compliance with the eight EALs discussed in the previous section of this report, the inspectors identified that the SGNR setpoints associated with SEP 3.0 differed from those of General Emergency EAL 3.1.1.4. Specifically, SEP 3.0, Step 5b., required that if at least one steam generator was not capable of being filled to 38 percent for normal containment conditions or 59 percent for adverse containment conditions, then the operators were required to implement the Emergency Plan. General Emergency EAL 3.1.1.4 and the corresponding EPIP, however, used corresponding setpoints of 29 and 51 percent. The inspectors reviewed the SEP 3.0 background document and EPIP 1.2 for EAL 3.1.1.4 and noted that the intent of both documents was to recognize the loss of the reactor heat sink.
The inspectors reviewed the temporary procedure change and 10 CFR 50.59 safety evaluation screening that changed the safety-related procedure setpoints to 38 and 59 percent. The inspectors determined that despite at least four personnel, including a SM and two SROs, having reviewed the procedure change and 10 CFR 50.59 screening, no one recognized the impact of the procedure changes on the Emergency Plan. In addition, the inspectors could not find any record that the operations department or corrective action program personnel had recognized the potential impact of the SGNR issue on the Emergency Plan and raised the issue to the attention of emergency preparedness personnel.
The inspectors reviewed the current temporary procedure change and 10 CFR 50.59 screening controls and noted that the present process included consideration and review of the potential impact of procedure changes on the Emergency Plan. Also, the inspectors noted that despite the emergency preparedness reviews completed prior to and during the 95003 supplemental inspection process, the licensee had not identified and evaluated the potential impacts of the discrepancy between the SGNR safety-related procedure setpoints and EAL 3.1.1.4.
Analysis:
The inspectors determined that the failure to recognize and evaluate the potential impacts of revising safety-related procedure SGNR level setpoints on the Point Beach Emergency Plan was a performance deficiency warranting a significance evaluation in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on June 20, 2003. This finding was considered more than minor because it:
- (1) involved the procedure quality attribute of the Reactor Safety/Emergency Preparedness cornerstone; and
- (2) if left uncorrected, it could become a more significant safety concern if the discrepancy in SGNR setpoints prevented, or caused a delay in, declaring a general emergency during a loss of electrical power event.
Also, the inspectors determined that not recognizing and evaluating the potential impacts of revising safety-related procedure SGNR level setpoints on the Point Beach Emergency Plan affected the cross-cutting area of human performance in four respects.
First, at least four personnel, including a SM and two SROs, reviewed the SEP 3.0 procedure change and 10 CFR 50.59 screening but failed to recognize the potential impact of the procedure changes on the Emergency Plan. Second, personnel associated with the corrective action process for the NCV discussed in Inspection Report 05000266/2002010; 05000301/2002010 failed to recognize the potential impact of the SGNR issue on the Emergency Plan and raise the issue to the attention of emergency preparedness personnel. Third, despite the emergency preparedness reviews completed prior to and during the 95003 supplemental inspection process, the licensee had not identified and evaluated the potential impacts of the discrepancy between the SGNR SEP setpoints and EAL 3.1.1.4. Fourth, until identified by the inspectors, personnel involved with efforts to achieve regulatory compliance with eight EALs during January 2004, had not recognized or evaluated the potential impact of the discrepancy. Finally, the inspectors noted that the apparent cause of the original SGNR level setpoint issue, a failure in the internal communication process, was also a contributing cause to this issue in that successful communications between operations, corrective action program, and emergency preparedness personnel would have promoted licensee self-identification of the setpoint discrepancy.
The inspectors completed a significance determination of the issue using IMC 0609, SDP, Appendix B, Emergency Preparedness Significance Determination Process, dated March 6, 2003. The inspectors determined that the Finding was considered to be of very low safety significance (Green), since it did not result in the failure to comply with a planning or risk significant planning standard.
Enforcement:
Point Beach maintains an emergency preparedness program in accordance with NUREG 0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, guidance which does not require shutdown EALs. In addition, the inspectors determined that the discrepancy between the safety-related SEP and the EAL 3.1.1.4.
SGNR level setpoints would account for less than 8 inches of actual height difference at the top of the steam generator U-tubes, a difference that would result in a minimal delay in transitioning between SEP 3.0 and declaring a General Emergency in accordance with EAL 3.1.1.4. Because
- (1) Point Beach was not licensed to an emergency preparedness scheme requiring shutdown EALs;
- (2) the discrepancy between the SGNR setpoints would not have appreciably impacted steam generator heat removal capabilities; and
- (3) the health and safety of the public would not have been impacted; no violation of regulatory requirements occurred. This issue was considered a finding of very low safety significance (FIN 05000266/2004002-02; 05000301/2004002-02). The licensee entered the finding into its corrective action program as CAP052916, EAL Setpoint in Question, dated January 16, 2004.
4OA4 Cross-Cutting Aspects of Findings
A finding discussed in Section 4OA2.2 of this report had, as its primary cause, a human performance deficiency in four respects. First, at least four personnel, including a SM and two SROs, reviewed the procedure changes but failed to recognize the potential impact of the procedure changes on the Emergency Plan. Second, personnel associated with the corrective action process for the initial steam generator narrow range level density compensation issue failed to recognize the potential emergency plan impact and raise the issue to the attention of emergency preparedness personnel.
Third, despite the emergency preparedness reviews completed, prior to and during the 95003 supplemental inspection process, the licensee had not identified and evaluated the potential impacts of the discrepancy between the procedure setpoints and Emergency Action Level 3.1.1.4. Fourth, until identified by the inspectors, personnel involved with efforts to achieve regulatory compliance with the eight EALs, during January 2004, had not recognized or evaluated the potential impact of the discrepancy.
4OA5 Other Activities
(Closed) Unresolved Item URI 05000266/2003009-03; 05000301/2003009-03: Sprinkler head locations not in accordance with fire code. The inspectors identified that the licensee had failed to install sprinklers in accordance with the applicable fire code in the CCW pump area of the auxiliary building, in that the sprinkler heads were located a greater distance below the ceiling than permitted by code (see Section 1R05.b.2 of Inspection Report 05000266/2003009; 05000301/2003009 for details).
Analysis:
In accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, the inspectors determined that the issue was more than minor because the finding was associated with the protection against external factors (i.e., fire) attribute of the Mitigating Systems reactor safety cornerstone and affected the Mitigating Systems objective in that a fire protection feature (i.e., an automatic suppression system) was adversely affected. In accordance with IMC 0609, Appendix A, the inspectors performed a SDP Phase 1 screening and determined that the finding degraded the Fire Protection portion of the Mitigation Systems Cornerstone.
As such, screening under IMC 0609, Appendix F, was required. Based on review of IMC 0609, Appendix F, the inspectors determined that the finding required a Phase 2 evaluation, since a fire protection feature was affected. The nonconforming location of the sprinkler heads would result in delay in activation of the sprinkler system because it would take a deeper (i. e., increased distance from the ceiling) hot gas layer to activate individual sprinkler heads. As such, the inspectors considered the sprinkler system in the CCW pump area to be moderately degraded. The licensee presented the ignition frequencies in the fire zone as 3.9 x 10-4 for pumps, 8.3 x 10-5 for electrical cabinets, 1.86 x 10-5 for transient combustibles, 4.18 x 10-4 for unqualified cables, and 7.1 x 10-5 for a ventilation system. The inspectors determined that credit for manual fire fighting, the availability of a turbine-driven AFW pump, and a motor-driven AFW pump (through a proceduralized manual action) was appropriate. As such, the inspectors concluded that the issue was of very low safety significance (Green).
Enforcement:
License condition 3.H requires, in part, that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the FSAR for the facility. Section 9.10.1 of the FSAR states, in part, that the fire protection program is outlined in the Fire Protection Evaluation Report (FPER).
Section 6.3.1 of the FPER stated, in part, that NFPA (National Fire Protection Association) 13 provided dimensional guidance and criteria necessary for installation or evaluation of an existing water suppression system. Section 6.3.3 of the FPER stated, in part, that fixed water extinguishing systems were designed and installed in accordance with applicable portions of NFPA 13.
Section 4-3.1.1 of NFPA 13-1978, specified that deflectors of sprinklers in bays shall be located 1 inch to 12 inches below noncombustible smooth ceilings. Contrary to the above, as of October 16, 2003, the inspectors identified 6 ceiling level sprinkler heads in the CCW pump area which were located in excess of 12 inches below the ceiling. The licensees failure to install a sprinkler system in accordance with NFPA 13, as described above, is a violation of license condition 3.H. This violation is associated with a finding that is characterized by the SDP as having very low risk significance (Green) and is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy.
This issue was entered as CAP051175. (NCV 05000266/2004002-03; 05000301/2004002-03)
4OA6 Meetings
.1 Exit Meeting
On April 5, 2004, the resident inspectors presented the inspection results to Mr. G. Van Middlesworth and members of his staff, who acknowledged the findings. The licensee did not identify any information, provided to or reviewed by the inspectors, as proprietary in nature.
.2 Interim Exit Meeting
- Occupational Radiation Safety ALARA and access control programs inspection with Mr. F. Cayia on January 30, 2004. A follow-up interim exit meeting relative to aspects of the ALARA and access control programs inspection was held telephonically with Mr. J. McCarthy on February 6, 2004.
4OA7 Licensee-Identified Violations
The following violations of very low significance were identified by the licensee and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Manual, NUREG-1600, for being dispositioned as NCVs.
Cornerstone: Mitigating Systems
- Criterion V, Instructions, Procedures, and Drawings, of Appendix B of 10 CFR Part 50, requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and be accomplished in accordance with these instructions, procedures, or drawings. Safety-related routine maintenance procedure RMP 9376-6, Limitorque Motor Operator Model SMB-00 Disassembly, Inspection, Repair, and Re-assembly, Revisions 2 and 4, Step 3.3, required all safety-related motor operators to use qualified replacement parts and materials.
Contrary to the above, between April 28, 2001, and November 1, 2003, the requirements of RMP 9376-6, Step 3.3, were not met in that an unqualified, nonsafety-related worm was installed in the 1AF-4000, 1P-29 AFW Pump Discharge to B Steam Generator, MOV. The licensee entered the issue as CAP051530, Non QA [Quality Assurance] Worm and Worm Gear used in QA Application for Limitorque Operator SMB-00.
- Criterion V, Instructions, Procedures, and Drawings, of Appendix B of 10 CFR Part 50, requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and be accomplished in accordance with these instructions, procedures, or drawings. Safety-related procedure RMP 9376-1, Limitorque MOV [Motor-Operated Valve] Removal/Installation/Swap and Testing for Gate and Globe Valves, Step 4.3, directed that if a TSAC was required, then the appropriate entry be made. Contrary to the above, on January 12, 2004, maintenance on water treatment system supply valve, SW-2817, was not accomplished in accordance with procedure RMP 9376-1, Step 4.3, in that several licensed operators, WCC personnel, and the STA failed to recognize that entry into TSAC 3.7.8.D was required when removing the valve from service.
The licensee entered the condition as CAP052765, Tag Series 0 SW SW-2817 Tech Spec Ops Rev 0-1 Not Hung As Required.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- G. Van Middlesworth, Site Vice-President
- J. McCarthy, Site Director of Operations
- J. Shaw, Plant Manager
- J. Connolly, Regulatory Affairs Manager
- J. Brander, Maintenance Manager
- G. Casadonte, Fire Protection Coordinator
- J. Schweitzer, Site Engineering Director
- R. Milner, Business Planning Manager
- M. Holzmann, Nuclear Oversight Manager
- G. Sherwood, Engineering Programs Manager
- R. Hopkins, Internal Assessment Supervisor
- C. Jilek, Maintenance Rule Coordinator
- T. Kendall, Program Engineering
- B. Kopetsky, Security Coordinator
- C. Krause, Senior Regulatory Compliance Engineer
- R. Ladd, Fire Protection Engineer
- B. Dungan, Operations Manager
- K. Locke, Regulatory Compliance
- M. Ray, Emergency Planning Manager
- T. Petrowsky, Design Engineer Manager
- C. Sizemore, Training Manager
- D. Schoon, Production Planning Manager
- M. Schug, Assistant Operations Manager
- P. Smith, Operations Training Supervisor
- J. Strharsky, Planning and Scheduling Manager
- P. Russell, Site Assessment Manager
- S. Thomas, Radiation Protection Manager
Nuclear Regulatory Commission
- H. Chernoff, Point Beach Project Manager, NRR
- P. Louden, Chief, Reactor Projects, Branch 7
Attachment
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
- 05000301/2004002-01 NCV Containment Upper Hatch Interlock (Section 1R23)
- 05000266/2004002-02; FIN Steam Generator Narrow Range Level Setpoints
- 05000301/2004002-02 Revised in Safety-Related Procedures But Not In Emergency Plan General Emergency EAL 3.1.1.4 (Section 4OA2)
- 05000266/2004002-03; NCV Sprinkler Head Locations Not in Accordance with
- 05000301/2004002-03 Fire Code (Section 4OA5)
Closed
- 05000266/2003009-06 URI Nonsafety-Related Worm and Worm Gears Used in Safety-Related Motor Operated Valve Actuators (Section 1R15)
- 05000301/2004002-01 NCV Containment Upper Hatch Interlock (Section 1R23)
- 05000266/2004002-02; FIN Steam Generator Narrow Range Level Setpoints
- 05000301/2004002-02 Revised in Safety-Related Procedures But Not In Emergency Plan General Emergency EAL 3.1.1.4 (Section 4OA2)
- 05000266/2004002-03; NCV Sprinkler Head Locations Not in Accordance with
- 05000301/2004002-03 Fire Code (Section 4OA5)
- 05000266/2003009-03; URI Sprinkler Head Locations Not in Accordance with
- 05000301/2003009-03 Fire Code (Section 4OA5)
Discussed
None.
Attachment