IR 05000361/2003003
| ML032090080 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 07/25/2003 |
| From: | Kennedy K Division of Reactor Safety IV |
| To: | Ray H Southern California Edison Co |
| References | |
| IR-03-003 | |
| Download: ML032090080 (33) | |
Text
uly 25, 2003
SUBJECT:
SAN ONOFRE NUCLEAR GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 50-361/03-03; 50-362/03-03
Dear Mr. Ray:
On June 28, 2003, the NRC completed an inspection at your San Onofre Nuclear Generating Station, Units 2 and 3, facility. The enclosed report documents the inspection findings which were discussed on July 2, 2003, with Mr. D. Nunn and other members of your staff.
This inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.
Within these areas, the inspection consisted of selected examination of procedures and representative records, observations of activities, and interviews with personnel.
Based on the results of this inspection, the NRC has determined that one Severity Level IV violation of NRC requirements occurred. In addition, the NRC identified two issues that were evaluated under the risk Significance Determination Process as having very low safety significance (Green). The NRC has also determined that violations are associated with these issues. These violations are being treated as noncited violations (NCVs), consistent with Section VI.A of the Enforcement Policy. These NCVs are described in the subject inspection report. If you contest the violation or significance of these NCVs, 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 copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the San Onofre Nuclear Generating Station, Units 2 and 3, facility.
Since the terrorist attacks on September 11, 2001, NRC has issued five Orders and several threat advisories to licensees of commercial power reactors to strengthen licensee capabilities, improve security force readiness, and enhance controls over access authorization. In addition to applicable baseline inspections, the NRC issued Temporary Instruction 2515/148, "Inspection of Nuclear Reactor Safeguards Interim Compensatory Measures," and its subsequent revision, to audit and inspect licensee implementation of the interim compensatory measures required by order. Phase 1 of TI 2515/148 was completed at all commercial power nuclear power plants
Southern California Edison Co. -2-during Calender Year 2002 and the remaining inspection activities for San Onofre have been completed. The NRC will continue to monitor overall safeguards and security controls at San Onofre.
In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter, its enclosure, and your response, if any, will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Should you have any questions concerning this inspection, we will be pleased to discuss them with you.
Sincerely,
/RA/
Kriss M. Kennedy, Chief Project Branch C Division of Reactor Projects Dockets: 50-361 50-362 Licenses: NPF-10 NPF-15 Enclosure:
NRC Inspection Report 50-361/03-03; 50-362/03-03 w/attachment: Supplemental Information cc w/enclosure:
Chairman, Board of Supervisors County of San Diego 1600 Pacific Highway, Room 335 San Diego, California 92101 Gary L. Nolff Power Projects/Contracts Manager Riverside Public Utilities 2911 Adams Street Riverside, California 92504 Eileen M. Teichert, Esq.
Supervising Deputy City Attorney City of Riverside 3900 Main Street Riverside, California 92522
Southern California Edison Co. -3-Joseph J. Wambold, Vice President Southern California Edison Company San Onofre Nuclear Generating Station P.O. Box 128 San Clemente, California 92674-0128 David Spath, Chief Division of Drinking Water and Environmental Management California Department of Health Services P.O. Box 942732 Sacramento, California 94234-7320 Michael R. Olson San Onofre Liaison San Diego Gas & Electric Company P.O. Box 1831 San Diego, California 92112-4150 Ed Bailey, Radiation Control Program Director Radiologic Health Branch California Department of Health Services P.O. Box 942732 (MS 178)
Sacramento, California 94234-7320 Mayor City of San Clemente 100 Avenida Presidio San Clemente, California 92672 James D. Boyd, Commissioner California Energy Commission 1516 Ninth Street (MS 34)
Sacramento, California 95814 Douglas K. Porter, Esq.
Southern California Edison Company 2244 Walnut Grove Avenue Rosemead, California 91770 Dwight E. Nunn, Vice President Southern California Edison Company San Onofre Nuclear Generating Station P.O. Box 128 San Clemente, California 92674-0128
Southern California Edison Co. -4-D
SUMMARY OF FINDINGS
IR 05000361/2003003, 05000362/2003003, 03/30 - 06/28/2003; San Onofre Nuclear
Generating Station, Units 2 & 3; Integrated Resident and Regional Report; Maintenance Risk Assessments and Emergent Work; changes to Emergency Plan; and Emergency Action Levels.
The report covered a 3-month period of inspection by resident inspectors and regional inspectors. Two Green noncited violations and one Severity Level IV violation were identified.
The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter 0609, Significance Determination Process. Findings for which the Significance Determination Process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,
Revision 3, dated July 2000.
NRC-Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
- Green.
The inspectors identified a noncited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, because the licensee implemented inadequate corrective actions to address several instances where incorrect oil was used in safety-related equipment. The inadequate corrective actions resulted in the introduction of incorrect bearing lubricating oil in Auxiliary Feedwater Pump 2P504 during an oil change.
The inspectors determined that the finding had a credible impact on the mitigating systems cornerstone because it resulted in an unnecessary extension of the unavailability of Auxiliary Feedwater Pump 2P504. The issue was determined to be more than minor because, if left uncorrected, the availability and reliability of a portion of the auxiliary feedwater system could be compromised in that excessive pump bearing temperatures could have been reached. Furthermore, the inadequate corrective actions could increase the likelihood of incorrect oil being introduced in safety-related equipment. The finding was determined to have very low safety significance because Auxiliary Feedwater Pump 2P504 was restored to operable status within its Technical Specification allowed outage time (Section 1R13).
- Green.
The inspectors identified a noncited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, because the licensee failed to implement adequate corrective actions following the identification of a leaking check valve in the Unit 3 low pressure safety injection system in May 2001, which resulted in the unnecessary pressurization of the Unit 3 low pressure safety injection header and challenged its associated relief valve.
The inspectors determined that the issue had a credible impact on the mitigating systems cornerstone because it resulted in the unnecessary pressurization of the
Unit 3 low pressure safety injection header and the cycling of its associated relief valve. The issue was determined to be more than minor because, if left uncorrected, it would become a more significant safety concern in that the licensee would continue to unknowingly pressurize the low pressure safety injection header and challenge its associated relief valve. As a result, the reliability of the relief valve and hence the low pressure safety injection header could be compromised. The finding was determined to have very low safety significance because the relief valve maintained the low pressure safety injection header pressure below the American Society of Mechanical Engineers code pressure limit and the safety function of the low pressure safety injection header was maintained (Section 1R13).
Cornerstone: Emergency Preparedness
- Severity Level IV. Between March 3 and April 25, 2003, the licensee implemented a change to Emergency Action Level C3 which constituted a decrease in effectiveness of the emergency plan because two conditions which would previously have resulted in site area emergency classification would not be classified by the revised emergency action level. Implementation without prior NRC approval of changes to the emergency plan which constitute reduction in the effectiveness of the plan was a noncited violation of 10 CFR 50.54(q).
The finding was evaluated using NUREG-1600, General Statement of Policy and Procedure for NRC Enforcement Actions,Section IV, because licensee reductions in the effectiveness of its emergency plan impact the regulatory process. The finding had greater than minor significance because deletion of conditions indicative of a site area emergency has the potential to impact safety.
The finding was determined to be a noncited Severity Level IV violation because the emergency action level change constituted a failure to implement an emergency planning standard and did not constitute a failure to meet an emergency planning standard as defined by 10 CFR 50.47(b). This finding has been entered into the licensees corrective action program as Action Request 030400514 (Section 1EP4).
Licensee-Identified Violations
None
REPORT DETAILS
Summary of Plant Status
Unit 2 began the inspection period at approximately 100 percent power. On June 21, 2003, a reactor shutdown to Mode 4 was initiated to replace a faulty reed switch position transmitter on Control Element Assembly (CEA) 33. The reed switch position transmitter was successfully replaced and a reactor startup was initiated on June 23, 2003. Unit 2 reached approximately 100 percent power on June 24, 2003, and remained there throughout the rest of the inspection period.
Unit 3 was maintained at approximately 100 percent power throughout the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01 Adverse Weather Protection
a. Inspection Scope
The inspectors reviewed the design features and procedures for protecting Units 2 and 3 mitigating systems from the adverse effects of high winds and flooding.
The inspection consisted of reviewing Procedure S023-13-8, Severe Weather, Revision 3. The inspectors also interviewed licensee personnel and directly observed systems and plant conditions. In addition, the inspectors walked down areas around Units 2 and 3 to determine the potential hazard associated with wind-generated missiles.
The inspectors also reviewed the following two components to ensure that their safety functions were adequately protected against high winds and flooding:
- Condensate Storage Tanks
- Auxiliary Feedwater Pumps
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment
a. Inspection Scope
Partial System Walkdowns. The inspectors performed two partial walkdowns during this inspection period. On April 7, 2003, the inspectors walked down the Unit 3 High Pressure Safety Injection (HPSI) system Train A and swing pump alignments while preplanned routine maintenance activities were being performed on HPSI Train B Pump 3P019. On June 24, 2003, the inspectors walked down the Unit 3 motor-driven auxiliary feedwater (AFW) pump trains while preplanned routine maintenance activities were being performed on Unit 3 Turbine-Driven AFW Pump 3MP140. These walkdowns were performed to evaluate the operability of the selected trains or systems when the redundant train or system was inoperable or out of service. The inspectors checked for correct valve and power alignments by comparing positions of valves, switches, and electrical power breakers to the procedures listed below as well as applicable chapters of the Updated Final Safety Analysis Report:
- Operating Instruction SO23-3-2.7, Safety Injection System Operation, Revision 19
- Piping and Instrumentation Diagram 40112ASO3, Safety Injection System No. 1204, Revision 35
- Operating Instruction SO23-2-4, Auxiliary Feedwater System Operation, Revision 19
- Piping and Instrumentation Diagram 40160ASO3, Unit 3 Auxiliary Feedwater System, Revision 27
- Piping and Instrumentation Diagram 40150DSO3, Condensate Pump System (Tanks), Revision 26 Complete System Walkdown. The inspectors conducted a detailed review of the alignment and condition of the Unit 2 AFW system. The inspectors used the licensee procedures and other documents listed below to verify proper system alignment:
- Operating Instruction SO23-2-4, Auxiliary Feedwater System Operation, Revision 19
- Piping and Instrumentation Diagram 40160A, Unit 2 Auxiliary Feedwater System, Revision 31
- Piping and Instrumentation Diagram 40150D, Condensate Pump System (Tanks), Revision 35
- Piping and Instrumentation Diagram 40160B, Unit 2 Auxiliary Feedwater Steam Supply System, Revision 17 The inspectors also verified electrical power requirements, labeling, hangers and support installation, and associated support systems status. Operating pumps were examined to ensure that the vibration was not excessive, pump leakoff was not excessive, bearings were not hot to the touch, and the pumps were properly ventilated.
The walkdown also included evaluation of system piping and supports against the following considerations:
- Piping and pipe supports did not show evidence of water hammer
- Snubbers did not appear to be leaking hydraulic fluid
- Component foundations were not degraded
b. Findings
No findings of significance were identified.
1R05 Fire Protection
a. Inspection Scope
The inspectors performed routine fire inspection tours, and reviewed relevant records, for the following six plant areas important to reactor safety:
- AFW pump room (Unit 2)
- AFW pump room (Unit 3)
- Train A primary switchgear room (Unit 2)
- Train B primary switchgear room (Unit 2)
- Secondary switchgear room (Unit 3)
- Technical Support Center The inspectors observed the material condition of plant fire protection equipment, the control of transient combustibles, and the operational status of barriers. The inspectors compared in-plant observations with the commitments in portions of the Updated Fire Hazards Analysis Report.
b. Findings
No findings of significance were identified.
1R07 Biennial Heat Sink Performance
.1 Performance of Testing, Maintenance, and Inspection Activities
a. Inspection Scope
The inspectors reviewed the licensee's test and cleaning methodology for the shutdown cooling heat exchanger, the control room emergency air cleanup system heat exchangers, emergency core cooling system pump room coolers, and the engineered safety features switchgear room coolers. In addition, the inspectors reviewed test data for the heat exchangers and design and vendor-supplied information to ensure that the heat exchangers were performing within design bases. The inspectors also reviewed the heat exchanger inspection and test results. The inspectors verified proper extrapolation of test conditions to design conditions, appropriate use of test instrumentation, and appropriate accounting for instrument inaccuracies. Additionally, the inspectors verified that the licensee appropriately trended these inspection and test results, assessed the causes of the trends, and took necessary actions for any step changes in these trends. The inspectors reviewed the methods and results of heat exchanger inspection and cleaning and verified that the methods used to inspect and clean were consistent with industry standards and that as-found results were appropriately dispositioned such that the final conditions were acceptable.
b. Findings
No findings of significance were identified.
.2 Verification of Conditions and Operations Consistent with Design Bases
a. Inspection Scope
For the selected heat exchangers, the inspectors verified that the licensee-established heat sink and heat exchanger condition, operation, and test criteria were consistent with the design assumptions. Specifically, the inspectors reviewed the applicable calculations to ensure that the thermal performance test acceptance criteria for the heat exchangers were being applied consistently throughout the calculations. The inspectors also verified that the appropriate acceptance values for fouling and tube plugging for the diesel generator jacket water heat exchangers remained consistent with the values used in the design-basis calculations. In addition, the inspectors verified that the parameters measured during the thermal performance tests for the diesel generator jacket water heat exchangers were consistent with those assumed in the design bases.
b. Findings
No findings of significance were identified.
.3 Identification and Resolution of Problems
a. Inspection Scope
The inspectors verified that the licensee had entered significant heat exchanger/heat sink performance problems into the corrective action program.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification
a. Inspection Scope
The inspectors reviewed two licensed operator requalification training activities, including the licensed operators performance and the evaluators critique. The inspectors compared performance in the simulator on April 9 and June 16, 2003, with performance observed in the control room during this inspection period.
The focus of the inspection was on high-risk operator actions, operator activities associated with the emergency plan, and previous lessons-learned items. These items were evaluated to ensure that operator performance was consistent with protection of the reactor core during postulated accidents.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
.1 Potter & Brumfield Motor Driven Relay Replacement
a. Inspection Scope
The inspectors reviewed the licensees plan for replacement of safety-related Potter &
Brumfield motor-driven relays after the licensee discovered that the relays may be susceptible to an age-related failure mechanism in which thermal growth of internal components could cause mechanical binding and ultimate relay failure when combined with age-related degradation of relay springs. The inspectors reviewed the licensees schedule for relay replacement to verify that it was risk informed. The inspectors also reviewed Action Requests (ARs) 020801305 and 961001095, Potter & Brumfield Part 21 Notification dated January 13, 1993, and the licensees risk evaluation associated with the increased failure probability of motor-driven relays. The inspectors also discussed relay forensic testing and replacement schedule with Engineering personnel.
b. Findings
No findings of significance were identified.
.2 Saltwater Cooling Check Valve Performance
a. Inspection Scope
The inspectors verified that the licensee appropriately addressed the declining performance of saltwater cooling system seal water check valves. The licensee had experienced recent test failures of the check valves as a result of mechanical component degradation and piping debris in the service water lines. The inspectors reviewed ARs 020100712, 030400156, and 030201157 and discussed the maintenance plan for inspection, repair, and modification of the seal water check valves and piping with Engineering and Maintenance personnel.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Evaluation
.1 Incorrect Lubricating Oil Used in AFW Pump 2P504
a. Inspection Scope
The inspectors reviewed emergent work associated with elevated temperature on the outboard bearing of AFW Pump 2P504 following oil replacement.
b. Findings
Introduction.
The licensee implemented inadequate corrective actions to address several instances in which incorrect oil was used in safety-related equipment. The inadequate corrective actions resulted in the introduction of incorrect bearing lubricating oil in AFW Pump 2P504 during an oil change. This finding was determined to be a noncited violation with very low safety significance (Green).
Description.
On March 28, 2003, the licensee performed a postmaintenance test on AFW Pump 2P504 following replacement of the pump packing and bearing oil. During the postmaintenance test following the oil change, the pumps outboard and inboard bearing temperatures exceeded their normal values of approximately 180EF and 130EF, respectively. The pump was manually secured when the outboard bearing temperature exceeded 190EF with no sign of stabilizing. The pump vendor's recommended maximum operating temperature was approximately 205EF. The test was performed four additional times using different methods to measure the bearings temperature. All four tests yielded the same result of elevated outboard bearing temperature with no sign of stabilization. The pump was manually secured each time before bearing temperatures exceeded 196EF. The licensee changed the bearing oil before the final test and the bearing temperatures returned to their normal values. The licensee analyzed the oil that was replaced and determined that the incorrect oil was added to the pump during the initial oil change. The introduction of the wrong oil extended the pumps unavailability by 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
The licensee traced the source of the oil used for the oil change to a one-gallon can labeled as containing Mobil SHC 624. The licensee analyzed the oil in the one-gallon can and determined that it was actually Mobil SHC 626, which has a factor of 2 higher viscosity than Mobil SHC 624. The correct oil was added to the pump and a subsequent postmaintenance test revealed that the bearing temperatures returned to their normal values. The pump was returned to operable status after 56 hours6.481481e-4 days <br />0.0156 hours <br />9.259259e-5 weeks <br />2.1308e-5 months <br />, but prior to exceeding its Technical Specification allowed outage time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
The inspectors reviewed an apparent cause evaluation (ACE) that the licensee completed in September 2002, which was documented in AR 010900606. The ACE was initiated to evaluate 11 instances in which contaminated or incorrect lubricants were found in both safety- and nonsafety-related equipment from July 1999 to October 2001 and to determine if there were common causes for these errors. One of the common causes identified in the ACE was that small containers of oil were improperly labeled with an oil type different than that actually in the container. One of the corrective actions the licensee took to address this issue included disposing of all small oil containers more than 2 years old. In addition, the licensee developed a desktop procedure for the lube oil locker that included steps for decanting oil from 55 gallon containers to smaller 1- and 5-gallon containers. The desktop procedure also included steps to ensure that containers were properly labeled. The licensees corrective actions developed in response to the ACE were not adequate to prevent the use of the incorrect oil in AFW Pump 2P504 on March 28, 2003. While the licensee is conducting its cause evaluation, an interim corrective action has been implemented to require a second check to verify that the correct oil has been decanted into a properly labeled container.
Analysis.
The inspectors evaluated the significance of the finding using the Significance Determination Process. The inspectors determined that the finding had a credible impact on the mitigating systems cornerstone because it resulted in an unnecessary extension of the unavailability of AFW Pump 2P504. The issue was determined to be more than minor because, if left uncorrected, the availability and reliability of a portion of the AFW system could be compromised in that excessive pump bearing temperatures could have been reached. Furthermore, the inadequate corrective actions could increase the likelihood of incorrect oil being used in other safety-related equipment. The finding was determined to have very low safety significance (Green) because AFW Pump 2P504 was restored to operable status within its Technical Specification allowed outage time.
Enforcement.
The regulations in 10 CFR Part 50, Appendix B, Criterion XVI, state, in part, that in the case of significant conditions adverse to quality, measures are to be taken to assure that the cause of the condition is determined and corrective actions taken to preclude repetition. Contrary to this criterion, the licensee did not implement adequate corrective actions in September 2002 to preclude the use of the incorrect oil in AFW Pump 2P504 during an oil change on March 28, 2003. This violation of 10 CFR Part 50 is being treated as a noncited violation (NCV 361/2003003-001) consistent with Section VI.A of the Enforcement Policy. This violation was entered into the licensees corrective action program as AR 030301792.
.2 Pressurization of the Unit 3 Low Pressure Safety Injection (LPSI) Header
a. Inspection Scope
The inspectors reviewed emergent work associated with leaking check valves in the Unit 3 LPSI system.
b. Findings
Introduction.
The inspectors determined that the licensee failed to implement adequate corrective actions following the identification of a leaking check valve in the Unit 3 LPSI system in May 2001, which resulted in the unnecessary pressurization of the Unit 3 LPSI header and challenged its associated relief valve. This finding was determined to be a noncited violation with a very low safety significance (Green).
Description.
On April 8, 2003, the licensee implemented a procedure to conduct a surveillance test on check Valve 3MU040 which is the Safety Injection Tank 3T008 outlet valve. In order to perform the test, the licensee ran HPSI Pump 3P019 to apply approximately 1500 psig of water pressure to the downstream side of Valve 3MU040.
The surveillance test required the licensee to monitor Safety Injection Tank 3T008 level and pressure for one hour. During the evolution, a licensee engineer not involved in the operations test was monitoring one of the licensees electronic parameter display systems and noticed that the LPSI header pressure was cycling between approximately 640 and 660 psig. The engineer informed Operations personnel and the surveillance was immediately secured. The pressurization of the LPSI header was determined to be the result of leakage by the seats of the LPSI header to Loop 1A Isolation Valves 3MU072 and 3HV9322, which allowed the LPSI header to fill and pressurize with water from the HPSI system. Valve 3MU072 is a check valve that serves as a reactor coolant system pressure isolation valve with a Technical Specification leak rate limit of 4 gpm.
The actual leak rate of the valve was approximately 30 gallons per day. Valve 3HV9322 is both a containment isolation valve and a safety injection valve with its operability determined solely by its response time to open following a safety injection actuation signal. Check Valve 3MU072 was eventually reseated on April 9, 2003, and the leakage stopped.
During the overpressurization event, Pressure Relief Valve 3PSV9318 on the LPSI header lifted several times over a period of approximately 30 minutes before the engineer noticed the cycling of LPSI header pressure. The relief valve served to maintain the pressure in the LPSI header at approximately 650 psig in the event that the header was overpressurized. The relief valves setpoint is 615 psig, which is also the rating of the LPSI header pipe.Section III of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code allows for the operating pressure of Code Class II piping to exceed design pressure by 10 percent during operation of relief valves. The maximum pressure that was reached during the evolution was 666 psig, which is below the ASME code maximum of 676.5 psig.
The inspectors reviewed AR 010501502, which documented a similar event that occurred in May 2001. At that time, the licensee was trying to seat Check Valve 3MU072 and inadvertently pressurized the LPSI header to the point where Relief Valve 3PSV9318 was cycling to maintain the LPSI header pressure at approximately 650 psig. The licensee determined that Check Valve 3MU072 was degraded (but operable) and decided to schedule it for maintenance during the Unit 3 Cycle 12 refueling outage in January 2003. However, the valve was not replaced during the outage and no other corrective actions were taken to monitor LPSI header pressure during evolutions in which known overpressurizations could occur.
Pressurization of the LPSI header also occurred on April 6, 2003. During an evolution to backseat Check Valve 3MU018 in the HPSI system, the LPSI header pressurized to 340 psig, at which time the licensee recognized the condition and stopped the evolution.
The inadequate corrective actions implemented following the May 2001 and April 6, 2003, evolutions resulted in the pressurization of the LPSI header a third time to the point where its associated relief valve was challenged and cycled several times.
Analysis.
The inspectors evaluated the significance of the finding using the Significance Determination Process. The inspectors determined that the issue had a credible impact on the mitigating systems cornerstone because it resulted in the unnecessary pressurization of the Unit 3 LPSI header and the cycling of its associated relief valve.
The issue was determined to be more than minor because, if left uncorrected, it would become a more significant safety concern in that the licensee would continue to unknowingly pressurize the LPSI header and challenge its associated relief valve. As a result, the reliability of the relief valve and hence the LPSI header could be compromised. The finding was determined to have very low safety significance because the relief valve maintained the LPSI header pressure below the ASME code pressure limit and the safety function of the LPSI header was maintained.
Enforcement.
The regulations in 10 CFR Part 50, Appendix B, Criterion XVI, state, in part, that, in the case of significant conditions adverse to quality, measures are to be taken to assure that the cause of the condition is determined and corrective actions taken to preclude repetition. Contrary to this criterion, the licensee failed to implement adequate corrective actions in May 2001 to preclude the pressurization of the Unit 3 LPSI header and subsequent cycling of its associated relief valve on April 8, 2003. This violation of 10 CFR Part 50 was determined to be a noncited violation (NCV 05000362/2003003-002) consistent with Section VI.A of the Enforcement Policy.
This violation was entered into the licensees corrective action program as AR 030400450.
.3 Quarterly Review of Maintenance Risk Assessments and Emergent Work
a. Inspection Scope
The inspectors verified the accuracy and completeness of risk assessment documents and that the licensees maintenance risk assessment program was being appropriately implemented. The inspectors also ensured that plant personnel were aware of the licensee established risk category for maintenance activities, according to the risk assessment results and licensee program procedures.
The inspectors also reviewed selected emergent work items to ensure that overall plant risk was being properly managed and that appropriate corrective actions were being properly implemented.
The inspectors reviewed the effectiveness of risk assessment and risk management for the following three activities:
- Unit 3 increase in quench tank in-leakage (AR 030201804)
b. Findings
No findings of significance were identified.
1R14 Personnel Performance During Nonroutine Evolutions
a. Inspection Scope
The inspectors observed operator response to nonroutine events during the inspection period. In addition to direct observation of operator performance, the inspectors reviewed procedural requirements, operator logs, and plant computer data to verify that the response was in accordance with procedures and consistent with training. The following operator response was observed:
- Operator response to an unexpected loss of a Unit 3 second point feedwater heater on May 14, 2003. The inspectors also reviewed AR 030500745.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed selected operability evaluations to evaluate technical adequacy and to verify that equipment operability was justified. The inspectors considered the impact of compensatory measures for each condition being evaluated and referenced the Updated Final Safety Analysis Report and Technical Specifications. The inspectors also discussed the evaluations with licensee personnel.
The inspectors reviewed six operability evaluations and cause assessments documented in the following ARs:
- ARs 030301589, 030301719, 030301760, and 030301792: Unit 2 Train B motor-driven AFW pump water in bearing oil and use of wrong oil in bearing
- AR 030400450: Unit 3 safety injection system operability during header isolation check valve leakage
- AR 030201912: Unit 3 Emergency Diesel Generator 3G002 air start receiver leak
- AR 030600950: Unit 2 Train A AFW system leaking valves in discharge piping allowing backleakage from main feedwater
- AR 030101173: Unit 2 pressurizer safety valve accelerometer operability following discovery of inoperable accelerometers in Unit 3
b. Findings
No findings of significance were identified.
1R16 Operator Workarounds
a. Inspection Scope
Cumulative Effects. The inspectors reviewed seven operator workaround items to evaluate their cumulative effects on the reliability, availability, and potential for misoperation of a system, and on the ability of operators to respond in a correct and timely manner to plant transients and accidents. The inspection included a review of the licensees criteria and processes used for identifying and tracking deficiencies as operator workarounds. The review also focused on the length of time the identified workarounds had been in existence and the efforts initiated to resolve them.
Individual Effects. The inspectors reviewed the following operator workaround to determine if the functional capability of the system or human reliability in responding to an initiating event was effected by the workaround. The inspectors evaluated the effect that the operator workaround had on the operators ability to implement abnormal or emergency operating procedures.
- Manual bypass of one channel of the core protection calculator and the CEA calculator should CEA 33 be required to restore axial shape index with a degraded reed switch position transformer
b. Findings
No findings of significance were identified.
1R17 Permanent Plant Modifications
a. Inspection Scope
On June 19, 2003, the inspectors observed a modification to the Units 2 and 3 main turbines that installed an additional DC-powered main lube oil pump in the main lube oil coastdown system. The purpose of the modification was to increase system redundancy. The inspectors discussed the modification with cognizant Engineering and Maintenance personnel.
b. Findings
No findings of significance were identified.
1R19 Postmaintenance Testing
a. Inspection Scope
The inspectors observed and/or reviewed postmaintenance testing for the following eight activities to verify that the test procedures and activities adequately demonstrated system operability:
- Unit 2 containment sump to Train A Emergency Core Cooling Suction Header Valve 2HV9303 linestarter postmaintenance test inspection per Procedure SO123-I-9.13, 480 VAC Linestarter Inspection, Coil, and Power Contact Replacement, Revision 3, performed on April 15, 2003
- Unit 2 Refueling Water Storage Tank Train A Outlet Valve 2HV9300 linestarter postmaintenance test inspection per Procedure SO123-I-9.13, 480 VAC Linestarter Inspection, Coil, and Power Contact Replacement, Revision 3, performed on April 15, 2003
- Unit 2 shutdown cooling heat exchanger to Train A Containment Spray Header Valve 2HV9367 linestarter postmaintenance test inspection per Procedure SO123-I-9.13, 480 VAC Linestarter Inspection, Coil, and Power Contact Replacement, Revision 3, performed on April 15, 2003
- Unit 2 component cooling water return from Containment Cooler 2ME400 Valve 2HV6369 linestarter postmaintenance test inspection per Procedure SO123-I-9.13, 480 VAC Linestarter Inspection, Coil, and Power Contact Replacement, Revision 3, performed on April 29, 2003
- Unit 2 component cooling water supply to Containment Cooler 2ME402 Valve 2HV6372 linestarter postmaintenance test inspection per Procedure SO123-I-9.13, 480 VAC Linestarter Inspection, Coil, and Power Contact Replacement, Revision 3, performed on April 30, 2003
- Unit 2 High Pressure Safety Injection Loop A Isolation Valve 2HV9324 linestarter postmaintenance test inspection per Procedure SO123-I-9.13, 480 VAC Linestarter Inspection, Coil, and Power Contact Replacement, Revision 3, performed on May 12, 2003
- Unit 2 AFW discharge to Steam Generator Train A Valve 2HV4713 linestarter postmaintenance test inspection per Procedure SO123-I-9.13, 480 VAC Linestarter Inspection, Coil, and Power Contact Replacement, Revision 3, performed on June 10, 2003
- Unit 2 Turbine-Driven AFW Pump P140 postmaintenance test per Procedure SO23-II-11.172, Auxiliary Feedwater Pump (Terry) Turbine Governor Calibration, Revision 1, performed on May 21, 2003. The inspectors also reviewed AR 030501202, Maintenance Order MO 02011761000, and Design Basis Document DBD-SO23-780, Auxiliary Feedwater System, Revision 6, as part of this inspection.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors observed and/or reviewed performance and documentation for the following four surveillance tests to verify that the structures, systems, and components were capable of performing their intended safety functions and to assess their operational readiness:
- Unit 3 Train B Engineered Safety Feature (ESF) Subgroup Relay Test per Procedure SO23-3-3.43.10, ESF Subgroup Relay K-110B Semiannual Test, Revision 8, performed on April 7, 2003
- Unit 3 HPSI Pump 3P019 surveillance test per Procedure SO23-3-3.60.1, High Pressure Safety Injection Pump and Valve Testing, Revision 3, performed on April 7, 2003
- Unit 3 Component Cooling Water Pump 3P026 surveillance test per Procedure SO23-3-3.60.3, Component Cooling Water and Seismic Makeup Pump Test, Revision 3, performed on April 10, 2003
- Unit 2 CEA position indication verification per Surveillance Procedure SO23-3-3.25, Attachment 6, CEA Position Verification, Revision 22, performed on April 28, 2003
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications
a. Inspection Scope
The inspectors reviewed the following temporary plant modification to verify that the safety functions of safety systems were not affected:
- Temporary Facility Modification per AR 020602025-1, CEDM Fan S21501ME404A Isolation and Removal from Service
b. Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness (EP)
1EP4 Emergency Action Level and Emergency Plan Changes
a. Inspection Scope
The inspector performed an in-office review of emergency plan implementing Procedure SO123-VIII-1, Recognition and Classification of Emergencies, Revision 18.
Revision 18 was compared with its previous revision; NUREG-0654, Revision 1, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Appendix 1; and 10 CFR 50.54(q),to determine if the revision decreased the effectiveness of the emergency plan.
b. Findings
Introduction.
The inspector determined that the licensee implemented a change to Emergency Action Level C3, Core Degradation or Overheating, which constituted a decrease in effectiveness of the emergency plan. The licensee changed Emergency Action Level C3 so that two conditions which previously resulted in a site area emergency classification no longer resulted in an emergency classification. This finding was determined to be a noncited, Severity Level IV violation.
Description.
The licensee implemented changes to emergency plan implementing Procedure SO123-VIII-1, Recognition and Classification of Emergencies, on March 3, 2003. As part of this revision the licensee revised indicators for Emergency Action Level C3, Core Degradation or Overheating, which identified a degraded reactor core condition with possible loss of coolable geometry. The previous emergency action level contained three independent indicators, any one of which resulted in a site area emergency classification:
- (1) inadequate core cooling indicated by safety function status concurrent with measured reactor coolant activity greater than or equal to 300 µCi/g dose equivalent I131,
- (2) high range containment accident radiation monitor indication above designated values, or
- (3) measured radiation exposure rates exterior to containment above designated values. The revised emergency action level resulted in classification only when inadequate core cooling was indicated by safety function status along with any one of the following concurrent conditions:
- (1) reactor coolant activity greater than or equal to 300 µCi/g dose equivalent I131,
- (2) high range containment accident radiation monitor indications above designated values, or
- (3) measured radiation exposure rates exterior to containment above designated values. The revised emergency action level required both indication of inadequate core cooling and one other indicator, whereas the previous emergency action level did not require these indicators be concurrent. The inspector determined that neither the high range containment accident radiation monitor nor measured exposure rates exterior to containment resulted in any emergency classification according to the revised emergency action level.
Analysis.
Implementation of an emergency action level change which decreased the effectiveness of the emergency plan was a performance deficiency. The finding was associated with a violation of NRC requirements. The finding had a credible impact on the Emergency Preparedness cornerstone because it represented a decrease in effectiveness of the licensees emergency plan associated with a risk-significant activity (classification). The finding was considered to be more than minor because:
- (1) deletion of conditions indicative of a site area emergency has the potential to impact safety, and
- (2) implementation of changes which decrease the effectiveness of the emergency plan without prior NRC approval has an impact on regulatory processes. In accordance with Manual Chapter 0609, Appendix B, §2.2(e) and §4.4, the inspector evaluated the significance of the finding using NUREG-1600, General Statement of Policy and Procedure for NRC Enforcement Actions (Enforcement Policy),Section IV, Significance of Violations. The finding was determined to be a Severity Level IV violation according to NUREG-1600 Supplement VIII, Emergency Preparedness, because the emergency action level change constituted a failure to implement an emergency planning standard, the affected emergency action level was not used during an actual emergency, and the change did not constitute a failure to meet an emergency planning standard as defined by 10 CFR 50.47(b).
Enforcement.
Licensee implementation without prior NRC approval of an emergency action level change which constitutes a decrease in effectiveness of the emergency plan is a violation of 10 CFR 50.54q, which states, in part, The nuclear power reactor licensee may make changes to these plans without Commission approval only if the changes do not decrease the effectiveness of the plans and the plans, as changed, continue to meet the standards of 10 CFR 50.47(b) and the requirements of Appendix E to this part. This violation of 10 CFR Part 50 is being treated as a noncited Severity Level IV violation (NCV 05000361; 362/2003003-003) consistent with Section VI.A of the Enforcement Policy. This issue has been entered into the licensees corrective action program as AR 030400514.
1EP6 Drill Evaluation
a. Inspection Scope
The inspectors observed the following emergency preparedness drills to evaluate the drill conduct and the adequacy of the licensees performance critique. The inspectors observed three site-wide drills from the simulator, Technical Support Center, Operations Support Center, and the Emergency Operating Facility on the following dates:
- May 29, 2003
- June 4, 2003 (simulator and EOF only)
- June 11, 2003
b. Findings
No findings of significance were identified.
Cornerstone: Physical Protection (PP)
3PP4 Security Plan Changes (71130.4)
a. Inspection Scope
The inspector conducted an inoffice review of the following Physical Security Plan, Contingency Plan, and Training and Qualification Plan changes to determine if they decreased the effectiveness of the respective plan and to determine if requirements of 10 CFR 50.54
- (p) were met:
- Physical Security Plan, Revision 68, dated October 30, 2000, that documented corrections to the table that described protected area barriers
- Physical Security Plan, Revision 69, dated November 22, 2000, documented changes that resulted from a revision to the target analysis, which revised the location and designation for armed responders
- Physical Security Plan, Revision 70, dated December 4, 2000, that documented changes resulting from upgrades to the intrusion detection system and the security boundary
- Physical Security Plan, Revision 71, dated February 23, 2001, that documented editorial changes to correct terminology following completion of the physical changes at the facility
- Physical Security Plan, Revision 72, dated May 3, 2001, which documented changes that occurred when the protected area was moved from around Unit 1.
This change also introduced the nonsafeguards information contained in the Unit 1 Consolidated Defueled Physical Protection Plan.
- Physical Security Plan, Revision 73, dated October 1, 2001, which documented changes that occurred by deletion of the guard towers
- Physical Security Plan, Revision 74, dated February 19, 2002, that documented editorial changes and clarifications and modified the requirements to verify military employment history
- Physical Security Plan, Revision 75, dated July 31, 2002, that documented changes to response post designations, assigned weapons, and minor administrative changes
- Safeguards Contingency Plan, Revision 25, dated November 22, 2000, that documented the change in munitions used by security officers
- Safeguards Contingency Plan, Revision 26, dated January 11, 2001, that eliminated some procedure references as a result of a procedure upgrade project and described editorial corrections
- Safeguards Contingency Plan, Revision 27, dated May 3, 2001, that documented changes which occurred as a result of removing the protected area from around Unit 1. This change also introduced the nonsafeguards information contained in the Unit 1 Consolidated Defueled Physical Protection Plan.
- Safeguards Contingency Plan, Revision 28, dated October 1, 2001, which documented changes that occurred by deletion of the guard towers
- Safeguards Contingency Plan, Revision 29, dated July 31, 2002, that documented editorial changes and reflected a change in the type of handgun being utilized by security officers
- Training and Qualification Plan, Revision 23, dated November 22, 2000, that documented the change in munitions used by security officers
- Training and Qualification Plan, Revision 24, dated May 3, 2001, that documented changes which occurred as a result of removing the protected area from around Unit 1. This change also introduced the nonsafeguards information contained in the Unit 1 Consolidated Defueled Physical Protection Plan.
- Training and Qualification Plan, Revision 25, dated October 1, 2001, which documented changes that occurred by deletion of the guard towers
- Unit 1 Consolidated Defueled Physical Protection Plan, Revision 0, dated May 1, 2001, that established the security requirements for the Unit 1 facility
- Unit 1 Consolidated Defueled Physical Protection Plan, Revision 1, dated January 3, 2002, that documented changes related to establishing a vehicle controlled area
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES (OA)
4OA1 Performance Indicator Verification
a. Inspection Scope
The inspectors verified the accuracy of data reported by the licensee for the following three performance indicators to ensure that the performance indicator color was correct for both Units 2 and 3:
Reactor Safety Cornerstone
- IE3 Unplanned Power Changes per 7000 Critical Hours
- MS1 Emergency AC Power System Unavailability
- MS2 High Pressure Injection System Unavailability The inspectors reviewed the performance indicator data for the last three quarters of 2002 and the first quarter of 2003. The inspectors reviewed NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 2, and licensee operating logs.
The inspectors discussed the status of the performance indicators and compilation of data with engineering personnel.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
.1 Annual Sample Review
a. Inspection Scope
The inspectors selected AR 030301263 for detailed review. The AR documented the formation of a pinhole leak at the discharge elbow of Saltwater Cooling Pump 2P307.
The AR was reviewed to ensure that the full extent of the issues were identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. The inspectors evaluated the AR against the requirements of the licensees corrective action procedure as delineated in Procedure SO123-XV-50, Corrective Action Process, Revision 4.
b. Findings
No finding of significance were identified.
.2 Quarterly Review of Corrective Action Documents
a. Inspection Scope
The inspectors reviewed a selection of ARs written during this period to determine if the licensee was entering conditions adverse to quality into the corrective action program at an appropriate threshold, to determine if the condition reports were appropriately categorized and dispositioned in accordance with the licensees procedures, and, in the case of conditions significantly adverse to quality, to determine if the licensees root cause determination and extent of condition evaluation were accurate and of sufficient depth to prevent recurrence of the condition.
b. Findings
No findings of significance were identified.
.3 Cross-References to Problem Identification and Resolution Findings Documented
Elsewhere Section 1R13 describes a finding where incorrect lubricating oil was used in an AFW pump. Prior to this incident, corrective actions had been implemented to address similar instances of the wrong oil being used in safety-related equipment. The corrective actions that were implemented were inadequate to prevent recurrence of the introduction of the wrong oil into safety-related equipment.
Section 1R13 describes a finding in which the Unit 3 LPSI system header was inadvertently pressurized and its associated relief valve challenged. The same event occurred 2 years earlier and no corrective actions were implemented to prevent recurrence.
4OA3 Event Followup
.1 (Closed) Licensee Event Report (LER) 362/2002-004-00: emergency room cooler for
component cooling water pump considered inoperable The LER was reviewed by the inspectors and no findings of significance were identified.
4OA5 Other
(Discussed) Unresolved Item 361; 362/2002013-001: protection of both alarm stations This item remains open pending completion of corrective actions by the licensee. On May 21, 2003, the Office of Nuclear Security and Incident Response issued a letter to the licensee that advised them that their protective strategy implemented to address protection of both alarm stations did not meet the intent of the Order. Consequently, the licensee had 30 days to describe its timetable and actions to come into compliance with the Order. In addition, the licensee had to maintain compensatory measures until the deficiency was corrected.
4OA6 Meetings, including Exit
Exit Meeting Summary
The emergency preparedness inspector presented inspection results to Mr. M. Hug, Supervisor, Site Emergency Planning, and other members of licensee management by telephone on April 24, 2003.
The engineering inspector presented inspection results to Mr. D. Nunn, Vice President Engineering and Technical Services, and other members of licensee management and staff on May 16, 2003.
The security inspector conducted a telephonic exit with Mr. M. McBrearty, Licensing Engineer, on May 27, 2003.
On July 2, 2003, the resident inspectors presented the inspection results to Mr. J. Wambold, Vice President, Nuclear Generation, and others.
During all meetings, licensee management acknowledged the inspection findings.
Proprietary information reviewed by inspectors during this inspection was left with the licensee at the end of the inspection.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel
- R. Allen, Supervisor, Reliability Engineering
- C. Anderson, Manager, Site Emergency Preparedness
- D. Axline, Licensing Engineer
- D. Brieg, Manager, Maintenance Engineering
- G. Cook, Supervisor, Compliance
- M. Cooper, Manager, Plant Operations
- J. Fee, Assistant Station Manager
- K. Flynn, Supervisor, System Engineering
- M. Goettel, Manager, Business Planning and Financial Services
- M. Hug, Supervisor, Site Emergency Planning
- M. Love, Manager, Maintenance
- J. Madigan, Manager, Health Physics
- C. McAndrews, Manager, Nuclear Oversight and Assessment
- D. Nunn, Vice President, Engineering and Technical Services
- N. Quigley, Manager, Mechanical/Nuclear Maintenance Engineering
- A. Scherer, Manager, Nuclear Regulatory Affairs
- P. Schofield, Supervisor, Mechanical Engineering
- M. Short, Manager, Systems Engineering
- T. Vogt, Manager, Operations
- R. Waldo, Station Manager
- J. Wambold, Vice President, Nuclear Generation
- T. Yackle, Manager, Design Engineering
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
None
Opened and Closed
- 05000361/2003003-001 NCV Incorrect lubricating oil used in AFW Pump 2P504 (Section 1R13)
- 05000362/2003003-002 NCV Pressurization of the Unit 3 LPSI header (Section 1R13)
- 05000361;362/2003003-003 NCV Change to Emergency Action Level C3 resulted in a decrease in effectiveness of the emergency plan in violation of CFR 50.54(q) (Section 1EP4)
-A1- Attachment
Closed
2/2002-004-00 LER Emergency room cooler for component cooling water pump considered inoperable (Section 4OA3)
Discussed
- 05000361; 362/2003013-001 URI Protection of both alarm stations (Section 4OA5)