IR 05000369/1998003
| ML20248J744 | |
| Person / Time | |
|---|---|
| Site: | Mcguire, McGuire  |
| Issue date: | 05/18/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20248J741 | List: |
| References | |
| 50-369-98-03, 50-369-98-3, 50-370-98-03, 50-370-98-3, NUDOCS 9806090287 | |
| Download: ML20248J744 (23) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-369. 50-370 License Nos: NPF-9, NPF-17 Report No: 50-369/98-03. 50-370/98-03 Licensee: Duke Energy Corporation Facility: McGuire Nuclear Station Units 1 and 2 Location: 12700 Hagers Ferry Road Huntersville NC 28078 Dates: March 8, 1998 - April 18, 1998
Inspectors: S. Shaeffer. Senior Resident Inspector M. Sykes, Resident Inspector M. Franovich. Resident Inspector S. Rudisail. Reactor Inspector (Section E8.1)
Approved by: C. Ogle, Chief, Projects Branch 1 Division of Reactor Projects l
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EXECUTIVE SUMMARY McGuire Nuclear Station. Units 1 and 2 NRC Inspection Report 50-369/98-03, 50-370/98-03 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covered a six-week period of resident inspection and an evaluation of a previously identified
' discrepancies in the Updated Final Safety Analysis Report (UFSAR)..
Doerations
- The licensee reports and retractions of events were appropriat (Section 01.2)
- Operations * immediate response to an electro-hydraulic control fluid leak on the Unit 1 main turbine emergericy trip header was good. Prompt actions prevented a potential fire and possible transient on the plan Management oversight, dialogue, and team work among operations, maintenance, and engineering to design and install a tem)orary modification to reduce the electro-hydraulic control leac rate was excellent. The supporting modification documentation and 10 CFR 50.59 screening were satisfactory. (Section 02.1)
- Operator identification and respor;e to a steam leak on Unit I reheat stop valve ISC36 was good. Maintenance activities associated with the temporary repair were adequately performed. The subject )ower reduction and MSR flange repair were conducted in a safe manner. T v ficensee was taking a proactive approach to resolving an identified nagal.1ve secondary equipment trend. (Section 02.2)
- The material condition of roofs on some buildings housing safety-related and important to safety equipment was poor and created conditions that could challenge safety system operability. Numerous rain water leaks continue to challenge plant operations personnel to identify and mitigate the effects of the leaks before plant equipment is adversely affected. Licensee actions were previously established to correct the identified roofing problem. (Section 02.3)
Maintenance
- Licensee management recognized an adverse trend in the performance of secondary support systems, based on a number of recent problems related to the turbine generator and other support systems. A focused review was initiated to address the secondary equipment trend. (Sections 02.2)
- Maintenance and surveillance activities reviewed were completed satisfactorily. (Section M1.1)
- Unit 2 turbine acceptance test coordination. pre-job briefing materials, and test execution were good. Overall, the 10 CFR 50.59 safety evaluation was adequate. Contingency actions could have been developed to be implemented in the event that bypass lines would be isolated beyond a short period of time. (Section M3.1)
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. The licensee's drawing updates following the Unit 1 and Unit 2 steam generator replacements projects were adequate to nrovide detailed and accurate information of as-built plant system Section M3.2)
Enaineerina
. Management oversight, dialogue, and team work among operations, maintenance, and engineering to design and instali a temporary modification to reduce the electro-hydraulic control leac rate was excellent. The supporting modification documentation and 10 CFR 50.59 screening were satisfactory. (Section 02.1)
. The licensee's review and evaluation regarding shared electrical system interactions affecting nuclear service water and control room ventilation systems were adequate to confirm that the plant had not operated in an analyzed candition due to shared system interactions. A Non-Cited Violation was identified for failure to record and monitor equipment inoperability for the affected inoperable equipment. (Section E2.1)
. A Non-Cited Violation was identified for failure to revise the Technical Specifications to accurately reflect the references and methodology used in developing the core operating limits report. (Section E3.1)
. The licensee's safety evaluation of the removal of the remote operator for 2B centrifugal charging pump discharge isolation valve 2NV232 was adequat (Section E4.1)
. A Non-Cited Violation was identified for inadequate procedures that resulted in a non-compliance with Technical Specifications for inoperable engineered safety feature instrumentation for refueling water storage tank level and the containment pressure control system. (Section E8.3)
. A Non-Cited Violation was issued for the licensee's failure to update the McGuire Updated Final Safety Analysis Report (Section E8.4)
Plant Suonort
. Locked high radiation doors were properly controlled, high radiation and contamination areas were properly posted. ar.d radiological area survey maps were updated to accurately reflect radiological conditions in the respective areas. (Section R1.1)
. Readiness of the McGuire Emergency Offsite Facility to support a postulated accident was good. The performance of a series of training drills to exercise a new duty rotation for emergency manning was considered a continued example of proactive training in the area of emergency preparedness. Incorporation of the Assistant Emergency Operations Facility Director position was considered proactive in augmenting the emergency response effectivenes (Section P2.1)
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Report Details Summary of Plant Status Unit 1 Unit 1 began the inspection period at approximately 100 percent power. On March 22, 1998, power was reduced to approximately 25 percent to allow the turbine generator to be taken off line to repair a steam leak on 181 Moisture Separator Reheater reheat stop valve 1SC3 Following the completion of the repair, the unit was returned to 100 percent power on March 23, 1998. The unit operated at approximately 100 percent power for the remainder of the inspection perio Unit 2 l Unit 2 began the inspection period escalating to approximately 100 percent power following a planned power reduction to inspect a 6900 volt bus duct damaged during the previous inspection period. The unit operated at approximately 100 percent power for the remainder of the inspection perio Review of Uodated Final Safety Analysis Reoort (UFSAR) Commitments While performing inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that were related to the areas inspecte The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures, and parameter I. Doerations 01 Conduct of Operations 01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-consciou Specific events and noteworthy observations are detailed in the sections which follow. The inspections included reviews of clearance controls in place to support o)eration and/or maintenance of key systems. The inspectors observed tlat the clearances were proper 13 prepared and authorized, and that the tagged components were in the required positions, with the appropriate tags in plac .2 10 CFR 50.72 Notifications Insoection Scoce (71707)
During the inspection period, the licensee made the following notifications to the NRC as required or for information purposes. The inspectors reviewed the events for impact on the operational status of the facility and equipmen _____
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2 Observations and Findinas On March 18. 1998, the licensee notified the NRC of a potential unanalyzed condition concerning previous shared equipment alignments and associated Technical-Specification (TS) logging practices. On April 7.1998, the licensee subsequently retracted this report based on licensee reviews which did not identify any specific situations where an inappropriate system alignment occurred. This issue is discussed in Section E . On April 13. 1998, the licensee notified the NRC regarding a i potential security event involving inappropriate badge acces On l April 17,1998, the licensee subsequently retracted this
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notification based on a review of the specific details of the event concluding that no NRC deportability threshold had been me NRC followup to this event will be further discussed in Inspection Report 50-369.370/98-0 . On April 18. 1998, the licensee reported a failure of several NRC Emergency Notification System (ENS) phones lines located in the Technical Support Center. The licensee made the notification after they were informed by the phone company of potentially inoperable phone lines. The licensee verified that the effected lines were not operating and made the required report to the NR The line problems initiated from an offsite fault and were promptly repaire Conclusions i
The inspectors concluded that the licensee reports and retractions of these events were appropriat Operational Status of Facilities and Equipment 02.1 Unit 1 Main Turbine Hydraulic Fluid Leak Insoection Scooe (71707)
. The inspectors evaluated the licensee's response to a hydraulic fluid leak on the Unit 1 emergency trip header for the main turbine. The temporary modification package and the 10 CFR 50.59 screening were reviewed and the inspectors attended licensee meetings to address the degraded conditio Observations and Findinag On March 23. 1998, the Unit 1 main turbine electro-hydraulic control (EHC) oil system experienced a leak at a connection between the tube fitting and the trip block. This'one-inch line is the emergency trip header line for the throttle and reheat stop valves. The leak rate was approximately 0.4 gallons per hour. To prevent oil dripping onto hot components and potentially igniting, a catch bucket was immediately i
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) lace underneath the leak. A skid mounted pump was used to refill the EHC system to prevent the system from reaching the low pressure auto trip setpoint. Operations personnel alsc appropriately considered industry operating experience with EHC fluid problems and turbine control valve A temporary modification (MGTM-0044) using a clam 31ng device was designed, manufactured, and installed to reduce tie leak rate and likelihood of a turbine trip and reactor trip from loss of hydraulic I pressure. A meeting among operations, maintenance, and engineering personnel was conducted to discuss the design and instariation of the device and to lay out contingency plans should the leak rate increase.
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The clamp was installed on March 25. 1998, and the leakage reduced to a I few drops per hour, Conclusions Operations * immediate response to an EHC fluid leak on the Unit 1 main turbine emergency trip header was good. Prompt actions prevented a potential fire and possible transient on the plant. Management oversight dialogue, and team work among operations, maintenance, and engineering to design and install a temporary modification to reduce the EHC leak rate was excellent. The supporting modification documentation and 10 CFR 50.59 screening were satisfactor .2 181 Moister Seoarator Reheater (MSR) Steam Leak Reauirina Unit Downoower Insoection Scone (37551)
The inspectors evaluated the licensee documentation associated with a Unit 1 downpower to repair a steam leak on MSR reheat stop valve ISC3 The inspectors focused on licensee initiatives to resolve an adverse trend concerning secondary plant system problem Observations and Findinos On March 21, 1998, a non-licensed operatur (NLO) identified a steam leak on the 1B1 MSR reheat stop valve inlet flanged connection. While in the process of initial inspection of the leak, the leak continued to deteriorate, prompting repair. Initial on-line efforts to repair the i leak were unsuccessful. Subsequently, it was decided to isolate the component by removing the turbine from service. The inspectors verified that operators performed the power reduction, to approximately 25 percent power. in a controlled manner and in accordance with applicable procedures. The root cause of the failure was determined to be a cut gasket, promulgated by a loss of flange torque preload. The temporary repair involved replacement of the existing flange bolts with seal injection port studs, and a subsequent leak sealant injectio Additional corrective actions included torquing of other Unit 1 MSR flange connections in an attempt to ensure their integrity until the planned. June 1998. refueling outag _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _
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Based on the subject issue and other recent secondary plant problems, licensee management initiated aroblem investigation process report (PIP)
0-M98-0909 to perform a compre1ensive examination of the turbine generator and its associated support systems. A number of secondary plant issues, including a reactor trip due to a failed voltage regulator
. component, have resulted in recent challenges to operators and unit power reductions. The inspectors reviewed the PIP and discussed the review scope with engineering personnel. For each identified problem, the scope of the planned review included: a determination of common failure modes of the recent failures; a review of the adequacy of current maintenance practices: identification of potential improvements to increase reliability: and a review of system design fo- known weaknesses from common industry failure Conclusion The operator identification and res)onse to a steam leak on Unit 1 reheat stop valve ISC36 was good. Maintenance activities associated with the temporary repair were adequately performed. The subject power reduction and MSR flange repair were conducted in a safe manne Based on the review, the inspectors concluded that the licensee was taking a proactive approach to resolving the identified negative secondary equipment tren .3 Rain Leaks Throuah Plant Structures Insoection Scone (71707)
The inspectors toured various areas of the plant to evaluate the material condition of the selected areas. Some of the areas toured included the auxiliary building, service building, turbine building, and the emergency diesel generator (EDG) room Observations and Findinas During a )lant tour on March 8.1998, inspectors observed rain water leaking t1 rough an electrical penetration in the Unit IB EDG room. The rain water was dripping onto safety-related sump Jump control panel 1 The inspectors immediately notified the shift worc manager and the licensee promptly placed a catch basin underneath the leak. The ins)ectors also noticed other leaks during the tour. For each of the leacs observed, the licensee had taken action to prevent water from impacting equipment reliabilit A review of PIPS indicated that leaking structures, which housed safety related equipment and important to safety equipment, had been a repetitive problem at McGuire. Leaking roofs were identified as the major cause of the leaks. The inspectors reviewed the PIPS and verified that a plan to repair the degraded structures had been initiated. The inspectors verified that some of the corrective actions had been completed, and the remaining work was scheduled to be completed over the
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next few years. Operations' management has also heightened NLO attention to check for additional leakage during periods of heavy rai Conclusions The material condition of roofs on some buildings housing safety-related and important to safety equipment was poor and created conditions that could challenge safety system operability. Numerous rain water leaks continue to challenge plant operations personnel to identify and mitigate the effects of the leaks before plant equipment is adversely affected. Licensee actions were previously established to correct the identified roofing proble Miscellaneous Operations Issues 0 (Closed) Licensee Event Report (LER) 50-369/96-06. Revision 0 and Revision 1: Manual Initiated Actuation of Both Unit 1 Motor Driven Auxiliary Feedwater Pum]s Due to Loss of Auxiliary Steam Supply to the Main Feedwater Pump Tur)ine On November 9. 1996, the licensee was returning Units 1 and 2 to service using the auxiliary electric boilers (AEB) with the units in Mode 3. A recirculating pump to one of the AEBs tripped causing a reduction in steam pressure. The recirculating pump tripped due to loss of bearing lubrication. The loss of bearing lubrication was attributed to a constant level oiler adjusting being low, which caused the recirculating pump to trip. This caused the main feedwater pumps on Unit 1 to lose speed reducing feedwater flow to all 4 steam generators. Operators started the unit 1 motor driven auxillary feedwater (AFW) pumps to stabilize steam generators (SG) levels. A four-hour NRC notification was made due to the manual engineered safety feature (ESF) actuatio The licensee was unable to determine the root cause as to why the constant level oiler adjusting device was low. However, the licensee identified several plausible causes, including improper maintenance setup and vibration causing the level controller to drif The inspector reviewed the corrective actions, which included communication to maintenance personnel on proper maintenance and operation of automatic oilers. The inspectors verified that each of the corrective actions were implemented and determined that the licensee's actions were adequate. This LER is close .2 (Closed) LER 50-369/97-05: In-voluntarily Terminated Employee Entered the Protected Are The subject of this LER was reviewed in depth by the NRC as documented in Inspection Report 50-369.3/0/97-13. issued on August 22. 1997. This event was also dispositioned as part of an Escalated Enforcement issued on September 26, 199 The specific corrective actions for this event and other identified security issues will be reviewed during closure of violations 50-369.370/97-13-01 and 02. This LER is closed.
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II. Maintenance M1 Conduct of Maintenance M1.1 General Comments Insoection Scooe (61726 and 62707)
I The inspectors observed portions of the following work activities:
Procedure / Work Order Title PT/2/A/4208/001B 2B Containment Spray Pump Test TT/2/A/7600/168 Unit 1 and Unit 2 Turbine Acceptance Test PT/2/A/4600/001 Unit 1 RCCA Movement Test PT/2/A/4200/002 SSF Diesel Generator Operability Test 96093080 SDSS Battery Cell Replacement 98006852 1A Charging Pump Oil Leak Repair Observations and Findinas The inspectors witnessed selected surveillance tests to verify that approved procedures were available and in use: test equipment was calibrated: test prerequisites were met: system restoration was completed; and acceptance criteria were met. In addition, the inspectors reviewed or witnessed routine maintenance activities to verify. where applicable, that approved procedures were available and in use, prerequisites were met, equipment restoration was completed, and maintenance results were adequat Conclusion The inspectors concluded that the maintenance and surveillance activities observed were completed satisfactoril H3 Maintenance Procedures and Documentation M3.1 Unit 1 and Unit 2 Turbine Acceotance Test (TAT) ! Jnsoection Scooe (61726)
The inspectors observed portions of the Unit 2 TAT performed between March 23 and March 26, 1998. Temporary Test (TT) procedure 2/A/7600/168 Rev. O. Post Steam Generator Replacement Project (SGRP) Thermal Performance Test, the associated 10 CFR 50.59 evaluation, calculation J
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number MCC-1552.08-00-0273, McGuire Unit 1 Turbine Valve Wide Open Test
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Evaluation (also used to support Unit 2 test). The UFSAR, Design Basis l~ Document (DBD), and Technical Specifications (TS) were also reviewe Cognizant engineering personnel were interviewed, and excore detector and thermal power best-estimate (TPBE) plots and reactor operator logs were reviewe Observations and Findinas The purpose of the TAT was to determine actual unit performance using methods described in American Society of Mechanical Engineers (ASME)
PTC6-1996. Performance Test Code 6 on Steam Turbines. The test involved gathering plant data with several days of reactor coolant system (RCS)
operation at a reduced average temperature (Tavg) while maintaining reactor and turbine power at approximately 100 percent. Tavg was reduced approximately 7 F below the normal Tavg value for 100 percent power (ap3roximately 585 F). The rod control system was in manual while tur)ine governor valve position was varied through turbine load adjustment Primary system was borated to induce the RCS cooldow Inspectors observed good operator controls and minimization of control !
room traffic during the tes j MCC-1552.08-00-0273 reevaluated UFSAR analyses that could be im) acted and reanalyzed the large-break Loss of Coolant Accident (LOCA) Jesign Basis Accident (DBA). The large-break LOCA reanalysis showed an increase in the peak clad temperature (PCT) of 24*F with an unrelated 77'F increase for non-conservatism identified actinide decay heat. The new PCT was 2173 F: however, the temperature limit remained with the 10 CFR 50.46 limit of 2200 F. Inspectors questioned the licensee if the reanalysis was performed at 1.02 times the licensed power level to account for instrument uncertainty as required by 10 CFR 50 Appendix The licensee indicated this LBLOCA analysis was performed at 1.02 times 3411 MWt. For non-LOCA DBAs. the reduced Tavg resulted in an increase in the margin to departure from nucleate boilin The inspectors were concerned that inducing a Tavg reduction would cause increased reactor vessel downcomer neutron attenuation and mask actual reactor power readings. A reduced Tavg causes the excore nuclear instrument (NI) detectors to indicted lower power than actual reactor power Such an effect would negatively impact the high flux reactor trip function of the reactor protection system (RPS). To compensate for this effect, the licensee adjusted the NI detectors when a mismatch of approximately 2 percent existed between excore and TPBE. MCC-1552.08-00-0273 addressed this effect: however, the inspectors identified a discrepancy between the 10 CFR 50.59 evaluation and the su) porting calculation recommendation. The calculation recommended tlat NIs be recalibrates for each 2 F reduction in Tavg or else the support calculation conclusions would not be valid. The 10 CFR 50.59 evaluation allowed for a 2 percent mismatch between excore and TPBE powe The licensee indicated that a 2 percent error was assumed in the evaluation of the UFSAR chapter 15 DBAs and the 2 F recommendation was made since the oniginal test was envisioned to take longer with distinct test
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)lateaus where NI readjustment would be conveniently performed at each lold point. The actual test had a Tavg reduction one half the magnitude assumed in the supporting calculation and the duration of the test was reduced. The inspectors considered this response satisfactory. An inspector review of the power alots confirmed that NI readjustments were performed for both Unit i and Jnit 2 TATS when excore and TPBE mismatches were approximately 2 percen Following the review of tha 10 CFR 50.59 evaluation, the inspectors questioned the licensee concerning the isolation of the Unit 1 steam orifice bypass lines (bypass 1SA48 and ISA49 steam admit valves) that-warm the plaing to the Unit 1 TDAFW pump. Several of the questions asked were Jase! on industry TDAFW testing results. Specifically, had the licensee identified a maximum length of time that the bypass lines could be isolated, and what contingency actions, if any, were in place should a maximum isolation time be exceede The inspectors were concerned due to the fact that, isolation time could affect TDAFW Sump operability. If the TDAFW pump actuated during the Unit 1 TAT. t1ere could (1) potentially be excess thermal stress on inlet piping and (2)
potential condensate accumulation (upstream water as-well as downstream water from steam leP.ing through the admit valves). The latter concern could result in a water slug causing the turbine to trip on overspee The inspectors determined that the licensee did not identify a specific length of time for which the bypass lines could be isolated. However, the safety evaluation did indicated that the bypass lines would be isolated for a only short period of time. The licensee indicated that engineering judgement was used, in some instances, to reach conclusions identified in the 10 CFR 50.59 evaluation and to determine procedure requi rements. That licensee stated that based on the fact that the bypass lines would be isolated for only a short time, there was no need to specify a maximum time for which lines could be isolated. The test coordinator indicated that on Unit 1 this was in the range of 4 to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. This steam load was not isolated for the Unit 2 test. The ins)ectors confirmed that the actual test was performed adequately, and wit 11n the guidelines identified in the test procedur Therefore, in this instance, no contingency plars were require Conclusions Unit 2 TAT coordination, pre-job briefing materials, and test execution were goo Overall, the 10 CFR 50.59 safety evaluation was adequat However, the inspectors did note that no contingency actions were identified, that could be im)lemented in the event the bypass lines would be isolated beyond a s1 ort period of tim M3.2 SGRP Proiect Drawina Uodate
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The inspectors reviewed drawings and compared as-built information to confirm proper updates of selected plant drawing .
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9 Observations and Findinas The inspectors reviewed plant drawings for the reactor coolant. the main steam, the auxiliary feedwater, and the steam generator blowdown systems to verify that proper and timely updates had been completed to address modifications made during the Unit I and Unit 2 SGRPs. The inspectors reviewed and compared control room and document control drawing Following the review of selected drawing, the inspectors determined that each plant drawings had been properly update Conclusions The inspectors concluded that the licensee's drawings updates following the Unit 1 and Unit 2 steam generator replacements projects were adequate to provide detailed and accurate information of as-built plant system III. Enaineerina E2 Status of Engineering Facilities and Equipment E2.1 Unit 1 and Unit 2 Shared Electric Motor Control Centers Insoection Scone (37551)
The inspectors evaluated the licensee's March 18. 1998, notification regarding the potential for an unanalyzed condition involving Unit 1 and Unit 2 600 volt (V) motor control center Observations and Findinas The licensee made notification to the NRC of a potential that 3ast electrical alignments may have caused un31anned Unit 1 and/or Jnit 2 o)eration in an unanalyzed condition. T1e potential was identified by tie licensee's Operating Experience Assessment (CEA) organization. The 600V motor control centers 1EMXG. 1EMXH. 2EMXG. and 2EMMH provide essential power to shared Unit 1 and Unit 2 plant equipment. The affected equipment included certain nuclear service water and auxiliary and control room ventilation system components. The Unit 1 electric motor control centers (IEMXG and IEMXH) provide power to the A Train shared components and the Unit 2 motor control centers (2EMXG and 2EMXH)
arovide )ower to the B Train shared components. The Unit 1A EDG and the Jnit 2B EDG typically provide alternate emergency AC power to these essential motor control centers. With the 1A EDG inoperable for maintenance, the A Train shared motor control centers 1EMXG and 1EMXH did not have the necessary alternate emergency AC supply to meet operability requirements. The inoperability of the Jnit 1 motor control centers caused several Unit 1 and Jnit 2 A Train shared components to be rendered inoperabl The same situation holds true for the 2B EDG and the Unit 1 and Unit 2 B Train equipmen ._ _ _ - - _ _____ _ _ -
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The licensee postulated that since this vulnerability had not been clearly communicated to operating staff, the condition may have gone unnoticed resulting in the unplanned inoperability of an ESF train on
. Unit 1 and Unit 2 which may have been coincident with the inoperability of opposite train equipment for planned maintenance. The inspectors noted that the licensee's unclear understanding of the 600V essential power system resulted in the unplanned and unrecognized inoperability of certain shared plant equipment. The inoperable equipment was not recognized and therefore not recorded in accordance with McGuire Nuclear Station. 0)erations Management Procedure (0MP) 5-2. Control Room Unit Logbooks. Revision 4. The licensee developed administrative guidance for the operating staff to ensure proper equipment and system logging practices and clarification of the 600V essential power system desig The failure to record shared equipment inoperability in the affected units' logs was identified as a non-cited violation. This non-repetitive licensee identified and corrected violation is being treated as a Non-Cited Violation. consistent with section VII.B.1 of the NRC Enforcement Policy NCV 50-369.370/98-03-01: Failure to Log System /Fquipment Inoperabilit Subsequent to the 10 CFR 50.72 notification, a detailed evaluation of the issue by the licensee concluded that no actual situations had occurred that would have placed Unit 1 or Unit 2 in an actual unanalyzed condition. The evaluation included reviews of Technical Specification Action Item Logbook (TSAIL) entries and Work Management System (WMS)
records. and interviews with operations and scheduling staff. The inspectors reviewed the licensee's results and determined that the system knowledge of those scheduling maintenance activities prevented multiple redundant components from being ino)erable at the same tim This prevented the licensee from operating t1e plant in an unanalyzed conditio Conclusions The inspectors concluded that the licensees review and evaluation were adecuate to confirm that the plant had not operated in an unanalyzed concition due to unclear shared system interactions. The failure to record shared equipment inoperability in the affected units' logs was identified as a non-cited violatio E3 Engineering Procedures and Documentation E3.1 Review of Technical Documents Insoection Scone (37551)
l The inspectors evaluated licensing basis materials to verify associated I
documents were in conformance with the current operating configurations, methodologies, and conditions.
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. 9 11 Observations and Findinas The inspectors focused the inspection effort on the UFSAR and Technical Specifications (TS). Emphasis was a) plied in verifying data incorporated by reference. During t11s review, the inspectors attended a Plant'0peration Review Committee Meeting where it was identified that current methodologies listed in McGuire TS 6.9.1.9 did not accurately reflect the actual methodologies used in establishing the core operating limits report (COLR).
Reference documents used to develo) the COLR had been determined acceptable; however, they had not )een incorporated into the TS 6.9. listing of references. Upon recognition of the problem, the licensee submitted a TS amendment request to u)date the affected TS section Yhe licensee also initiated process c1anges to ensure proper revision of the TS referenced methodologies in the future. The inspectors verified that the methodology utilized in the COLR was based on NRC approved methodologies. Once identified licensee actions to correct the problem was considered adequate. .The failure to update the list of references was a violation of NRC requirement However, this non-repetitive, licensee identified. and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy. NCV 50-369.370/98-03-02: Failure to Revise Technical Specification 6.9. ] Conclusions A non-cited violation was identified for the licensee's failed to revise the TS to accurately reflect the actual references and methodologies used in developing the COLR.
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E4- Engineering Staff Knowledge and Performance I l
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E4.1 Unit 2 B Train Charoino Puma Remote Valve Ooerator Insoection Scooe (37551)
l The inspectors reviewed the licensee's evaluation and removal of a remote valve operator to ensure licensee compliance with regulatory requirements and license commitments, Observations and Findinas During routine inspections of the auxiliary building inspectors noted a detached remote valve operator at valve 2NV232. the manual discharge isolation valve for the 28 centrifugal charging pump. The discharge isolation valve was normally locked open and was only closed to perform charging pump maintenance. The valve had recently been replaced:
however, the existing reach rod was not long enough to be reattached to the new valve. The inspectors reviewed the completed modification L package MGMM-8470. The modification addressed replacing the valve but E - did not specifically include an evaluation for the removal of the remote l
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valve operator. A Variation Notice VN-84700 was completed to evaluate the temporary removal of the remote operato The ins)ectors performed an extensive review of several licensing and design aasis documents including 10 CFR 50. Appendix A. General Design Criteria. Criterion 4 and 19. NUREG 0737. Clarification of TMI Action Plan Requirements. McGuire UFSAR and McGuire SER Supplement No. 4 to identify any specific criteria for establishing a means for isolating and venting equipment during or following the recirculation phase of ECCS operation. No specific requirements was identified that required the licensee to provide remote valve operation during the long term period of operation which involved bringing the unit to cold shutdown conditions. Although the valve was not specifically identified in plant startup, shutdown or emergency operating procedures, the inspectors questioned the licensee concerning ALARA. Specifically, the advantag if any. of being able to operate the valve remotely during post-LOCA. as radiation levels inside the room increases. The licensee had recognized the potential and has planned to replace the remote operator once replacement parts were procure Conclusions The inspectors concluded that the licensee's evaluation of the removal 4 of the remote operator for 28 centrifugal charging pump discharge j isolation valve 2NV232 was adequat E8 Miscellaneous Engineering Issues E (Closed) VIO 50-369.370/96-07-05: Inadequate 10 CFR 50.59 Evaluation for AFW System Water Hammer Testing On August 6.1996, the licensee conducted a test to verify the conclusion of an operability determination, that a water hammer event would not occur with the presence of steam voids in auxiliary feedwater piping. The licensee did not perform an adequate 10 CFR 50.59 safety evaluation to provide the basis for the determination that the test did not involve an unreviewed safety question (US0) 3rior to conducting the test. The licensee determined that the responsi)le qualified reviewer incorrectly determined that a procedure change was not a test or experiment. The inspector noted that the licensee confirmed that no USQ existed under these test conditions and that the 10 CFR 50.59 evaluation was revised to document the scope of the information known to engineering personnel. The inspector noted that engineering management discussed the inadequacy of the evaluation with both supervisory personnel and the qualified reviewer. The inspectors verified implemented corrective actions which included revision to Nuclear Safety Directive (NSD) 209, 10 CFR 50.59, to include additional guidance to the qualified reviewers. A reading package was also developed to address the lessons learned as a result of the inadequate review and em)hasize the importance of performing conservative 50.59 evaluations. T1e i
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inspector reviewed the reading package and determined that it was adequat The-inspector concluded that overall corrective actions were adequate to address the violation. This item is close E8.2 (Closed) IFI 50-370/97-17-04: Load and Moment Sign Transformation Application from Unit 1 to Unit 2 During SGRP inspection activities, the inspectors identified a potential for incorrect application of coordinate axes included in a piping analysis to support the Unit 2 steam generator replacement. The inspectors reviewed the licensee's methodology prescribed in MCSAG Procedure 8.0 Mirror Image / Identical Routing Analysis Procedure to-complete the Unit'2 main-steam system piping stress analysis. No discrepancies were noted in the methodology used to perform piping design calculation MCC-1206.02-71-0091 to qualify the aiping. The licensee also reviewed the Unit 2 su) port / restraints. )ranchlines, and rupture restraints qualifications. io misapplication were identifie In an effort to minimize the potential for misinterpretation, the licensee also revised calculation MCC-1206.02-71-0091 for clarification. The licensee also reviewed additional main steam branch lines not affected by the steam generator replacement. No discrepancies were noted. There were no actual instances of incorrect application of the coordinates and the licensee's reanalysis of main steam and branchline was sufficient to assure that an appropriate evaluation was conducted. This item is close E8.3 (Closed) URI 50-369.370/98-02-02: Potential Non-compliance with Technical Specifications for Inoperable Engineered Safety Feature Instrumentation for Refueling Water Storage Tank (RWST) Level and Containment Pressure Control System Ins)ection Re) ort 50-369.370/98-02 documented the inspectors' concerns wit 1 troubles 1ooting and repairs of failed components in ESF instrumentation circuits such as the RWST level transmitters and the containment )ressure control system (CPCS). Inspectors discussed the concerns wit 1 plant personnel who provided additional information on equipment reliability and proposed corrective action Since 1993 one RWST loo) power (LP) supply failure had occurred, and 6 CPCS LP supply failures lave occurred since 1990 with 3 of the 6 in the past 5 years. The inspectors also confirmed through a review of TSAIL that during the maintenance evolution to replace the failed LP supply for CPCS 28 train, no 2A ESF train outages occurred that could have caused the 2A containment spray pump to be inoperable during inoperability of the'2B containment spray pump. The licensee's corrective actions included a review of procedures for work on RWST and CPCS instrumentation (still under technical hold). No other plant safety systems circuits were identified that had relays energized to tri) or start equipment. Long-term corrective actions for implementing a clange to the relay power supply design to support maintenance was still under review by engineering.
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The inspectors concluded that these problems were two examples of inadequate procedures'that resulted in failures to maintain TS required ESF positions during maintenance activities. This non-repetitive, licensee-identified and corrected violation.is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy, NCV 50-369.370/98-03-03: Inadequate Procedures Results in Non-compliance With Technical . Specifications for Inoperable Engineered Safety Feature Instrumentation for Refueling Water Storage Tank Level i and Containment Pressure Control System. LER 50-369/98-01 will remain open pending further NRC review of all corrective actions and the root cause analysi E8.4 ! Closed) URI 50-369.370/96-04-02. FSAR Inconsistencies The inspector reviewed the NRC and licensee identified UFSAR inaccuracies detailed in the following table in accordance with the Enforcennt Policy as updated by Enforcement Guidance Memorandum (EGM)96-005, " Enforcement Issues Asscriated with FSARs. Section 8. Enforcement of FSAR Commitments." With respect to the items in the table below, the inspector reviewed the licensee's planned UFSAR review effort to determine whether it was reasonable to conclude that the inaccuracies identified by the NRC would have been identified by the licensee's review program. The inspector had the following findings-associated with the items listed in the tabl Item 1 through 5, 7. and 14, are NRC identified items. Item I was determined not to be a discrepancy. The miniflow valves do close automatically after a safety injection signal. Item 2 is not an FSAR error. The licensee interprets the injection mode and recirculation mode to be two different modes. The recirculation mode relies on operator action but the injection mode is completely automatic after an SI signal. Item 3 was a minor editorial / typographical type error and the table heading has been correcte For. item 4. the UFSAR did not require revision and was correct as written. The minor modification was not properly implemented in accordance with the UFSAR requiremen Item 5 has been corrected by the licensee to clarify that the ventilation system only maintains the positive pressurization of the control room during an acciden Item 7 has been corrected. The ISI schedule has been removed from the UFSAR in a subsequent revisio Item 14 has been resolved. The plant procedures have been changed to eliminate the option of running a single component cooling water pum Previous review and resolution of this issue was discussed in NRC Inspection Report 50-369.370/96-0 The remaining items were licensee identifie __ _ _ _ _ _ _ _ . _ _ _ _ _ _ .
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Item 6 has been resolved by the licensee. The reference to water level has been deleted in the UFSAR. Actual water depth of the fuel assembly is not a critical number. The water is the radiation shielding for plant personnel. Manipulator cranes are equipped with radiation monitors to alert operator of high radiation level Item 8 has been corrected in the UFSAR to identify a height of 3 feet and 6 inches. The analyzed condition is 6 fee Item 9 has been resolved by changing the proce'Jre to limit the lift heights for s Revision to the UFSAR was not required. pent fuel casks to 12 inche Item 10 identified that the fuel lifting and handling devices were capable of supporting maximum loading in a Safe Shutdown Earthquake situation but there was no supporting documentation. Calculations to support the seismic capability of the fuel lifting and handling devices have been completed demonstrating the capability of the equipment within the UFSAR requirements. No revision to the UFSAR was require Item 11 has been addressed. The manipulator crane was originally seismic qualified. The licensee has completed calculation documenting the seismic qualification and resolving all modification to the crane which would have impacted the seismic qualificatio With respect to item 12. the analysis was more conservative than the UFSA The UFSAR has been revised to include the analyzed cycle length for refuelin Item 13 was an editorial error for a safety evaluation repo o. A revision to the UFSAR was not require Item 15 has been addressed by the licensee and the calculation was revised to address the fuel pool rerackin The inspector concluded that the licensee's program to review the UFSAR was of sufficient scope to identify the examples identified by the NRC. The NRC identified discrepancies were of minor significance. Those items identified by the licensee are under the discretion of the EGM. In accordance with the Enforcement Policy, these failures to update the UFSAR not involving unreviewed safety questions and/or of minor significance will be documented in accordance with Sections IV and VI.B.1 of the Enforcement Policy as NCV 50-369.370/98-03-04: Failure to Update UFSAR. Unresolved Item (URI) 50-369.370/96-04-02. FSAR Inconsistencies is close l l
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FSAR DISCREPANCIES Item IR Paragraph Discrepancy 1 97-300 0 Section 7.4.1.6.1 0 Safety Injection Description, page 7-69. The last paragraph on the page describes the electrical interlocks of the system and incorrectly states that the valves on the miniflow line [1(2)NV-150B and 1(2)NV-151A] automatically close (en an SI signal). Actual closure of these valves relies upon operator action at 1500 psig NC pressur .1 Section 6.3.2.2.2 - ECCS System Operation, page 6-147. The last paragraph states " Operation of the Emergency Core Cooling System during
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injection mode is completely automatic." This is not completely
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accurate since operator action is necessary to reposition the recirculation line valves when proper plant condition occu .1 Section 6.3.2.16 - Motor Operated Valves and Controls. page 6-159. The table at the top of the page incorrectly lists valve 1NI-162A as a " Hot leg Recirc Valve." This is actually a " Cold leg injection Valve."
4 96 008 M UFSAR. Section 1.11.5.1.3.1 requires that each process variable the recorded channels be enhanced through the addition of isolators such that the control board recorders will not share isolators with the non-safety computer. A minor modification to ensure proper isolation of the post accident monitoring instrumentation from non-safety circuitry was not properly completed. The minor modifications required the addition of isolators at associated input and output wiring change F UFSAR section 9.5.1.2.6 states that the control room has an independent ventilation system which maintains the area at a slight posittve pressure. The control room ventilation system is continuously pressurized only during accident condition E FSAR 9.1.4.3.4 stated that the manipulator cranes contain positive stops which prevent the top of the fuel pellets in a fuel assembly from being raised to within ten feet of normal water level. Actually. the upper limit switches on the cranes limit height but do not ensure ten feet of water cove E FSAR Chapter 5 contained Table 5.31. concerning an ISI schedule, that was not referenced in the text of Chapter 5 and was not current with the approved 151 plan for the McGuire sit E FSAR 9.1.2.3 stated that the highest level above the fuel racks that the fuel assembly can be dropped is 3 feet. two inches. The re-rack modification changed the height of the fuel racks such that the highest level would be 3 feet. six inche E FSAR 9.1.2.3.6 stated that spent fuel cask lifting height was limited to 12 inches if the cask shock absorbing cov tr is not installed. There were no administrative limits or physical restrictions on the crane to ensure this limit. This 12 inch limit is used in the drop analysi E FSAR 9.1.4.1 stated that fuel lifting and handling devices were capable of supporting maximum loads under Safe Shutdown Earthquake (SSE)
conditions. No documentation was available to validate this seismic capabilit _ _ - _ _ _ - _ _ _ _ _ _ - _ - - - _ _ _ _ _ _ _ _ _ _ _ _ - - _ . . _ _ _ _ _ _ _ _ _ _ - - _ - _ _
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Item IR Paragraph Discrepancy _
11 96-004 E FSAR 9.1.4.3.1 stated that the reactor manipulator crane was designed to prevent disengagement on a fuel assembly from the gripper in an SSE. No documentation was available to support this seismic capabilit E FSAR 9.1.3.1.1 stated that decay heat of s nt fuel was analyzed for a twelve month refueling cycle. Current ana sis addressed refueling cycle of greater than twelve month E SER Supplement 6. Section 3.3 stated that the long term SFP makeup sources included the reactor makeup water storage tank (RMWST) and the refueling water storage tank (RWsT). both at 2000 ppm boron. The RMWST was not a borated water sourc __
14 96-004 E FSAR 9.2.4.2 implies that two component cooling water system pumps are necessary during normal plant operation. Unit I was operated for an extended period following the 1E0C10 outage with only one component cooling water pump in servic E The calculation to determine the nuaber of fuel assemblies affected by a post accidental drop of a fuel pool weir gate did not address the more diversely spaced fuel storage provided by fuel pool re-rackin IV. Plant Support R1 Conduct of Radiation Protection and Chemistry R1.1 General Comments (71750)
The inspectors made frequent tours of the controlled access area and reviewed radiological postings and observed worker adherence to protective clothing requirements. Locked high radiation doors were properly controlled, high radiation and contamination areas were properly posted, and radiological survey maps were updated to accurately reflect radiological conditions in the respective area P2 Status of Emergency Preparedness Facilities and Equipment P2.1 Performance of Emergency Preparedness Practice Drills General Comments (71750)
On March 31, 1998, the inspectors conducted a tour of the McGuire local Emergency Operations Facility (EOF) during the performance of a McGuire emergency preparedness practice drill. The inspectors reviewed the status of the facility and observed the licensee's performance during the drill and its associated drill critique at the EOF. The inspectors concluded that the readiness of the McGuire Emergency Offsite Facility to support a postulated accident was good. The performance of a series of training drills to exercise a new duty rotation for emergency manning was considered a continued example of proactive training in the area of t
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I 18-emergency preparednes Incorporation of the Assistant E0F Director
>osition was considered proactive in increasing the effectiveness of the E0F functio V. Manaaement Meetinas l
X1 Exit Meeting Summary The resident inspectors ) resented the inspection results to members of licensee management at tie conclusion of the inspection on April 24, 1998. The licensee' acknowledged the findings presented. No proprietary information was identifie PARTIAL LIST OF PERSONS CONTACTED Licensee Barron. B., Vice President. McGuire Nuclear Station Bhatnagar. A..-Su)erintendent. Plant Operations Boyle. J., Civil / Electrical / Nuclear Systems Engineering Byrum. W., Manager. Radiation Protection Cash. M., Manager. Regulatory Compliance Dolan. B., Manager. Safety Assurance Evans W.. Security Manager Geddie. E. , Manager. McGuire Nuclear Station Peele. J. , Manager. Engineering Loucks. L., Chemistry Manager Thomas, K., Superintendent. Work Control Travis. B., Manager. Mechanical Systems Engineering INSPECTION PROCEDURES USED IP 71707: Conduct of Operations IP 62707: Maintenance Observations IP 61726: Surveillance Observations IP 40500: Effectiveness-of Licensee Controls in Identifying. Resolving, and Preventing Problems IP 37551: Onsite Engineering IP 71750: Plant Support IP 92902: Followup -- Operations IP 92904: Followup - Engineering
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4 4-19 ITEMS OPENED AND CLOSED OPENED i 50-369,370/98-03-01 NCV Failure to log System / Equipment l Inoperability (Section E2.1)
! 50-369,370/98-03-02 NCV Failure to Revise Technical Specification 6.9.1.9. (Section E3.1)
50-369,370/98-03-03 NCV Inadequate Procedures Results in Non-compliance With Technical Specifications for Inoperable Engineered Safety Feature Instrumentation for Refueling Water Storage Tank Level and Containment Pressure Control System (Section E8.3)
50-369.370/98-03-04 NCV Failure to Update UFSAR (Section E8.4)
CLOSED 50-369/96-06. Rev. O and 1 LER Manual Initiated Actuation of Both Unit 1 Motor Driven Auxiliary Feedwater Pumps Due to Loss of Auxiliary Steam Supply to the Main Feedwater Pump Turbine (Section 08.1)
50-369/97-05 LER In-voluntarily Terminated Employee Entered the Protected Area (Section 08.2)
50-369.370/96-07-05 VIO Inadequate 10 CFR 50.59 Evaluation for AFW System Water Hammer Testing (Section E8.2)
50-370/97-17-04 IFI Load and Moment Sign Transformation Application from Unit I to Unit 2 (Section E8.3)
50-369,370/98-02-02 URI Potential Non-compliance with Technical Specifications for Inoperable Engineered Safety Feature Instrumentation for Refueling Water Storage Tank Level and Containment Pressure Control System (Section E8.4)
50-369,370/96-04-02 URI FSAR Inconsistencies (Section E8.5)
LIST OF ACRONYMS USED
.ALARA - As Low As Reasonably Achievable
'AEB -
Auxiliary Electric Boilers AFW -
Auxiliary Feedwater-AP - -
Abnormal Procedure
- ASME - American Society of Mechanical Engineers
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CCW -
Component Cooling Water CAR -
Code of Federal Regulations COLR - Core Operating Limits Report CPCS - Containment Pressure Control System CR -
Control Room DBA -
Design Basis Accident DBD -
Design Basis Document DES -
Duke Engineering Services DRPI -
Digital Rod Position Indication EDG -
Emergency Diesel Generator EGM -
Enforcement Guidance memorandum EHC -
Electro-Hydraulic Control ENS -
Emergency Notification System EOF -
Emergency operating Facility EP -
Emergency Procedure ESF -
Engineered Safety Feature F -
Fahrenheit GL -
Generic Letter IFI -
Inspector Followup Item IN -
Information Notice IR -
Inspection Report
KV -
Kilo-volt LER -
Licensee Event Report LOCA - Loss of Coolant Accident MOV -
Motor-Operated Valve MSR -
Moisture Separator Reheater MSSV - Main Steam Safety Valve NCV -
Non-Cited Violation NI -
Nuclear Instrumentation l NLO -
Non-Licensed Operators l l
NRC -
Nuclear Regulatory Commission i NRR -
NRC Office of Nuclear Reactor Regulation i NSD -
Nuclear Site Directive i OAC -
Operator Aid Computer l OEA -
Operating Experience Assessment 1 OMP -
Operations Management Procedures PAP -
Personnel Access Portal PCE -
Persennel Contamination Event PCT -
Peak Cladding Temperature PDR -
Public Document Room PIP -
Problem Investigation Process PM -
Preventive Maintenance PT -
Periodic Testing RCA -
Radiologically Controlled Area RCS -
Radiation Protection RPS -
Reactor Protection System RWP -
Radiation Work Permit RWST - Refueling Water Storage Tank SFP -
Spent Fuel Pool SG -
Steam Generator Replacement Project L------_-----_- - - - _ -
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SRWP -
Special Radiation Work Permit SSF -
Standby Shutdown Facility TAT -
Turbine Acceptance Testing TAVG -
Average Temperature TDAFW - Turbine-Driven Auxiliary Feedwater TEAR - Top Equipment Problem Resolution TM -
Temporary Modification TPBE -
Thermal Power Best Estimate TS -
Technical Specifications TSAIL - Technical Specification Action Item Log Book TT -
Temporary Test UFSAR - Updated Final Safety Analysis URI -
Unresolved Item USS -
Utilities Support Specialists Incorporated USQ -
Unreviewed Safety Question V -
Volt VIO -
Violation WMS -
Work Management System WO -
Work Order i
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