IR 05000369/1999003
| ML20195F193 | |
| Person / Time | |
|---|---|
| Site: | Mcguire, McGuire  |
| Issue date: | 06/02/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20195F192 | List: |
| References | |
| 50-369-99-03, 50-369-99-3, 50-370-99-03, 50-370-99-3, NUDOCS 9906140221 | |
| Download: ML20195F193 (25) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGION 11 Docket Nos: 50-369,50-370 License Nos: NPF-9, NPF-17 Report No: 50-369/99-03,50-370/99-03 Licensee: Duke Energy Corporation Facility: McGuire Nuclear Station, Units 1 and 2 )
Location: 12700 Hagers Ferry Road Huntersville, NC 28078 Dates: March 28,1999 - May 8,1999 Inspectors: S. Shaeffer, Senior Resident inspector M. Franovich, Resident inspector R. Chou, Regional inspector (Section E8.5)
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 50-369/99-03, 50-370/99-03 This integrated inspection included aspects of licensea operations, maintenance, engineering, and plant support. The report covered a six-week period of resident inspections and also included regional inspections in the area of the independent spent fuel storage facilit Ooerations a Plant operations placed appropriate emphasis on nuclear safety during the Unit 2 outage evolutions and startup activities. (Section O1.1)
. Unit 2 reactor building equipment was well maintained with no active leaks identifie Areas inspected were free of loose debris which minimized the potential for containment sump strainer blockage. These observations reflected positively on the licensee's material condition walkdowns of containment prior to the restart. (Section O2.1)
. A Non-Cited Violation was identified for failure to meet Technical Specification requirements for low temperature overpressure protection system due to lack of self-verification, checking oversight, and test planning deficiencies. (Section 04.1)
. Operators' draining of the reactor coolant system and plant operations in reduced
, inventory (including midloop conditions) following Unit 2 core reload were satisfactorily performed. Requirements for shutdown Technical Specifications and associated selected licensee commitments were satisfied. (Section 04.2)
. The decision to drain to midloop in lieu of the original outage plan to remove steam generator nozzle dams in reduced inventory was not timely and did no allow for the most efficient use of established risk planning methods. (Section 04.2)
. During an emergency drill, operators in the control room simulator followed plant procedures and communicated clearly and effectively in implementing the abnormal and emergency operating procedures. The crew performed in an excellent manner. (Section 04.3)
Maintenance
. Routine maintenance and surveillance activities reviewed were adequately completed and no problems were identified concerning testing of equipment being restored from the Unit 2 outage. (Section M1.1)
. Initial licensee inspections of the Unit 2 refueling water storage tank indicated that the interior coating system was adequate and there were no immediate operability concern (Section M2.1)
. Foreign material (gasket material and sand blast particles) were found in the Unit 2 refueling water storage tank. Past and current operability for the material were considered adequate based on current information. (Section M2.1)
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The licensee operability evaluations and attempts to retrieve metal shavings from the Unit 2 containment spray system were considered adequate. (Section M2.2)
Enaineerina
The licensee appropriately identified an adverse trend in the pressurizer heater capacity, identified the root cause of the problem, and took appropriate actions to correct the issue I in the current refueling outage. The issue could have been prevented by a more detailed procurement review process of We replaced heater cable termination lugs. (Section E8.2)
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A Non-Cited Violation was identified for failure to effectively translate the design basis and applicable regulatory requirements for the turbine driven auxiliary feed water pumps'
main steam supply piping into specifications, drawings, and procedures. (Section E8.4)
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Report Details Summarv of Plant Status Unit 1 Unit 1 operated at approximately 100 percent power throughout the inspection perio Unit 2 Unit 2 began the inspection period in a shutdown and defueled configuration while completing activities associated'with the End of Cycle (EOC) 12 refueling outage. The unit was restarted on April 14,1999, and reached approximately 100 percent power on April 18,1999, where it operated for the remainder of the inspection perio l 1. Operations 01 Conduct of Operations .
O1.1 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-conscious. During this inspection period, the licensee completed the EOC 12 refueling outage for Unit 2 including successful midioop operations and restart of the unit. The inspectors observed portions of the midioop evolutions and startup activitie Operations placed appropriate emphasis on nuclear safety during the outage evolutions and startup activities. Other specific events and noteworthy observations are detailed in the sections which follow, including one operator performance issue involving failure to maintain Technical Specification (TS) requirements for low temperature overpressure protection limits which occurred during Unit 2 outage activities (see Section O4.1).
01.2 10 CFR 50.72 and Other Reauired Notifications Insoection Scope (71707)
i During the inspection period, the licensee made the following notification to the NRC as I required by 10 CFR 50.72. The inspectors reviewed the event for impact on the operational status of the facility and equipmen Observations and Findinas On May 4.1999, the licensee made a report to the NRC in accordance with 10 CFR 50.72 (b)(1)(ii)(A) conceming the discovery of a previously unanalyzed condition associated with Unit 2. The licensee determined that problems first identified on March 14,1999, on the Unit 2 steam generator (SG) power operated relief valves l
_ (PORVs) resulted in two SG PORVs being inoperable greater than the time allowed by TS 3. _
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These problems were initially identified with the unit shutdown in Mode 5. The condition involved shaft keys which enable two SG PORVs to be manually operated in response to the mitigation of certain design basis accidents not being properly installed or missin The problems were corrected on Unit 2 prior to restart from the recent refueling outag However, the fact that the missing keys resulted in the plant being in an unanalyzed condition was not recognized until after the unit was restarted. Additional corrective actions included verifying that the Unit 1 SG PORVs had the keys correctly installed. At the end of the inspection period, the licensee was performing a review to determine the root cause as to why the SG PORVs' shaft keys were improperly installed or missin The licensee indicated their intentions to submit Licensee Event Report (LER) 50-370/99-01-00, Failure to Comply with Operability Requirements and Required Action of T.S. 3.7.4 regarding this issue. The NRC will review the licensee's root cause and, if applicable, additional corrective actions once the LER is complete Conclusions The inspectors concluded that once the significance was recognized the licensee reported the above issue in accordance with the requirements of 10 CFR 50.7 Immediate corrective actions were appropriate for the identified proble O2 Operational Status of Facilities and Equipment O2.1. Post-Outaae Inspection of Reactor Buildina and Eauioment Insoection Scope (71707. 62707. 71750. 37551)
During heatup of the unit following containment closeout for the EOC 12 refueling outage, the inspectors conducted inspections of the Unit 2 reactor building and equipment to verify that accessible portions of selected safety-related systems and components were properly aligned and the areas were free of loose material Observations and Findinos
- The inspectors focused on areas and components near completed outage maintenance work activities to verify leak tightness and containment cleanliness. The inspectors also confirmed 10 CFR 50, Appendix R required reactor coolant pump oil collection containers were empty and properly aligned; refueling drains were open; and that the material condition of the unit containment emergency sump was acceptable. Very little debris was identified by the inspectors. The reactor building equipment and support systems observed by the inspectors were properly maintained and aligned. The inspectors also inspected incore instrumentation rooms for pressure boundary leakage, cleanliness, and equipment condition. No problems were noted in these area Conclusions Based on post-outage containment walkdowns, the inspectors concluded that reactor building equipment was well maintained with no active leaks identified. The inspectors
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3 confirmed that the pipe chase and lower equipment areas of the reactor building were free of loose materials and equipment which minimized the potential for containment sump strainer blockage. These observations reflected positively on the licensee's material condition walkdowns of containment prior to the restar Operator Knowledge and Performance 04.1 Noncomoliance with TS 3.4.12 Durina Unit 2 Shutdown for Refuelina Insoection Scooe (71707)
The inspectors reviewed and evaluated licensee actions following identification of a failure to comply with TS 3.4.12, Low Temperature Overpressure Protection (LTOP)
System. The inspectors discussed the circumstances which led to the event with operations personnel and reviewed LER 50-370/99-002-00, Failure to Comply with the Required Actions of TS 3.4.12, LTOP System, With Two Centrifugal Charging Pumps Capable of injecting into The RC Observations and Findinas On March 18,1999, with Unit 2 in Mode 5 and the reactor coolant system (RCS) cold leg temperatures below 107* Fahrenheit (F), the unit was aligned with two centrifugal charging pumps capable of injecting into the RCS. In this condition, McGuire Nuclear Station TS 3.4.12 prohibits operation in Mode 5 with more than one centrifugal charging or safety injection pump capable of injecting into the RCS, except during pump swap-out of durations less than 15 minutes. Unit 2 remained in this condition for approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> during centrifugal charging pump performance testing in accordance with PT/2/A/4209/12A and 128. Upon completion of the performance tests, the licensee returned one of the two centrifugal charging pump breakers to the racked out position, re-establishing the appropriate system configuration. The licensee subsequently identified that the inappropriate configuration had existed and initiated Problem Investigation Process Reports (PIP) 2-M99-1295 to document the proble Inspector discussions with shift personnel concluded that they were familiar with the requirements of LTOP TS; however, the licensee in this case failed to recognize correct applicability of the TS and verify that LTOP system conditions were not applicable prior l to initiation of the testing. A specific problem involved the operators inappropriately referencing hot leg versus cold leg temperatures in their decision making proces Format changes for Improved TS upgrade and a lack of self-checking were also contributing factor The TS implications c,f allowing two centrifugal charging pumps capable of injecting into i the RCS were not recognized. This oversight resulted in the plant being in a more risk significant condition since the overpressure protection from mass input type transients was not in effect. Since unexpected mass input event and pressure fluctuation can occur more quickly during Mode 5 shutdown conditions, allowing two centrifugal charging pumps capable of injecting into the RCS, the potential was compounded for exceeding
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the pressure limitations specified in 10 CFR 50, Appendix G. However, the inspectors also noted that no luch head injection occurred during the condition and all three pressurizer PORVs and their associated block valves were open, though not blocked open. This would have aided in the mitigation of any pressure transient, had it occurre The licensee failed to comply with this condition for approximately four hours on March 18,1999. This is identified as Non-Cited Violation (NCV) 50-370/99-03-01, Failure to Meet the Requirements of TS 3.4.12, LTOP. This Severity Level IV violation is being treated as a NCV, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as PIP 2-M99-129 Conclusions A NCV was identified for failing to meet TS rquirements for the low temperature ,
overpressure protection system. The licens .e's corrective actions were appropriate to address the lack of self-verification and checking oversight and test planning deficiencie .2 Unit 2 RCS Drain Down and Midlooo Operations Insoection Scope (71707)
The inspectors observed control room activities associated with draining of the RC The inspectors verified that these evolutions were performed in accordance with approved procedures, that appropriate oversight was present, and that TS requirements were followed. NRC Generic Letter (GL) 88-17, Loss of Decay Heat Removal, McGuire Site Directive 403, Shutdown Risk Management Guidelines, plant procedures for minimizing shutdown risk, the outage work schedule, and plant configuration were reviewed prior to the planned drain dow i Observations and Findinas j
A post-refueling (Iow decay heat conditions) drain down to reduced RCS level was performed on April 4,1999. The licensee drained RCS level from approximately 350 inches above centerline of the RCS hot leg to 10 inches to remove a SG nozzle dam (large vent path) and install the reactor vessel head. Reduced inventory is approximately 48 inches above centerline (3 feet below the reactor vessel flange).
Midloop conditions at McGuire is 15 inches or less above RCS hot leg centerline. The RCS drain down was performed in accordance with operating procedures (OP)
OP/2/A/6100/SO-3, Draining the Refueling Cavity, and OP/2/A/6100/SU-2, Refueling and Replacing the Reactor Vessel Head. Unit 2 operated approximately 44 hours5.092593e-4 days <br />0.0122 hours <br />7.275132e-5 weeks <br />1.6742e-5 months <br /> in midloop condition The original outage plan for 2EOC12 did not include plans for draining the RCS to midloop conditions since draining to midloop is not physically required to remove SG nozzle dams. An independent review team reviewed the outage plan to identify, in advance of the outage, schedule changes that could minimize shutdown risk. The
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results were presented before the plant operating review committee (PORC). However,
. several days prior to the evolution, the licensee decided to drain the RCS to midloop because of postulated radiological concems with nozzle dam removal. An engineering evaluistan was performed to support this decision with the independent review team concurrence. However, the inspectors considered that the late decision to go into midloop ( onditions for an extended time did not allow for the most effective risk planning for the ev !utio Prior '.o the. drain down evolution, the licensee conducted a special pre-job briefing as
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reo;; ired by procedures for conduct of infrequently performed evolutions. During the craining activities, operators appropriately stopped draining the RCS at approximately 10 inches because of discrepancies between wide range and narrow range level indication (approximately 5 inch difference). Procedure OP/2/A/6100/SO-3 requires that at 20 inches RCS level, wide range and narrow range must be in agreement. A technician performed an instrument calibration of the narrow range and discovered the instrument was greater than 2 times out of its tolerance band. Once the instrument discrepancies were resolved, operators proceeded to drain down the RCS to approximately 10 inche The inspectors observed that a three-hour delay occurred due to the instrumentation problem which extended the overall time in reduced inventory conditions. Standard troubleshooting practices were employed, ultimately resulting in a containment entry by a technician to calibrate the narrow range instrument. The inspectors and the licensee observed that these standard troubleshooting techniques extended the time in reduced inventory. The inspectors also observed that procedure OP/2/A/6100/SO-3 did not provide quantitative criteria for allowable instrumentation discrepancies and did not direct operators to another procedure to obtain such information. Lack of clarity on OP/2/A/6100/SO-3 partially added to the delay. Operators used a diagram provided in a shutdown procedure (OP/2/A/6100/SD20) which contains tolerances for individual RCS level instruments and determined the maximum allowed deviation between wide range and narrow range indication. These observations were communicated to operations management. The licensee identified additional areas for improvement that could -
reduce the time in reduced inventory and entered these items into the corrective action progra Conclusions Overall, draining of the reactor coolant system and operation in reduced inventory (including midloop conditions) following the Unit 2 core reload were satisfactorily performed. However, the decision to drain to midloop in lieu of the original outage plan to remove steam generator nozzle dams in reduced inventory was not timely and did not allow for the most efficient use of established risk pianning methods. Requirements for shutdown Technical Specifications and associated selected licensee commitments were satisfie *
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04.3 Control Room Simulator Observations Durina Emeroency Drill Scenario I
a.- Insoection Scone (71707)
The inspectors observed the licensee's control room simulator activities associated with an emergency drill. The inspectors reviewed the drill scenario and observed operators'
performance in implementing various abnormal procedures (APs), emergency procedures (EPs), and response procedures (RPs). Observations and Findinas On April 28,1999, the licensee held an emergency drill exercise to demonstrate effectiveness of McGuire emergency plans. The inspectors observed operator performance on the plant simulator. This scenario involved staffing the simulator control room, the technical support center (TSC), and the emergency operations facility (EOF).
During the drill, a year 2000 (Y2K) type computer problem was intentionally introduced to challenge licensee staff to cope with potential Y2K issues in the future. Specifically, the electronic notification form (ENF) program system was disabled and required EOF personnel to manually develop handwritten ENFs to be transmitted to offsite authoritie The inspectors observed a challenging scenario involving a loss-of-coolant accident with multiple equipment failures. Operators in the control room simulator followed plant procedures and communicated clearly and effectively in implementing the APs and EP Operators performed tasks in a timely manner and worked through the procedures at a j good pace. Time critical actions were performed appropriately. Station communication !
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standards were adhered to during the drill. Minor discrepancies were identified and resolved by the licensee. The crew performed in an excellent manner. A post-scenario critique was held among the operators. The inspectors considered the critique a candid -
and positive forum for exchange of information to improve operator and overall crew performance. The inspectors also reviewed the licensee's overall critique of the drill as documented in PIP 0-M99-2301 which was used to track, trend, and resolve areas of concern for the training dril Conclusions l During an emergency drill held on April 28,1999, operators in the control room simulator followed plant procedures and communicated clearly and effectively in implementing the !
abnormal and emergency operating procedures. Minor discrepancies were identified l and resolved by the licensee. The crew performed in an excelient manne Miscellaneous Operations issues (92901, 90712)
08.1 (Closed) LER 50-370/99-002-00: Failure to Comply With The Required Actions of TS 3.4.12, LTOP System, With Two Centrifugal Charging Pumps Capable of injecting into The RCS This LER is closed based on the review completed in Section O .
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11. Maintenance
.M1 Conduct of Maintenance M1.1 General Comments Insoection Scope (61726. 62707)
The inspectors reviewed a variety of maintenance and/or surveillance activities during the inspection period, focusing on outage related testing and maintenance activities including the following specific items:
. CP/0/B/8600/027, Revision 16, Sampling Diesel Fuel Oil Tank Trucks
. PT/0/A/4150/21, Revision 87, Post Refueling Controlling Procedure For Criticality, Zero Power Physics Testing, and Power Escalation Testing
. PT/2/A/4209/12A, and 12B, Revision 7, Centrifugal Charging Pumps 2A and 2B Head Curve Performance Test and Acceptance Testing of Various NV/NI System Check Valves
- PM 2iPECA9020, Testing on SSPS Train B
= MCC-1201.04-00-0002, Revision 10, Refueling Water Storage Tank Design Calculation 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 Conclusions The inspectors concluded that the reviewed routine maintenance and surveillance activities were completed adequately. No problems were identified conceming testing of equipment being restored to operable status from ths Unit 2 outag M2 ~ Maintenance and Material Condition of Facilities and Equipment M2.1 Unit 2 Refuelina Water Storaae Tank (RWST) Interior inspection Insoection Scope (61726. 62707)
The inspectors reviewed video taped inspections of the interior of the Unit 2 RWST and discussed the identified material condition with licensee engineering personnel. The inspectors referenced previous inspection finding in Inspection Reports 50-369,370/98-
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06 and 50-369,370/98-07, applicable vendor information, the facility design basis documentation, and available vendor information. The inspectors also reviewed the past operability determinations made by the licensee for foreign material identified within the RWST during the video inspectio Observations and Findinas During the Unit 2 Cycle 12 refueling outage, the licensee developed means to use video for inspecting the interior of the RWST. In the above subject inspection reports, concems were raised regarding the lack of interior tank inspections for both the integrity of the interior tank coatings and the potential for unidentified foreign material. A camera was inserted through a vent hole in the top center of tank. The results of the inspection concluded that the overall condition of the interior coating system (Plasite 7155H installed in 1978) was adequate for continued operation. Several small areas of '
localized rust indications, blistering, and pitting from coating failure were identifie These were concentrated on areas around the top vent and manway penetrations, and several other areas. The licensee evaluated the pit indications based on visual analysis and pre-established acceptance criteria and concluded that they did not exceed applicable limits. Most blistering indications were in areas which appeared to have been repaired after the original coating system was applied to the constructed tank. In addition, ultrasonic inspections were performed on the exterior of the tank shell. No abnormal indications were identified which would challenge tank operability. Other interior components were also reviewed including installed heaters, temperature indication wells, and emergency core cool;ng suction supply piping. No operability concems were identified regarding these component During the inspections, two types of foreign material were identified. One type consisted of several small pieces of gasket material located on the bottom of the tank (away from the tank suction). This material was successfully retrieved and removed from the tank prior to restart of the unit. The second type of foreign material found was determined by l the licensee to be residual sandblasting material which was used during initial interior tank coating installation / repair. This material had collected on the bottom of the tank in several locations. None of the material was in the immediate vicinity of the RWST suction supply piping, which is located approximately 12 inches off the bottom of the
' tank. The licensee did not attempt to remove the identified material from the tank during the current outage. The licensee reviewed the amount of the material, its location related to the suction supply line, other factors and the use of engineering judgement to conclude that the material did not impose any operability concern. This justification was documented in PIP 2-M99-1233. No concerns were identified based on the inspectors'
review of the operability evaluatio Based on the as-found conditions in the Unit 2 RWST, the licensee was planning on performing baseline inspections in the Unit 1 RWST during the next scheduled refueling outage. The licensee also indicated that they were reviewing the establishment of some type of periodic inspections to be performed in order to maintain assurance that the RWST and its interior components, including the coating system, remained satisfactory for future operatio *
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9 Conclusions initial Unit 2 interior RWST inspections provided indication that the material condition of !
the applied interior coating system was adequate and no immediate operability concems were identified. Identified foreign material was appropriately removed or adequate justification was provided to allow it to remain in place for the next operating cycl Engineering efforts to establish the current and periodic future inspections were appropriat M2.2 ~ Foreion Material Found in the Unit 2 Containment Sorav System Insoection Scope (62707. 40500)
l The inspectors reviewed and evaluated conditions related to foreign material identified in i the Unit 2 containment spray system. Corrective actions, plant procedures for foreign material exclusion (FME) control, and an associated operability evaluation were reviewe Observations and Findinos During the Unit 2 EOC 12 refueling outage, while filling and venting the containment spray system, operators discovered foreign material (metal shavings) in the 2B containment spray piping. The metal shavings were identified in fluid samples taken while leak testing check valve 2NS163. The licensee addressed this issue in PIP 2-M99-1799 and noted that the metal shavings were likely introduced into the system during a containment spray check valve outage modification. These shavings were from pipe boring operations, and it appeared that some of the debris was not vacuumed from the syvent. Immerjiate corrective actions included visual boroscope inspection of the smerh. The 4 stem engineer determined that the most likely location for deposit of the shavings would be in the containment spray heat exchanger. Transportability of the limited debris was evaluated not to be a concem on system subcomponents, including containment spray nozzles (3/8-inch diameter holes). The licensee determined that none of the debris collected was large enough to block spray nozzles. The licensee informed the inspectors that both trains of containment spray were determined to be operabl Nuclear Site Directive (NSD)-104, Housekeeping, Material Condition, and Foreign Material Exclusion, Revision 16, provides guidance for the control of foreign material when performing work activities. NSD 104.7, Rules For Maintaining And Verifying A Cleanliness Zone, states that during work activities, efforts should be make to control cleanliness within established barriers. One such technique that should be considered to maintain required system cleanliness is vacuuming. The NSD 104.7 also states that verification of system cleanliness is required prior to system / component closur Verifications may range from visual inspections to system flushes with acceptance criteria. The inspectors determined that the licensee failed to adequately remove the metal shavings which were introduced into the system following a containment spray check valve outacJe modification, as required by NSD-104. This failure to adequately
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remove the metal shavings constitutes a violation of minor significance and is not subject to formal enforcement actio Conclusions The licensee operability evaluations and attempts to retrieve metal shavings from the Unit 2 containment spray system were considered adequat Ill. Ennineerina E8 Miscellaneous Engineering issues (92902, 92903,60853)
E (Ooen) Unresolved item (URI) 50-369.370/96-10-05: Use of Compensatory Measures to Ensure Control Room Ventilation System Operability This issue involved the licensee's practice of breaching the control room pressure boundary to support control room ventilation system maintenance or other system testing. During these planned activities, the licensee did not declare the control room ventilation system inoperable per the TS, which would have resulted in both trains of the system being inoperable and entry into TS 3.0.3. Instead, the licensee declared the control room ventilation system operable, but degraded based on planned compensatory measures to restore the breach to the closed position within a three-minute allowable time-frame, reviewed via 10 CFR 50.59. The inspectors were concemed that the licensee's practice may have introduced new failure mechanisms which would require NRC review. Review of this issue has been performed by the NRC's Office of Nuclear Reactor Regulation (NRR) and is provided as an enclosure to the letter which forwards this report (Task interface Agreement (TIA)98-008). Pending additional NRC review, this issue remains ope E8.2 (Closed) Insoector Followuo item (IFI) 50-369.370/98-13-01: Root Cause of Pressurizer Heater Failures During the Un't 2 EOC 12 refueling outage, the licensee performed inspections of failed pressurizer heater cables. The inspectors reviewed the licensee's root cause investigation, inspected portions of the failed components, reviewed procurement specifications, and discussed the failures with responsible engineering personnel. The inspection confirmed an engineerin0 hypothesis that a different type of heater cable termination lug installed during the previous refueling outage did not function as well as the original lugs. Within an approximate two to three month period of operation after the EOC 11 refueling outage, over twenty heaters failed, leaving 31 of the total 78 being non-functional. Prior to the current outage, the licensee believed that they had reterminated the majority of the pressurizer heater connections during the EOC 11 outage. However, during the current refueling outage, the licensee identified that due to miscommunication of the actual work performed, only 27 of the cables were actually terminated with the new lugs. Based on this information, the licensee concluded that of the 27 lugs installed during the EOC 11 outage, approximately 23 failed within three months. Corrective actions during the EOC 12 outage included replacement of the failed heater termination i
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lugs with lugs similar to the original supplied by the vendor. The new lugs included improved design features such as a longer crimp barrel and more suitable dimensions for the applicatio Throughout period of degraded heater capacity, the inspector verified that the licensee maintained the minimum TS required capacity as defined by TS 3.4.9. No operability concems were identified. The inspectors concluded the licensee appropriately identified j an adverse trend in the pressurizer heater capacity, identified the root cause of the l problem, and took appropriate actions to correct the issue in the current refueling outag Unit 1 was not affected by this problem. Although the failed heater lugs were specified for use in the application as pressurizer heater cable terminations, other factors such as
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environmental conditions during installation, installation practices, and a less rigorous design, led to the subject failures. The inspectors concluded that the issue could have been prevented by a more detailed procurement review process of fne replaced heater cable termination lugs. In addition, had the licensee performed the heater cable termination replacement on more than 27 heaters, the impact of this common mode failure mechanism could have developed into a total loss of pressurizer heater capacit This issue is close E8.3 (Closed) IFl 50-369.370/98-10-01: Potential Common Mode Failure of Emergency Diesel Generators (EDGs) Due to Degradation of Fuel Oil During Cold Weather This item documented the inspectors' concems with potential EDG inoperability due to cold fuel oil. The licensee addressed this issue via PIP 0-M-98-4125. The licensee evaluated the likelihood of the fuel oil lines experiencing sustained temperatures below the chemistry test procedure cloud point limit of 23' F. This cloud point is defined by American Society for Testing and Materials (ASTM) standard D975-81. Meteorological data revealed that the longest time that outdoor temperatures were below 23*F was a 57-hour period in 1989. The licensee evaluated the pits where the fuel oil transfer lines are located and determined that ground temperatures should keep these lines at approximately 50*F. In addition, the licensee informed the inspectors that McGuire diesel fuel oil is procured to a 15*F criterion for cloud point. The inspectors reviewed the l last six surveillances performed on EDG fuel oil and verified that the cloud point i acceptance criterion was met. This issue is close l E8.4 (Closed) URI 50-369.370/98-04-02: General Design Criteria (GDC) 57 Implementation and Updated Final Safety Analysis Report (UFSAR) Actions on Valves SA-1 and SA-2 This URI had been opened to address a licensee-identified design oversight associated with Unit 1 and Unit 2 containment penetrations M-261 (B Main Steam to the Turbine Driven Auxiliary Feedwater (TDAFW) Pumps) and M-363 (C Main Steam to TDAFW Pump). The two penetrations did not comply with 10 CFR 50, Appendix A, GDC 57, in that the lines providing main steam to the pump turbines were not provided with valves that were either automatic, locked closed, or capable of remote manual operation. The two containment isolation valves associated with these lines,1(2)SA-1 and 1(2)SA-2, are manual gate valves that were locked open to maintain the TDAFW pumps operable. The licensee submitted a letter to the NRC on April 20,1999, requesting exemption from the m
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GDC on the basis that the as-designed configuration was necessary to maintain each unit's TDAFW pump operable, and that providing motor operators to the two valves would introduce an additional failure mode which could degrade the reliability of the TDAFW pump to mitigate an accident. The licensee stated, as further basis, that the valves could be manually closed as necessary to isolate a faulted steam line, unless they were inaccessible due to post-accident environmental conditions, in which case associated stop check valves could be used. The licensee stated in its submittal that the time needed to isolate steam using SA-1 and SA-2, or their associated stop check valves, had been factored into accident analyses and dose calculations referenced in the UFSA The NRC granted the Catawba station an exemption for the same issue via a letter dated December 29,1998. In that letter, the NRC concluded that literal compliance with the operational requirements of GDC 57 was not desirable, as it potentially conflicted with the existing TS related to the TDAFW pump and was not necessary to achieve the underlying purpose of the rule (to provide a reliable means for isolating the penetration).
NRC issuance of the exemption effectively corrected the GDC noncomplianc The McGuire design basis was described in the UFSAR. The inspectors reviewed UFSAR Section 3.1, "Conformance With General Design Criteria", and noted for Criterion 57, that the licensee provided the following discussion: "Each line that penetrates the reactor containment and is neither part of the reactor coolant pressure boundary nor connected directly to the containment atmosphere has at least one containment isolation valve located outside the containment as close to the containment as practical." Implicit in that statement was the understanding that the valves complied with GDC 57. The only exception to the criterion taken in the UFSAR was for the residual heat removal system. The inspectors determined that the licensee's failure to effectively translate the design basis and applicable regulatory requirements for the TDAFW pumps' main steam supply piping into specifications, drawings, and procedures prior to NRC issuance of the GDC exemption constituted a violation of 10 CFR 50, Appendix B, Criterion lli (Design Control). This Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement l Policy. This violation is in the licensee's corrective action program as PIP 0-M97-354 This item is identified as NCV 50-369,370/99-03-02: Failure to Comply with GDC 57 for Main Steam Supply Piping to the TDAFW Pumps. This issue is close E8.5 (Closed) IFl 50-369.370/98-09-04: Design Discrepancies In the Calculations MCC 1140-00-0010 and -0011 This issue concerned minor calculation problems and site seismic issues, including assuring that the fuel storage cask does not alide or tip over on the concrete pad during earthquake conditions. The licensee consulted with the TN-32 cask vendor to resolve the seismic, sliding, and tip over issues. The vendor revised the TN-32 cask's safety analysis report (SAR) and set maximum seismic allowable acceleration with a minimum friction coefficient for horizontal and vertical directions, at center of gravity of the cask, to be 0.26 g (g is the gravity acceleratlon) and 0.17 g, respectively, to prevent the cask from sliding on the top of the concrete pad. A minimum friction coefficient of 0.35 between the
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13 cask and the pad was required to prevent cask sliding. This figure is in accordance with I
the maximum seismic allowable horizontal acceleration 0.26 g. The maximum allowable seismic horizontal acceleration for cask tip over was slightly higher than that for slidin Therefore, the sliding condition would be the worst case scenario and can be used as a controlling factor. In order to meet the cask sliding requirements during seismic events, the licensee determined that the pad size needed to be 16 feet by 16 feet for each cas There was an 8 foot spacing between two pad The inspectors reviewed the following revised calculations and associated drawings:
. Calculation MCC 1140.00-00-0010, Concrete Slab (Foundation) Analysis for Dry l Cask Storage, Revision 1
. Calculation MCC 1140.00-00-0011, Concrete Manhole and Trench Design for McGuire N. S. ISFSI, Revision 0
. Calculation MCC 1140.00-00-0012, Dry Cask Storage - Determination of Cask Seismic Accelerations, Revision 0 The inspectors considered the calculations to be adequate except for one calculation regarding a cask bottom acceleration of 0.13 g. The inspectors were concerned about the accuracy of the computer generated output which evaluated cask bottom seismic acceleration of 0.13 g at fundamental frequency 7 Hertz to be less than the ground seismic acceleration of 0.24 g at frequency 7 Hert On April 26 and 27,1999, representatives from the Office of Nuclear Reactor Regulation and the Spent Fuel Project Office of the Office of Nuclear Material Safety and Safeguards arrived the McGuire site to evaluate the seismic acceleration issue. The i seismic analysis was reviewed including the computer model, computer input, and the soil property information and discussions were conducted with the licensee's personne A visit was conducted to the concrete pad construction site to evaluate the soil and site conditions. The inspectors determined that the large mass of the combined structure of the cask and the concrete pad would be similar to the rigid condition of the ground. The ground vibrates at a rigid frequency of 33 Hertz for an acceleration of 0.15 g which causes the combined structure to vibrate at a frequency of 7 Hertz for an acceleration of 0.24 g at the center of gravity. This is less than the maximum allowed design of 0.26 g and 0.17 g. At these conditions the cask bottom has an acceleration of 0.13 Consequently, the ground and the cask will vibrate at different frequencies at the same tim Based on the calculation review and discussions with licensee's personnel, the analysis ,
of the seismic acceleration was considered to be adequate. This item is close l
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IV. Plant Support R1 Radiological Protection and Chemistry Controls R1.1 General Comments (71750)
The inspectors made frequent tours of the controlled access area and reviewed radiological postings. The inspectors observed that workers were adhering to protective clothing requirements. The inspectors also determined that 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 F8 Miscellaneous Fire Protection issues (37551)
F8.1 (Closed) IFl 50-369.370/98-09-05: Potential Overpressurization of Fire Protection Piping in the Standby Shutdown Facility (SSF) Diesel Room This item documented the inspectors' observations and concerns during a walkdown of fire protection piping in the SSF diesel room. Specifically, line pressures reading on a local gauge were reading approximately 190 pounds per square inch gauge (psig) on the downstream side of an alarm check, which was higher than the 150 psig design pressure rating indicated by plant drawings. The licensee addressed this issue in PIP 0-M99-0102. Actual capacity of the installed piping was evaluated to be greater than the indicated line pressure on the field gauge. The licensee could not identify the cause of the higher than normal line pressure and postulated that the line had experienced a pressure transient in the past. This item is close V. Manaaement Meetinas X1 Exit Meeting Summary The resident inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on May 13,1999. The licensee acknowledged the findings presented. No proprietary information was identifie In addition to the above, the licensee submitted the following comments regarding Section E8.1:
McGuire management understands that a Technical Interface Agreement (TIA)
response will be included as an enclosure to the Inspection Report for this perio Site management further understands from the exit that this response will bring into question the use of manual compensatory actions to maintain operability of control room ventilation. The use of manual compensatory actions to maintain technical specification equipment operable is an issue of generic applicability to the industry. McGuire will provide a formal position on the docket after receipt of
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the inspection report. Duke will also seek to have further discussions with the Office of Nuclear Reactor Regulation (ONRR) in an effort to clarify the issues and seek the appropriate regulatory framework for resolution in this regar PARTIAL LIST OF PERSONS CONTACTED Licensee Barron, B., Vice President, McGuire Nuclear Station Bhatnagar, A., Superintendent, Plant Operations Boyle, J., Manager, 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 37551: Onsite Engineering I IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems ,
IP 60853: Onsite Fabrication of Components and Construction of an ISFSI IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 71707: Conduct of Operations IP 71750: Plant Support IP 90712: Event Reports IP 92901: Followup - Operations IP 92902: Followup - Maintenance IP 92903: Followup - Engineering ITEMS OPENED, CLOSED, AND DISCUSSED OPENED 50-370/99-03-01 NCV Failure to Meet the Requirements of TS 3.4.12, LTOP Reactor (Section 04.1)
50-369,370/99-03-02 NCV Failure to Comply with GDC 57 for Main Steam Supply Piping to TDAFW Pumps (Section E8.4)
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CLOSED 50-370/99-002-00 LER Failure to Comply with the Required Actions of TS 3.4.12, LTOP System, with Two Centrifugal Charging Pumps Capable of injecting into the RCS (Sections O4.1 and 08.1)
50-369,370/98-13-01 IFl Root Cause of Pressurizer Heater Failures (Section E8.2)
50-369,370/98-10-01 IFl Potential Common Mode Failure of EDGs Due to Degradation of Fuel Oil During Cold Weather (Section E8.3)
50-369,370/98-04-02 URI General Design Criteria (GDC) 57 Implementation and Updated Final Safety Analysis Report (UFSAR)
Actions on Valves SA-1 and SA-2 (Section E8.4)
50-369,370/98-09-04 IFl Design Discrepancies in the Calculations MCC 1140-00-0010 and -0011 (Section E8.5) j i
50-369,370/98-09-05 IFl Potential Over-pressurization of Fire Protection Piping in the SSF Diesel Room (Section F8.1)
DISCUSSED l 50-370/99-01-00 LER Failure to Comply with Operability Requirements and Required Action of T.S. 3.7.4 (Section O1.2)
i 50 369,370/96-10-05 URI Use of Compensatory Measures to Ensure Control !
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Room Ventilation System Operability (Section E8.1)
Abnormal Procedure ASTM -
American Society for Testing and Materials CFR - Code of Federal Regulations EDG - Emergency Diesel Generator ENF -
Electronic Notification Form EOF -
Emergency Operations Facility EOC -
End of Cycle EP -
Emergency Procedures F -
Fahrenheit FME -
Foreign Material Exclusion GDC - General Design Criteria
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GL -
Generic Letter IFl -
Inspector Followup Item IR -
Inspection Report
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' Licensee Event Report LTOP -
Low Temperature Overpressure Protection NCV -
Non-Cited Violation NRC -
Nuclear Regulatory Commission NRR NRC's Office of Nuclear Reactor Regulation NSD- Nuclear Site Directive OP -
Operating Procedure PDR -
Public Document Room PIP -
Problem investigation Process PORC --
Plant Operating Review Committee PORV -
Power Operated Relief Valve PSIG -
Pounds Per Square Inch Gauge PT -
Periodic Te: ting RCS -
Reactor Coolant System RP - Response Procedures RWST -
Refueling Water Storage Tank SAR -
Safety Analysis Report SG -
Steam Generator j SSF -
Standby Shutdown Facility j TDAFW -
Turbine Driven Auxiliary Feed Water TIA -
Task interface Agreement TS -
Technical Specifications TSC - Technical Support Center UFSAR -
Updated Final Safety Analysis Report URI -
Unresolved item Y2K -
Year 2000 -
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/ y UNITED STATES 3 E e- E NUCLEAR REGULATORY COMMISSION E WASMNc*f 0N, D.C. 255-0001
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- March 31, 1999 MEMORANDUM TO: Loren R. Plisco, Director -
l Division of Reactor Projects Region Il FROM: Suzanne C. Black, Deputy DirectorMdfM Division of Licensing Project Management
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Office of Nuclear Re. actor Regulation SUBJECT:
TASK INTERFACE AGREEMENT (TIA 98008)- USE OF MANUAL COMPENSATORY ACTIONS ON CONTROL ROOM EMERGENCY VENTILATION SYSTEM AT THE MCGUIRE NUCLEAR STATION, UNITS 1 AND 2 (TAC NOS. MA2467 AND MA2468)
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By memorandum dated July 29,1998, your office requested assistance in the evaluation of Duke Energy Corporation's (DEC) potentialinappropriate evaluation of compensatory measures pursuant to G'eneric Letter 91-18, Revision 1, *lnformation to Licensees Regarding NRC Inspection Manual Section on Resolution of Degraded and Nonconforming Conditions." The letter identified a specific application involving the control room emergency ventilation system (CREVS), and potential application to other systems at the McGuire site and other DEC unit _j Also, the letter indicated that this issue may be generic to the industr <
The evaluation has been performed by the Plant Systems Branch with support from Technical
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l Specifications Branch, Operator Licensing and Human Performance Branch, Emergency Preparedness and Radiation Protection Branch, and Generic issues and Environmental Projects Branch. The attached staff evaluation concludes that the use of manual compensatory actions is a violation of the technical specification This completes our effort on TIA 98008 and TAC Nos. MA2467 and MA2468 are closed, if you have any questions regarding this review, please contact Frank Rinaldi at (301) 415-144 Docket Nos. 50-369 and 50-370 Attachment: As stated -
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cc w/att: R. Blough, R1 J. Bames, Ril G. Grant, Rill ,
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K. Brockman, BlV
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X NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555 0001
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SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION
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TIA 98008
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- USE OF MANUAL COMPENSATORY ACTIONS ON CONTROL ROOM EMERGENCY l
VENTILATION SYSTEM -
DOCKET NbS. 50-369 AND 50-370
1.0 INTRODUCTION By memorandum dated July 29,1998, from Loren R. Plisco, Director, Division of Reactor
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Projects, Region 11, to John A. Zwolinski, Acting Director, Division of Reactor Projects 1/11, Office
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of Nuclear Reactor Regulation, a Task interface Agreement (TIA-98008) expressed a concem regarding a potentialinappropriate evaluation of compensatory measures pursuant to Generic Letter (GL) 91-18. Revision 1, "information to Licensees Regarding NRC Inspection Manual Section On Resolution of Degraded and Nonconforming Conditions." The letter stated that the specific application involves the control room emergency ventilation system (CREVS) at the McGuire Nuclear Power Plant, and that the concern may apply to other systems at the McGuire Plant and other units owned by the Duke Power Company. The letter also stated that this issue may be generic to the industr ,0 BACKGROUND As described in the July 29 letter, the CREVS at McGuire provides normal and emergency ventilation to the control room, control room area, and switchgear rooms. It includes both the control area ventilation system (VC) and the control area chilled water system (,YC). The design has two independent trains that share common duct work. The design of the VC is such that the maximum radiation dose received by control room personnel under accident conditions is within the limits of General Design Criterion 19 cf Appendix A to Title 10 of the Code of Federal Reoulations NO CFR) Part 50. The safety function is described as an automatic function (actuation on receipt of an engineered safety feature (ESF) signal)in the Updated Final Safety Analysis Report (UFSAR) and in the licensee's design basis documentatio i
' Maintenance and modifications conducted (or proposed) breach (or will breach) the common VC duct work or control room pressurization boundary. Through engineering analysis, the licensee developed a calculation which allows the use of compensatory measures rather than i
declaring both trains of the system inoperable (declaring both trains inoperable would require entry into TS 3.0.3).
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. -2-t This calculation is known as the three-minute-rule. The three-minute-rule is based on the criteria in the dose assumption calculations that no credit is taken for any VC system actuation within the first three minutes of an accident. Therefore, the licensee's position is that three minutes'would~ allow adequate time to seal a given VC system or control room boundary breach and pressurize the control room, thereby ensuring doses to operators would not exceed limit The rule allows the VC system or control room pressure boundary to be breached as long as contingency n enares are in place to ensure that the system can be sealed within three minutes of an ESF actuation. Examples of work performed using this rule include the following:
pulling new cable into the control room, propping open control room doors to allow routing of cables to the reador trip breaker room during rod testing, and performing maintenance on common ventilation duct component i
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3.0 EVALUATION Region 11 concerns center on the 10 CFR Part 50.59 evaluation conducted by the licensee on the compensatory measures. One of the issues for consideration when conducting a 10 CFR 50.59 evaluation is, whether the activity could create the possibility for a matfunction of a different type than any evaluated in the SAR. The compensatory measures in question is the sealing of a given VC system or control room boundary breach. The licensee takes the position that the type of firestop sealant material used is the standard and it is used as permanent sealant for all control room penetrations. As cn added assurance, a backup supply of sealant material will be available at the job site. The licensee concludes that "this compensatory measure does not create the possibility for any new type of malfunction that may hinder the ability of the VC system to pressurize the control room as considered in the SAR."
The problem, as Region il correctly points out, is that manual action would be required to reinstall the seals should control room pressurization be required. The licensee's conclusion 6eglects any potential for malfunction introduced by the manual actio Now, in response to the two specific questions asked in the TI l 1. Does the licensee need to evaluate the impact of the manual compensatory measures on the original degraded condition in its 10 CFR 50.59 review? In other words, does the i licensee need to evaluate the likelihood of a new failure mechanism because the penetration seal will be manually refilled in the first three minutes of an event?
Response:
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In all cases where a licensee proposes a change to the design of the facility (either temporary or permanent) to credit manual operator action in place of automatic actions or to modify
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previously credited manual actions, the licensee is required to evaluate the impact of the proposed change as part of its 10 CFR 50.59 review. Atthough it is possible, it is not expected that many determinations of operability will be successful for manual action in place of i
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With respect to the particular cited McGuire example, it is not appropriate for a licensee to purposefully degrade or create a non-conforming condition and then use a compensatory measure as a means of bypassing Technical Specification Limiting Condition of Operation action statements and associated action times or other license conditions. The staff's position for the use of compensatory measures, as described in GL 91-18, Rev.1 was established as a means for affording licensees the ability to take direct and prudent compensatory measures upon the discovery of a non-conforming or degraded condition to maintain the plant in a safe condition until the non-conforming or degraded condition could be evaluated and corrected. It was not envisioned, nor is it appropriate, that such compensatory actions be used to avoid fulfilment of license conditions or technical specification . Is it permissible for McGuire to use the three-minute-rule for planned breaches of the control room ventilation system or is a Technical Specification change needed?
Response:
The McGuire Technical Specifications (TS) has a surveillance requirement which verifies that either CREVS train can maintain a positive pressure within the control room boundary, if the C, REVS duct work or control room boundary is breached such that the CREVS system cannot achieve and maintain this positive pressure, then this surveillance requirement cannot be met and the appropriate TS actions need to be entered. This would mean entry into TS 3.0.3 when in MODES 1,2,3 or 4 and/or immediate suspension of Core Afterations, and movement of irradiated fuel assemblies when in MODES 5 and 6 or during movement of irradiated fuel assemblies. The Technical Specification Branch (TSB) finds that the three-minute-rule does not provide sufficient time or guaranty that the surveillarice requirement could be performed or that the newly sealed breaches can maintain the boundary positive pressure. Thus, TSB finds that implementation of the three minute rule would be a violation of the McGuire Technical Specification .
The Technical Specification Branch and the Owners Group recognized that the Standard Technical Specifications (STS) were inconsistent with regards to the remedial measures to be taken when breaching various ventilation controlled boundaries. The Owners Group Technical Specification Task Force (TSTF) submitted a generic change to the improved STS (TSTF-287)
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4-which corrects these inconsistencies to allow 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to restore the boundary to OPERABLE status and verify that the subject ventilation system can maintain the specified positive or negative pressure. The staff is currently reviewing the changes proposed in TSTF-287 for inclusion in the STS (NUREG 1430 to 1434). The Technical Specification Branch recommends that the licensee update their technical specifications to incorporate the TSTF-287 changes once approve .0 CONCLUSION Based on the above evaluation the staff concludes that the use of such action like the I compensatory actions on the control room emergency ventilation system is a violation of the technical specifications. Accordingly, the Region should coordinate with the Office of Enforcement to initiate the appropriate enforcement actio .
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