IR 05000369/1999002
| ML20206C064 | |
| Person / Time | |
|---|---|
| Site: | Mcguire, McGuire  |
| Issue date: | 04/23/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20206C048 | List: |
| References | |
| 50-369-99-02, 50-369-99-2, 50-370-99-02, 50-370-99-2, NUDOCS 9904300171 | |
| Download: ML20206C064 (30) | |
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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: 50-369/99-02, 50-370/99-02 Licensee: Duke Energy Corporation Facility: McGuire Nuclear Station, Units 1 and 2 Location: 12700 Hagers Ferry Road Huntersville, NC 28078 Dates: February 14,1999 - March 27,1999 Inspectors: S. Shaeffer, Senior Resident inspector M. Franovich, Resident inspector M. Sykes, Regional Inspector (Sections 04.3, E8.7)
J. Coley, Regional Inspector (Sections M1.2, M8.2)
W. Bearden, Regional inspector (Sections M2.2, M2.3, M3.1, M8.3, E1.2 )
L. Moore, Regional inspector (Sections E1.1, E8.4 - E8.6)
Approved by: C. Ogle, Chief, Projects Branch 1 Division of Reactor Projects x
e Enclosure
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l EXECUTIVE SUMMARY j
McGuire Nuclear Station, Units 1 and 2 NRC Inspection Report 50-369/99-02,50-370/99-02 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covered a six-week period of resident inspections and also
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included regional inspections in the areas of in-service inspection, ice condenser system i maintenance, and engineering modification )
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Operations .
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Plant operations placed appropriate emphasis on preventing recurrence of previous unit shutdown problems. Increased use of peer review and good oversight by a dedicated shutdown senior reactor operator were noted for the Unit 2 end of cycle 12 reft.eling I outage shutdown. (Section O1.1) {
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An operational weakness was identified for poor planning, communication, and !
configuration control (isolation valve not fully closed) of Unit 2 service water system !
valves to support system draining and maintenance activities. The overall risk l significance of the activity was not fully understood or evaluated prior to the I maintenance activity. These problems resulted in a flood event in the Unit 1 auxiliary feed-water pump room with Unit 1 at approximately 100 percent power. (Section 02.1)
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During Unit 2 cold shutdown (Mode 5), operators successfully performed a temporary test to: (1) full flow test containment spray check valve in accordance with Technical Specification surveillance requirements and (2) flush radioactive crud in stagnant water in the suction pipe between the containment sump isolation valve and the suction to the residual heat removal and containment spray pumps. Shutdown risk operating _l experience (Generic Letter 98-02) was appropriately factored into the pre-job brief and !
test procedure to preclude an inadvertent loss of reactor coolant system inventor !
Plant configuration was adequately controlled, communications between the operators '
and test evolution coordinator were clear and effective, and the test was executed in an excellent manner. (Section O4.S
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A non-cited violation was identified for an operator's failure to follow an abnormal operating procedure in response to a plant transient. The plant transient involved a loss j of a vital electrical inverter on February 15,1999. The improper operator action resulted '
in an inadvertent opening of a Unit 1 primary power operated relief valve. (Section 04.2)
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A non-cited violation was identified for failure to maintain pressurizer heatup/cooldown limits within Selected Licensee Commitments and procedurallimits during the Unit 2 shutdown. (Section 04.3)
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A strength was identified for the operations self-assessment program which critiques operator performance following significant plant transients or equipment malfunction Two examples were noted for application of this process during the inspection perio These self-assessments provided timely and comprehensive feedback to operations personnel for improvements in the areas of human performance, procedures, and operator training. (Sections O4.2 and 04.3)
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The licensee's investigation and proposed corrective actions for a failed Agastat time-delay relay that partially controls fuel oil to the 1 A emergency diesel generator was adequate. Operator's identification of the degraded condition through operator rounds ,
and attention-to-detail revealed this degraded diesel generator condition. (Section M2.1) l Maintenance
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Inservice examination activities observed were performed using approved procedures by certified examiners who were skillfulin the use of the test equipment, knowledgeable of the test methods, and who properly recorded and evaluated the inspection results in accordance with the appropriate test procedures. (Section M1.2)
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The erosion / corrosion program correctly identified significant wall thinning in the service !
water discharge piping. (Section M1.2) l
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During a system walkdown, the inspectors ide'itified a blocked drain in the auxiliary ,
building underdrain grid system (groundwates drainage system / flood protection) that I was indicative of a material condition deficien:y. (Section O2.1)
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A non-cited violation was identified for the liceasee's failure to develop and implement adequate corrective actions to prevent the installation and use of unqualified diesel engine cylinder valve springs. This resulted in a repetitive valve spring failure of an l
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unqualified spring on February 23,1999, and degraded the 1 A emergency diesel generator. (Section M2.1)
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No significant material condition problems for the Unit 2 ice condenser were identifie (Section M2.2)
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No problems were identified during observation of ongoing repairs or servicing of ice basket components. (Section M2.3)
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A non-cited licensee identified violation was identified regarding inadequate opening torque testing of lower ico condenser inlet doors. (Section M3.1)
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A review of three ice condenser surveillance and maintenance test pror+dures showed that these procedures were clearly written and met Technical Specifice on requirements. (Section M3.1)
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A non-cited licensee identified violation was identified for failure to perform lower ice condenser flow passage inspections. (Section 08.1)
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Appropriate design controls were implemented for sampled Unit 2 outage modification (Section E1.1)
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Lessons learned from previous modifications on Unit 1 were effectively implemented on l Unit 2 outage modifications. (Section E1.1)
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10 CFR 50.59 safety evaluations for the Final Safety Analysis Report Verification Project identified discrepancies and Unit 2 outage modifications were technically adequat (Section E1.1) ,
. Licensee problem reports involving ice condenser system components, determined that identified concems were appropriately corrected or resolved. Any potential reportable issues were evaluated and an appropriate determination made. (Section E1.2)
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A non-cited violation was identified for failing to maintain minimum electrical separation for redundant safety-related cables in the control area ventilation system as described by applicable design procedures. (Section E1.3)
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A non-cited violation was identified for failure to properly identify divider barrier test coupons on appropriate drawings for storage in the reactor building. (Section E8.1)
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,, Report Details
. Summary of Plant Status Unit 1 Unit 1 operated at approximately 100 percent of licensed thermal power throughout the inspection period. '
< Unit 2 Unit 2 began the inspection period at approximately 95 percent power in a planned power
- coast-dc,wn to support the Unit 2 end of cycle 12 refueling outage. On March 12,1999, the unit was taken off line from approximately 81 percent power to begin the outage it was subsequently cooled down and defueled, where it remained at the end of the inspection perio l. Operations 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-conscious. During this inspection period, the licensee performed a planned shutdown of Unit 2 for the end of cycle 12 refueling outage. The inspectors observed portions of the shutdown, focusing on previous problem areas like control of removing main feedwater pumps from service (sea inspection Report 50-369,370/98-07 for details). Based on the observations and the successful completion of the activities, the
. inspectors concluded that operations had placed appropriate emphasis on preventing
. recurrence of prior problems. Increased use of peer review and good oversight by the dedicated shutdown senior reactor operator (SRO) were noted. Other specific events and noteworthy observations are detailed in the sections which follow, including one operator performance issue involving failure to maintain pressurizer heatup and cooldown limits (see Section O4.3).
102 . Operational Status of Facilities and Equipment O2.1 Flood in the Unit 1 Auxiliary Feedwater (AFW) System Pumo Room
' Inspection Scone (71707)
'The inspectors reviewed the facts and circumstances related to a flood event that
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occurred in the Unit 1 AFW pump room. Operators involved in the event, as well as engineers and other station personnel involved in the followup of the event, were -!
contacted. A limited groundwater system flood protection walkdown was performed to assess visible material condition. The Updated Final Safety Analysis Report (UFSAR),
_ plant drawings, and the plant probabilistic risk assessment (PRA) were reviewe .
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W 2 Observations and Findirgs On March 21,1999, a flood occurred in the McGuire Unit 1 AFW system pump room with Unit 1 at 100 percent power and Unit 2 in Mode 6. The AFW pump room contains both Unit 1 motor driven AFW pumps, the Unit 1 turbine drive AFW pump, and the Unit 1 auxiliary shutdown panel. A drain down of a segment of the Unit 2 service water system (SWS) train A piping was underway to support maintenance on the SWS pump 2A discharge check valve. The SWS was being drained to the Unit 1 A ground water sump, which is located in the Unit 1 AFW pump room. The drainage was not progressing as expected, so an operator was dispatched to ensure boundary isolation valves were fully closed to allow for a complete drain. While attempting to fully close (hand tighten) valve 2RN-16A (SWS Pump 2A suction butterfly valve located in the Unit 1 AFW pump room), the operator unknowingly moved the valve beyond its closed sea This resulted in a large leak path from the suction supply (Lake Norman low level intake)
to the sump. The operator left the room and returned to where the SWS water level was being monitored for the drain evolutio Following the operator's attempt to hand tighten valve 2RN-16A, operators in the control room received a Hi-Hilevel ground water sump A alarm and dispatched another operator to investigate along with the shift work manager (SWM) and another SR Unaware of the source of the leak or the SWS draining activity, the SWM recommended that the control room operators align SWS suction to the standby nuclear service water pond to reduce line pressure since the pond is at a lower elevation than Lake Norma Shortly after this action, operators realized that the source of the flood was from valve 2RN-16A. An operator re-closed this valve to terminate the flood. The entire event
. lasted approximately 40 minutes. The licensee estimated a leak rate between 1,000 and 1,500 gallons per minute (gpm).
The two safety-related sump pumps in the A sump did not match the in-leakage. Each sump pump has a 250 gpm-rated capacity. Subsequently, the sump pumps were submerged and the sump overflowed, resulting in approximately 2 inches of water on the floor of the AFW pump room. The A sump purnps ran for a short time (10 to 20 minutes) while submerged before the motors shorted. Floor drains in the pump room, which drain to a floor drain tank, and the plant's B and C ground water sumps were used to mitigate the flood. The B and C sumps are located elsewhere in the auxiliary building and are interconnected to the A sump through an underdrain syste Sump level was restored and an area clean up was performed. A preliminary review of equipment in the Unit 1 AFW pump room did not reveal any impact to the AFW system or other equipment in the room. The inspectors independently verified that with the exception of the groundwater sump pump motors, there were no visible effects on equipment in the room. A temporary air-operated pump (non-required compensatory measure) was setup in the A sump, a dedicated operator (in contact with the control room) was stationed at the sump, and the two affected sump pump motors were removed for repair. By the end of the inspection period, one motor was returned to servic . l
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The inspectors determined that the operator draining the SWS pipe was not cognizant that the draining path was routed to the A groundwater sump. The pre-job brief did not cover this aspect. In addition, the operator draining the system had to conduct system boundary valve manipulation in different parts of the plant other than the AFW pump room and also monitor water level in the pipe near the subject SWS pump that was also not located in the AFW pump room. Consequently, there was no visual monitoring of the sump input from the draining. The irispectors reviewed the plant PRA, which indicated that internal flood consisted of approximately 1.8 percent of total core damage frequency (CDF) and 3.1% of the internal CDF. However, the inspectors noted that the initiating frequency used generic data and that the initiating frequency may not be consistent with actual plant events since this is the second auxiliary building flood in the last year (see inspection Report 50-369,370/98-09 for fire suppression water flood event). At the end of the inspection period, the licensee was conducting an event investigation and reassessment of the plant PRA with respect to flood On March 25,1999, the inspectors also walked down the B groundwater sump, which is located in the Unit 2 AFW pump room. The water was drained low enough to allow for a visual inspection of the underdrain grid portals that connect the B sump to the A and C sumps. Based on drawing MC-1220-21 (January 4,1972), Reactor Building & Auxiliary Building Groundwater Drainage System, the underdrain system consists of a series of narrow wooden channels imbedded in the plant concrete. These channels were provided to prevent excess hydrostatic loads on plant structures in the event of a service water pipe crack (external to the auxiliary building) resulting in nearly 700 gpm into the underdrain system. In addition, the underdrain system allows for the three groundwater sumps in the auxiliary building to communicate with each other. The inspectors identified that one of eight portals that penetrate the walls of the B groundwater sump was blocked with a polyethylene-type construction material and grout. Another portal had some sediment coming out of the portal, but was not blocked. These NRC observations were conveyed to the licensee and were being evaluated under PIP 0-M99-159 c. Conclusions An operational weakness was identified for poor planning, communication, and configuration control (isolation valve not fully closed) of Unit 2 service water system valves to support system draining and maintenance activities. The overall risk significance of the activity was not fully understood or evaluated prior to the maintenance activity. These problems resulted in a flood event in the Unit 1 auxiliary feedwater pump room with Unit 1 at approximately 100 percent power. During a system walkdown, the inspectors identified a blocked drain in the underdrain grid system (groundwater drainage system / flood protection) that was indicative of a material condition deficiency.
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04 Operator Knowledge and Performance 04.1 Unit 2 Containment Sorav Suction Check Valve Full Flow Test and Residual Heat Removal / Containment Sprav (ND/NS) Line Flush Inspection Scope (71707. 61726. 37551)
The inspectors reviewed procedure Temporary Test (TT)/ 2/A/9100/475, NS Suction Check Valve Full Flow Test and ND/NS Suction Flush, Revision 0, applicable Technical Specifications (TS), and observed a'special pre-job briefing covering the test and contingency actions. The inspectors reviewed the proposed test ano activities in detail with consultation from the NRC's regional senior reactor analyst for PRA insight l
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Operating experience for shutdown risk, including NRC Generic Letter (GL) 98-02, Loss of Reactor Coolant System Inventory and Associated Potential for Loss of Emergency Mitigation Functions While in a Shutdown Condition, were also reviewed. The i inspectors monitored control room activities during the evolution, execution of the subject procedure, and independent verification of plant conditions and parameters using the operator aid computer (OAC) and control room board indication Observations and Findinos On March 17,1999, the licensee performed a special evolution to: (1) satisfy an 18- I month TS surveillance requirement for full flow test of the suCan check valve 2NS-21 l
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and (2) perform radiological crud cleanup of stagnant water between the containment sump valve (2N1-185) and the pipe to the ND and NS pumps. This test was performed during Mode 5 with the primary loops filled. The test procedure and special pre-job briefing for this infrequent evolution were reviewed and approved prior to the actual test i by the Plant Operating Review Committee (PORC).
Operating experience, configuration controlimportance, and prevention of plant work that could create an inadvertent reactor coolant system (RCS) drain down and/or loss of ND were factored into the procedure and the pre-job b.-iefing. Specifically, the inspectors observed that lessons learned from the Wolf Creek plant event, discussed in l GL 98-02, were appropriately incorporated into the test procedure and pre-job brief to minimize the potential for an inadvertent drain down of the RCS. In reviewing the proposed contingency actions for a loss of ND in TT/2/A/9100/475, the inspectors identified steps in the procedure that could not be performed sequentially as implied by the numbering in the procedure. Specifically, power restoration to the ND Train A l suction valve 2ND-19 (which was closed and power removed for the test) from the refueling water storage tank (RWST) could not be opened until the power supply breakers were closed. Power restoration would occur several steps after operators attempt to open 2ND-19 from the control room. The licensee informed the inspectors that it was intended for these steps to be done concurrently as implied in the briefing package. However, in response to the inspectors' observations, the licensee enhanced the procedure by removing the step numbers in the contingency actions and clarified the procedure to note each contingency action to imply concurrent actions. Prior to the test, the test evolution coordinator also clarified this with the operators to note concurrent contingency actions in the event ND was lost during the tes .
The inspectors also observed a pre-job brief of one of two crews who received the briefing. The test evolution coordinator provided clear and detailed in4ormation to the crew regarding the test method, plant shutdown risk, and contingency actions to be used in the event ND was lost with "he plant in this test configuration. The briefing was performed in the control room. However, the inspectors observed that the non-licensed operators were not present for the briefing. These individuals were to receive a l separate briefing. The inspectors considered that this briefing approach did not allow each operator involved in the activities the benefit of questions, answers, and comments ;
during the various briefings since all involved are not present at once. In addition, the location of the briefing offered many distractions and made it difficult to focus on the information being presented. Specifically, control room traffic was high and one of the -
operators in the briefing had to acknowledge several control room alarms. The briefing was *:e disrupted by other individuals who momentarily stepped away to conduct other outage related business. The test evolution coordinator appropriately paused during each interruption and resumed the briefing when allindividuals were present. In addition, an operator in the briefing indicated that she did not receive the just-in-time training for this activity. The inspectors questioned the effectiveness of this training since it was later determined that she did receive the training prior to the outage, but did not recallit. These observations were discussed with operations managemen Using the A train of ND, the operators full-flow tested the NS suction check valve 2NS-21 and simultaneously flushed the suction line between the containment sump valve and i the ND and NS pumps' suction. The A train of ND was isolated from the RCS and configured to provide a test loop. A flow path was established from the RW3T to the ND pump suction via the NS pump suction supply piping and discharged from the ND pump back to the RWST via valve 2ND-35 (ND :,ystem to RWST isolatiN). The A train ND system was isolated from the RCS. Crossties between the trains of ND were isolated to separate the two trains. During the test, the B train of ND was operable (as defined by TS) and in operation to provide decay heat removal from the RCS. The inspectors also verified that two steam generators were available with greater than 12 percent inventory on the narrow range level indication in accordance with TS requirements. All other test prerequisites were also satisfied prior to the test. The Unit 2 work list was reviewed to ensure no scheduled work (i.e., ND valve work) was being performed that could result in a loss of RCS inventory or N During execution of the test, control room traffic was minimized. The inspectors observed deliberate and conscientious decision making. Steps in the procedure requiring double verification were appropriately performed. A third, informal check, was performed by an extra SRO on shift who was monitoring the evolution. Three-way communication and repeat backs were frequently and consistently used. Approximately 30 minutes into the flush, an operator noticed a slight increase in pressurizer level (approximately one percent), requiring an increase in letdown by 5 gpm. Operators suspected leak by closed valve 2NI-173 (ND to RCS cold ieg). Because ND train A was slightly less borated than the primary (several parts per million lower), operations management conservatively terminated the test. The test acceptance criteria for a full flow test were satisfied and an approximate 75 percent dose reduction in the ND/NS suction pipe was accomplishe I~
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6 _ Conclusions During Unit 2 co:d shutdown (Mode 5), operators successfully performed a temporary
- test to: (1) full flow test containment spray check valve in accordance with Technical Specification surveillance requirements and (2) flush radioactive crud in stagnant water in the suction pipe between the containment sump isolation valve and the suction to the residual heat removal and containment spray pumps. Shutdown risk operat:ng experience (Generic Letter 98-02) was appropriately factored into the pre-job brief and test procedure to preclude an inadvertent loss of reactor coolant system inventor Plant configuration was adequately controlled, communications between the operators and test evolution coordinator were clear and effective, and the test was executed in an excellent manne O4.2 Loss of Vital Electrical Inverter 1 EVIC Inspection ScoDe (71707. 40500)
The inspectors performed a post-event review and evaluation of the licensee's self-assessment for the failure of 1EViC inverter. The ir spectors reviewed operator logs, OAC trends, related abnormal procedures (AP), operator training materials, and a self-assessment report which reviewed this issue. Discussions with involved plant operators were also conducte Observations and Findinos On February 15,1999, vital inverter 1 EVIC failed due to blown capacitors in the inverter
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panel. This condition caused an annunciator alarm in the control room (BATT (battery]
EVCC Ground) followed immediately by several other related alarms for affected plant equipment on Unit 1. Channel 3 bistables fed from the 1EVIC inverter were also tripped. Some of the effects on major equipment included RCS letdown isolated, pressurizer heaters de-energized, pressurizer pressure channel 3 failed low (1700 pounds per square inch gauge (psig) bottom scale), and power range nuclear !
instrument N-43 faile In response to the plant conditions, the control room operators performed the immediate actions of the related APs. In addition, a Unit 1 operator promptly switched the control selector switch for the pressurizer pressure control system from channels 3-2 to channels 1-2. This action, which was performed within approximately 11 seconds from the start of the event, caused primary system power operated relief valve (PORV) 1NC-34 to cycle open for approximately 5 seconds. The opening of the PORV was due to an anticipatory signal that a large rate of pressure increase had occurred when the PORV control circuit channel was switched to a channel indicating normal RCS pressur Consequently, a turbine runback of approximately 30 megawatts occurred when the PORV opened and reduced primary pressure to approximately 2150 psig. The RCS pressure reduction lowered the over temperature delta temperature (OTDT) parameter to less than 3 percent of the OTDT setpoint. By design, a turbine runback will occur when the OTDT parameter is within 3 percent of setpoint. The entire transient from the loss of 1 EVIC inverter lasted approximately 80 minutes before power to the affected 120 volt vital bus was restored from its alternate sourc l
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The operator's action of immediately selecting channels 1-2 was not an AP immediate action and should not have been performed in this manner. To preclude such an event, AP/1/A/5500/15, Loss of Vital or Auxiliary Control Power, requires that the pressurizer pressure master controller be placed in manual, the output adjusted to 50 percent, an operable channel selected, and then to return the controller to automatic mod Technical Specification 5.4.1 requires that procedures be established, implemented, and mainta!ned, covering activities (including abnormal procedures) recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Contrary to TS 5.4.1, operators failed to follow the subject AP. 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 1-M99-0936. The inspectors identified this procedural adherence issue as NCV 50-369/99-02-01: Reactor Operator Failure to Follow Procedure During Loss of VitalInverte l Accordmg to the licensee, the pressurizer pressure control selector switch is normally selected to channels 1-2. On the day of the event, the operating crew responding to the event had channels 3-2 selected. The switch was placed in this position by the previous shift due to surveillance activities and this switch position was communicated to the on-coming shift. The licensee indicated that there was no required position for normal channel alignment. The licensee discovered that simulator scenarios are typically run with channels 1-2 selected. In addition, the specific steps of AP/1/A/5500/15 for setup of the pressurizer pressure control had been previously incorporated into the procedure based on operating experience from another plant. Numerous recommendations for improvements in operator performance, including additional training for this scenario, AP changes, and simulator fidelity were identified in operations self-assessment (SA) 99-04 (PIP 1-M99-0936). The inspectors considered the licensee's SA was performed in accordance with the recently implemented Operation Management Procedure (OMP) 9-7, Post Event Assessment, Revision 1 (June 10,1998). It was comprehensive in scope and depth of assessment of operator actions, quality of procedures used, and plant equipment response during the even c. Conclusions A NCV was identified for an operator's failure to follow an abnormal operating procedure in response to a Unit 1 transient. The plant transient involved a loss of a vital electrical inverter on February 15,1999. The improper operator action resulted in an inadvertent opening of a Unit 1 primary power operated relief valve. The licensee's post-event review performed under operations self-assessment program provided timely and comprehensive feedback to operations personnel for im >rovements in the areas of i human performance, procedures, and operator traininr;.
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04.3 Noncomoliance with Selected Licensee Commitment (SLC) 16.15-3.4.9.2-Pressurizer Inspection Scope (71707. 40500)
The inspectors reviewed and evaluated licensee actions in response to the licensee's failure to comply with SLC and administrative limits for RCS heatup and cooldown during the scheduled shutdown for refuelin Observations and Findinos On March 13,1999, during preparation for a Unit 2 refueling outage, the licensee exceeded administrative cooldown limits and SLC heatup limits for the RCS while taking Unit 2 to cold shutt'own (Mode 5) in accordance with plant shutdown procedure The licensee was in the process of reducing RCS system temperature and pressur Three of four reactor coolant pumps were in operation. Tha B reactor coolant pump had been secured due to elevated motor bearing temperatures. With the B loop idle, ,
operators had difficulty controlling pressure since the B loop spray capability was adversely affected. Because of the complications in controlling pressurizer pressure, the licensee opted to increase the cooldown rate by increasing pressurizer level and securing a second reactor coolant pump in order to establish shutdown cooling. The reduction in forced coolant flow and reactor coolant loop pressure significantly impacted pressurizer spray capability. To compensate for the loss of spray capability, operators reduced the number of pressurizer heaters in service and continued to increase pressurizer level. During this time, the lack of spray flow and minimal pressurizer heater operation resulted in stratification of the pressurizer water. The continued insurge of makeup water resulted in the licensee exceeding the established administrative cooldown limit in Procedure PT/2/A/4600/09, Surveillance Requirements for Unit Shutdown, of 150 degrees F within an hour. However, SLC 16.15-3.4.9.2 limit of 200 degrees F within an hour was not exceede In response to the rapid cooldown, control room operators energized all available pressurizer heaters and aligned low pressure auxiliary pressurizer spray to the pressurizer from the residual heat removal systems. The increase in pressurizer spray coupled with the maximum heat input resulted in a rapid pressurizer water temperature increase, which when averaged over 60 minutes exceeded the SLC limit of 100 degrees F within an hour. These operator actions were contrary to maintaining pressurizer limits noted in Procedure PT/2/A/4600/09. The licensee's failure to control the evolution in accordance with SLC and procedural requirements is a violation of TS 5.4.1, Administrative Controls. This Severity Level IV violation will be treated as a NCV, I consistent with Appendix C of the NRC Enforcement Policy. This violation is in the l licensee's corrective action program as PIPS 2-M99-1152,2-M99-1149. It will be identified as NCV 50-369,370/99 02-02: Failure to Maintain Pressurizer Heatup/Cooldown Limits During Reactor Shutdow l McGuire Operations management initiated a self-assessment in accordance with OMF l 9-7, Post Event Assessment. As a result, comprehensive and detailed ;
recommendations were developed. The inspectors reviewed the assessment, finding it
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to be comprehensive with the provided suggested areas for improvement being appropriat _C_onclusions The inspectors concluded that control room operators were unprepared for the Unit 2 cooldown to residual heat removal entry and failed to make necessary adjustments when pressurizer pressure control complications were encountered. The operators ,
continued to focus on each problem individually rather than taking the time to assess plant conditions and obtain additional guidance prior to increasing the cooldown rat A non-cited violation was identified for failure to control pressurizer heatup and cooldown in accordance with Selected Licensee Commitments and procedural requirement Miscellaneous Operations issues (92901,90712)
08.1 (Closed) Licensee Event Report (LER) 50-369/98-006: Noncompliance with ice Condenser Technical Specification Surveillance Requirement 4.6.5.1. On August 12,1998, the licensee determined that surveillance requirements for ice condenser ice bed operability had been improperly interpreted and had not been performed in accordance with TS requirements. The requirement involved the applicability of certain areas in the lower ice condermer for flow passage surveillance verification. The licensee immediately declared the Unit 1 and Unit 2 ice condensers'
ice beds inoperable. The licensee also notified the NRC of the noncompliance and requested enforcement discretion. The request was reviewed by the staff and granted on August 13,1998. The licensee also submitted a TS amendment request to clearly establish the TS surveillance requirements, and the failure to conduct this surveillance as required is a violation of TS Surveillance Requirement 4.6.5.1.b.3. 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 0-M98-2794 and will be identified as NOV 50-369,370/99-02-03: Failure to Complete Ice Condenser Surveillance for Lower Turning Vanes. Based en this review, both the subject LER and Notice of Enforcement Discretion 98-6-014 are closed, ll. Maintenance -
M1 Conduct of Maintenar.ce M1.1 General Comments Inspection Scope (61726. t'2707)
The inspectors reviewed a variety of maintenance and/or surveillance activities during the inspection period, includit g the following specific items:
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PT/1/A/4350/002,1 A D/G [ Diesel Generator) Operability Test ,
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PT/1/A/4208/001 B,18 NS Pump Test l
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MP/0/A/7650/143, Receipt, inspection and Storage of Framatome Cogema Fuel New Fuel
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PT/0/A/4150/35, inspection and Storage of New Fuel
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WO#98135879 - Replacement of EDG 1 A Valve Spring
. TT/2/A/9100/475, NS Suction Check Valve Full Flow Test and ND/NS Suction J Flush 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 l
l The inspectors concluded that the reviewed routine maintenance and sutveillance I activities were adequately complete M1.2 Inservice insoection (ISI)- Observation of Work Activities l Inspection Scope. Unit 2 (73753) l The inspectors observed four ISI ultrasonic and two magnetic particle nondestructive examination (NDE) welds to evaluate the effectiveness of ISI procedures; examiners'
skill, knowledge and thoroughness in their performance; and interpretation or evaluation and acceptance of the test results. Examinations observed were as follows:
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NI-2F-543 (Ultrasonic Examination)
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NI-2F-527 (Ultrasonic Examination)
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2CA-FW44-1 (Ultrasonic and Magnetic Particle Examinations)
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2CF-FW46-1 (Ultrasonic and Magnetic Particle Examinations)
in addition to the above examinations, documentation was reviewed which included the ISI outage scan plan, ISI procedures, examiner certifications, radiographs for nuclear piping welds, and ultrasonic examination results and evaluation Observations and Findinas The Code of Record for the second 10-year ISI interval for Unit 2 is the 1989 Edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI, Division 1. However, in a letter dated August 4,1995, an alternative examination qualification to the requirements of the 1989 Edition of the ASME Boiler and Pressure Vessel Code,Section XI was proposed. The licensee requested approval
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for the implementation of the alternative examination qualification techniques in the 1992 Edition with the 1993 Addenda of ASME Section XI, Appendix Vill, Supplements 2 and 3. This relief was approved by NRC in a letter dated September 12,1995, and was applicable to the examination of all Examination Category B-J, C-F-1, and C-F-2 similar metal piping welds that require volumetric examination. The inspectors concluded that the ISI and NDE examination activities observed were performed in a skillful manne Discontinuities were properly recorded, interpreted, evaluated, and dispositioned by knowledgeable examiners using approved procedures. Radiographic film for weld No NS-1-16,17, and 2-NS-3-19,20 revealed
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that film technique and weld quality were very goo Review of the erosion / corrosion program revealed that ultrasonic thickness examinations had not found any piping that would require replacement during the end-of-cycle (EOC) 12 outage. During discussions with the erosion / corrosion engineer and subsequent review of PIP 0-M99-0329 the inspectors were informed that ultrasonic wall thinning inspections for the service water corrosion program identified significant wall thinning in the 12 inches of exposed 36-inch diameter service water discharge piping downstream of valve ORN149A. Minimum wall for this piping is 0.393 inch and 133 of 516 one-inch grids were below minimum wall. Most readings averaged 0.250 inch thick, but a few were as thin as 0.074 inch. The thinning was characterized as pittin Subsequent ultrasonic examinations revealed that both trains of the exposed service water discharge piping are experiencing similar wall thinning. Pipe wall thinning examinations for the supply portions of the service water piping did not reveal similar I degradation. Although not confirmed by analysis, the licensee concluded that the f
corrosion was apparently caused by a combination of biological / oxidation degradation I related to long term exposure to the pond environment. Structuralintegrity calculation MCC-1206.02-84-2021, Revision D55 stated that the wall thinning identified was acceptable. The licensee was reviewing alternative methods for repair of the exposed piping and inspection of the buried discharge pipin Conclusions
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Inservice examination activities observed were performed in a skillful manne Discontinuities were properly recorded and evaluated by knowledgeable examiners using approved procedure The erosion / corrosion program correctly identified significant wall thinning in the senrice water discharge pipin M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Emeroency Diese! Generator (EDG) Performance issues Inspection ScoDe (62707. 37551. 40500)
The inspectors reviewed the conditions related to: (1) a repetitive failure of EDG valve springs and (2) a failed time delay relay for engine fuel oil control (starting air solenoids).
The inspectors reviewed the licensee's extent of condition investigation and licensee
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actions to assure reliability of the EDGs. The inspectors observed selected portions of corrective diesel maintenance and post-maintenance EDG operability runs for the spring failure issu l Observations and Findinos Valve Sprina Failure On February 23,1999, a broken inlet valve spring was discovered on EDG 1 A, cylinder 6R. The broken spring condition was detected by review of diagnostic data taken during I an EDG surveillance, in particular, lower than normal exhaust temperature and I increased peak firing pressure. The licensee removed the failed spring and a ;
i subsequent metallurgical examination indicated that the spring failure was the result of l deficient material specification of the valve springs. This failed valve spring was installed by the licensee during corrective maintenance in June 1998, to address a June )
4,1998, broken exhaust valve spring failure. The June 4,1998 spring failure was '
discovered on the EDG 2A, cylinder 4L exhaust valve outer spring. (See inspection l Report 50-369,370/98-07 for details.) l
in both cases, the failures involved an outer valve spring and the licensee's metallurgical j exam indicated an unqualified material was used. Specifically, the subject springs' j material composition was consistent with American Society for Testing and Materials I (ASTM) A229, which did not include appropriate amounts of silicon, vanadium, and chromium. These alloys were added to improve the fatigue strength of the spring Following the June 4,1998, spring failure, the licensee replaced all the outer springs on all four station EDGs since they suspected that other unqualified springs may have been installed during the vendor's (NAK Engineering) rebuild of the heads during the 1997 refueling outages for each unit. The licensee believed, at the time, that all the outer springs were replaced with original Nordberg springs during the June 1998 corrective i maintenance. Original Nordberg springs are of a high-quality steel consistent with
) material specification American iron and Steel Institute (AISI) 6150. During the !
corrective maintenance in June 1998, NAK Engineering returned to McGuire most of the ;
original springs that were replaced during the 1997 rebuild; however, some of the springs had been resold by the vendor. To make up the difference, the licensee used other springs on-site to replace the springs on four of the EDG 1 A cylinder heads. The I four cylinder heads (SR,6R,7R, and 8R) were the last four worked during the 100 l percent spring change-out in June 199 In response to the February 23,1999, spring failure, the licensee inspected all of the EDG 1 A outer springs using in-situ dimensional checks. The original Nordberg springs were approximately 0.490 inches spring wire diameter. Acceptable substitute springs have wire diameter of greater than or equal to 0.500 inches and may be comprised of AISI 6150 type material or ASTM A401 type material. The unqualified springs comprised of ASTM A229 material, also have a wire diametcr of 0.500 inches or greater. Cylinders 1L through 8L, and 1R through 4R were confirmed to be original Nordberg springs. The inspectors reviewed the data, which revealed that the l
dimensions for these springs were below 0.500 inches. However, the licensee determined that cylinders SR through 8R had a mixed population of springs, comprised l
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13 of Nordberg originals, A401 type, and A229 type (determined by metallurgical exam).
Two A229 springs were identified and both were located on the 6R head (the one that failed plus the exhaust valve outer spring). At the end of the inspection period, the licensee was investigating the root cause of the problem and how these unqualified springs were installed by maintenance personnel in June 199 ;
The inspectors identified a violation of 10 CFR Part 50, Appendix B requirements.
Specifically,10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires that in the case of significant conditions adverse to quality, that measures shall assure that the condition is determined and corrective actions taken to preclude repetition. Sufficient i measures were not taken in June 1998 to assure that only qualified springs were used '
l on EDG 1 A, as evidenced by the recent spring failure. 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 1 M99-0832. The issue is identified as NCV 50-369,370/99-02-04: Inadequate Corrective Actions for l Emergency Diesel Generator Valve Spring Failur '
On or about February 25,1999, the licensee replaced all outer springs on cylinders 5R through 8R with A401 type material. Spectrography was used to confirm the chemical composition of the new springs. Cylinder 8L outer valve springs were also changed to A401 type springs because the initial dimension checks indicated diameters slightly below 0.500 inches in lieu of the expected 0.490 for original springs. The metallurgical lab later provided a more precise measurement that was closer to 0.490 inches. The j
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inspectors verified that the spectrography of the A401 replacement springs demonstrated that appropriate levels of fatigue strengthening materials were present. A post-maintenance run was performed and the EDG was returned to operable status on February 25,1999. Dimensional checks were performed on the Unit 2 EDGs and verified that original springs were used in the June 1998,100 percent spring change-out. Additional measures in progress included an inventory check of springs in the warehouse, material confirmation, and final determination of the root cause of the problem.
In addition, the inspectors noted that the licensee's response to Violation 50-369,370/98-07-07 indicafed that all of the outer springs had been replaced with originals. This was incorrect and the licensee subsequently corrected the response by letter dated March 23,1999.
Startino Air Solenoid Valves During the inspection period, operators discovered an additional degraded condition of EDG 1 A. During operator rounds on February 28,1999, an operator noticed that the EDG 1 A battery charger amps were indicating below normal. The licensee declared the EDG inoperable. During troubleshooting, the licensee discovered that an Agastat time delay relay that controls one of two control air solenoids (1VGSV5160 and 1VGSV5161)
for engine fuel rack position had failed. Normally, the solenoids are de-energized (i.e.
fuel rack in the shutoff position) with the diesel in standby mode. This defective relay was replaced within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of discovery of the EDG degraded condition. Plant engineering informed the inspectors that the auto and manual start functions of the EDG
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l f 14 were not affected since only one of two solenoids need to be energized and vented to start the diesel by starting relays. The inspectors verified this through a review of plant drawing Metallurgical results indicated that the pneumatic timer in the relay was affected by l microscopic paint chips that collected over time in a subcomponent. These paint chips
! appeared to have collected from accumulated shavings from painted components which l are rotated during timer calibration. The failure was the first of this type for an Agastat l relay identified at McGuire. The defective Agastat relay was relatively new (1993). The licensee had contacted the vendor to determine if the subcomponents in question should have had a paint coating and if a 10 CFR Part 21 notification should be issue Operator's continued semi-daily rounds of diesel generator battery charger checks for this condition. The licensee indicated that these relays were targeted for potential replacement, and addressed this Agastat relay issue through PIP 1-M99-089 Conclusions l A NCV was identified for the licensee's failure to develop and implement adequate corrective actions to prevent the installation and use of unqualified diesel engine cylinder valve springs. This resulted in a repetitive valve spring failure of an unqualified spring that occurred on February 23,1999, and degraded the 1 A emergency diesel generato The licensee's investigation and proposed corrective actions for a failed Agastat time-delay relay that partially controls fuel oil to the 1 A emergency diesel generator was adequate. Operator's identification of the degraded condition through operator rounds and attention-to-detail revealed this degraded diesel generator conditio M2.2 Ice Condenser (IC) - Material Condition (Unit 2) Inspection Scope (62707)
The inspectors observed and evaluated the adequacy of material condition of IC equipment. Areas observed included the upper blankets, upper plenum, and lower plenum. During this inspection, ongoing work activities observed included ice basket servicing, basket repairs, and basket inspections. As-found conditions were evaluated with respect to TS, the UFSAR, design criteria, and applicable licensee drawings and procedure Observations and Findinos Ice Baskets Some minor damage to the top rings on a small number of ice baskets was noted during the inspection of the Unit 2 upper plenum. This damage was attributed to the licensee's previous use of certain tools used to free-up frozen or stuck baskets and was not considered as significan '
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! The inspectors noted that ongoing weighing of the baskets was performed in
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accordance with Procedure MP/0/A/7150/005," Ice Basket Weight Determination,"
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Revision 5. This procedure requires the use of a calibrated load cell assembly which utilized a hydraulic jack, a digital readout unit and a lifting bridge. The procedure also requires that prior to weighing, ice baskets be checked to determine if they are frozen or ;
stuck. Stuck ice baskets that can not be freed are emptied with the aid of vibrators, i inspected, repaired as needed, replenished with ice, and weighed. This weight is subsequently documented and becomes a part of the computer database progra MP/0/A/7150/005 limits the lifting force (i.e.,3000 pounds maximum) that can be applied i to raise and free stuck ice baskets. This limitation was imposed for the purpose of !
minimizing basket damag I The inspector observed the condition of baskets which had been emptied for servicin )
This observation was performed with the aid of lights and a video camera. No !
significant damage was noted in any of those basket . Lower Plenurn During the tour of the Unit 2 lower IC plenum, the inspectors noted a potential interference problem with one of the lower doors for Bay 23 due to valve 2-NF-138 The assigned system engineer agreed that a potential interference problem existed and PIP 2-M99-1403 was issued to resolve this issue. Subsequent operational testing of the j affected lower inlet door showed that there had been no actual interference proble l No other concerns were noted in the lower IC plenu Uoper Deck B!ankets i
The inspectors observed the Unit 2 upper deck blankets for adequacy of material condition. The inspectors noted that each section of radial tape was contained at the j blanket hinge end with clips to assure that the tape was retained during a design basis I event. Sections of circumferential sections of tape at the outer wall had been applied properly. In addition, the blankets were in good material conditio i Conclusions No significant material condition problems for the Unit 210 were identified.
M2.3 Servicina of Ice Baskets Inspection Scope (62707)
The inspectors determined by work observation the adequacy of inspection procedures and work practices for inspection, servicing, and repairing ice basket component Observations and Findinos The inspectors observed work in progress which included vibration of ice to unload baskets, minor basket repairs, visual inspections and remote inspections with the aid of a video camera. The inspectors noted that ongoing ice basket work activities were performed in accordance with Procedure SM/0/A/8510/007," Ice Basket Corrective
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Maintenance and Tracking," Revision 5. No problems were identified during observations of ongoing servicing / repairing ice basket component Conclusion No problems were identified during observations of ongoing repairs or servicing of ice basket component M3 Maintenance Procedure and Documentation M3.1 Review of Surveillance and Maintenance Test Procedures Inspection Scope (61726)
The inspectors reviewed selected Unit 2 surveiilance and maintenance test procedures to assure that they conformed to TS requirements. This review included procedures used by the licensee for TS Surveillance Requirements (SR) 4.6.5.1.b.2 and 4.6.5. The following procedures were included in the review process:
SM/0/A/8510/002, " Ice Basket inspection," Revision 2
MP/0/A/7150/076, " Ice Basket Weight Determination," Revision 5
SM/0/A/8510/007," Ice Basket Corrective Maintenance and Tracking,"
Revision 5 Observations and Findinas The procedures reviewed were clearly written and met TS requirements. Additionally, the inspectors reviewed PlP 0-M99-1034, which documented a TS violation for SR 3.6.13.6 for torque testing of lower IC inlet doors. Periodic Test Procedure, PT/0/A/4200/032," Periodic Inspection of Ice Condenser Lower inlet Doors," Revision 4, had not adequately implemented SR 3.6.13.6 requirements. The SR Bases required that the IC lower doors opening force at 40 degrees open be less than or equal to 195 inch pounds. The licensee had been accomplishing this by placing a spring scale at a point 27 inches from the hinge axis of the door with an established acceptance criteria of 7.22 pounds to satisfy this requirement. However, the acceptance criteris cpecified in PT/0/A/4200/032 had been rounded upward in a non-conservative direction to 7.25 pounds. The licensee was preparing to issue LER 50-369/99-01 to address this issu The licensee reviewed the as-found inlet door torque values for the last two outage periods for both units. The licensee verified that the most recent as-left values for all lower inlet doors during the most recent outage for each unit had not exceeded 7.22 lb However, the as left values for two Unit 1 doors tested during the previous May 1997 outage had 'rceeded the required acceptance criteria. One lower inlet door from Bay 2 had a value ; 8.0 lbs and one lower inlet door from Bay 20 had a value of 7.5 lbs. The failure to adequately test the lower inlet doors is a violation of TS SR 3.6.13.6. This ,
Severity Level IV Violation is being treated as a NCV consistent with Appendix C of the l NRC Enforcement Policy. This violation is in the licensee's corrective action program as l l
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i PIP 0-M99-1034. This is identified as NCV 50-369/99-02-05: Inadequate Opening !
Torque Testing of Lower Ice Condenser inlet Doors . I Conclusions A review of three IC surveillance and maintenance test procedures showed that these procedures were clearly written and met TS requirements. One NCV for an inadequate surveillance test instruction was identifie M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Violation (VIO) 50-369/98-02-01: Failure to Follow and/or inadequate Procedures for Unit 1 Containment isolation Valve Maintenance This violation involved two examples involving either a failure to follow applicable procedures or inadequate procedures used for maintenance activities on containment ,
isolation valves. The inspectors reviewed the licensee's response to the violation along with the detailed reviews previously performed in inspectir.n Report 50-369,370/98-0 Procedural problems for maintenance activities associat9d with the main feedwater isolation valves were corrected and the specific hyocric valves have been replaced with a different type of actuator on both units. For the second example involving a failure to follow applicable procedures during the reassembly of containment purge isolation valves, the inspectors concluded that the identified corrective actions appeared -
adequate the prevent recurrence of the issue. The inspectors noted that the licensee clarified the wording of the violation associated with the containment purge inlet valves in their response dated May 6,1998, and did not have any concems. This violation is .
close M8.2 (Closed) VIO 50-370/9.7-15-01: Failure to Follow Eddy Current Analysis Guidelines This item identified the licensee's failure to evaluate an indication in tube R7C60 of Steam Generator 2 during the 10* Unit 2 refueling outage in April 1996. The inspector verified the implementation of the licensee's corrective actions as stated in their letter of response dated November 19,1997, and concluded that the actions taken were sufficient to prevent recurrence. This item is close !
M8.3 . (Closed) IFl 50-369/98-11-01: Ice Condenser insulation Effect on ECCS Sump i
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l This' item had been opened pending review of licensee's evaluation of the potential
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contribution of damaged insulation on small bore glycol piping toward plugging of the emergency core cooling system (ECCS) sump. The inspectors reviewed PlP 1-M98- i 1644 which had evaluated debris in the Unit 1 1C. This issue had been evaluated by the ;
licensee who determined that the amount of insulation which could potentially contribute toward plugging of the ECCS sump was very small and well below existing criteri Additionally, the licensee scheduled removal and/or replacement of the affected
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insulation on both units during the next available outages. The inspectors noted that Work Order (WO) 98075433 had been issued for implementation of this on the Unit 2 IC j
! during the ongoing outage. This item is close Ill. Enaineerin_g E1 Conduct of Engineering l E Review of Desian Chanaes and Plant Modifications and 10 CFR 50.59 Evaluations Scope (37550.37001)
- The inspector reviewed nuclear station modifications (NSMs) implemented during the current Unit 2 outage. Elements of the design process reviewed included post-modification testing, procurement, implementing procedures and work instructions,10 CFR 50.59 safety evaluations and screenings, and field verification of plant hardware changes as applicable. Additionally,10 CFR 50.59 safety evaluations were reviewed for UFSAR discrepancies identified by the licensee's UFSAR verification process. The l following NSMs were reviewed
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NSM-MG-22515, Addition of Automatic Recirculating Valves on Unit 2 Auxiliary ,
Feed Pumps !
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NSM-MG-22482, Replace Unit 2 EDG Battery Chargers
. NSM-MG-22505, Main Feed Isolation Valve Replacement ;
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NSM-MG-22509, Replace NV Pump Cold Leg Isolation Valves 2NIMV009A and 2NIMV0010B Observations and Findinas The licensee implemented several safety significant modifications during the outage to provide irrprovements in system and plant performance or replace obsolete '
components.- The level of detail in the design change packages and implementing work instructions was adequate for proper installation and testing of the modification Lessons learned from previous modifications on Unit 1 were effectively implemented on the Unit 2 modifications. In particular, the main feed isolation valve replacement modification used a different design to improve the control solenoid valve reliabilit The 10 CFR 50.59 safety evaluations for UFSAR discrepancies identified by the UFSAR verification project and for the Unit 2 modifications were technically adequate and consistent with regulatory requirements and plant procedures, Conclusions Appropriate design controls were implemented for the Unit 2 outage modification Post-modification testing performed and scheduled was adequate to verify equipment
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and system function following the modification.10 CFR 50.59 safety evaluations reviewed were technically adequate and consistent with regulatory requirement E Reportabilitv/ Operability Evaluations (Units 1 and 2) Inspection Scope (40500)
i The inspectors determined through t%cument review the adequacy of the licensee's evaluations with regards to items concerning reportability and operability issues relative to the I Observations and Findinas l
The licensee used the PIP program to document concerns identified in the field, including those associated with material condition and documentation errors. Under this system, concerns were assessed, evaluated for plant operability and reportability to the NRC (i.e.,10 CFR 50.73 and 10 CFR 21), and appropriately corrected or resolve Issues with potential operability or reportability concerns were evaluated, and a ;
determination was made and documented using PIPS. The inspectors reviewed 17 PIPS issued for both McGuire units between June 1,1998, and the present that addressed problems associated with IC equipment and prc edures, for the purpose of verifying that reportability and operability issues were adequately evaluated and whether appropriate actions were taken as required. The inspectors noted that only a relatively small population of the reviewed PIPS actually involved issues that would qualify as potential reportability candidate Through this review, the inspectors determined that the findings as documented in 15 PIPS did not meet the reportability threshold of either 10 CFR 50.73 or 10 CFR 2 However, in two instances evaluations determined that the problems identified were reportable (i.e., PIPS 0-M98-2794 and 0-M99-1034) and the licensee performed detailed evaluations for operability and reportability requirements, and appropriately reported or had taken steps to report the issues to the NRC. In all cases, the licensee's completed current operability and reportability reviews were considered acceptabl Conclusions The inspectors' review of PIPS involving IC system components, determined that the concerns were appropriately corrected or resolved. Any potential reportable issues were evaluated and an appropriate determination made by licensee personne E1.3 Control Room Safetv-Related Ventilation Eauioment Not Meetino Separation Criteria Insoection Scope (71707) !
The inspectors conducted routine tours of the safety-related areas adjacent to the control room. The inspectors compared as found electrical cable train separation with site procedure DC-1.01, Design Criteri i 20 Observations and Findinos On March 2,1999, the inspectors identified that control area ventilation system redundant safety-related cables 1-VC512 and 1-VC514 did not meet the established electrical separation requirements as described in site procedure DC-1.01, Design Criteria. The two subject cables are the supply lead to Unit 1 intake path isolation valves 1VC2A and 1VC48. The established minimum separation was 12 inches, whereas the as-found separation was less than 6 inches.10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality be described by procedures and followed in accordance with the established procedures. Contrary to this requirement, minimum safety-related cable separation distance was not maintained between power cables for valves 1VC2A and 1VC4B. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV), consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as PIP 0-M99-0677. The inspectors verified that the licensee had corrected the condition prior to the end of the inspection period. This issue is identified as NCV 50-369/99-02-06:
Failure to Maintain Electric Cable Separation Criteria, Conclusions The NRC identified a NCV for failing to maintain minimum electrical separation as described by applicable design procedure E8 Miscellaneous Engineering issues (92903)
E (Closed) Unresolved item (URI) 50-369/98-07-02: Divider Barrier Patches Left in Containment Following Outage This issue involved the inspectors identification of rubber divider barrier seal test coupons identified in the lower Unit 1 reactor building during shutdown condition Through the resolution of PlP 1-M98-2534, the licensee confirmed that the subject .
materials were older divider barrier coupons moved to the vestibule location during the l end of cycle 7 refueling outage. At that time, new coupons were installed close to the actual seal locations and the older coupons were moved to the current location in the vestibule. The licensee performed an evaluation of the potential adverse impact of the material on the function of the containment sump following a loss of coolant accident and concluded that sump performance would not have been impacted. The inspectors concluded that the sump impact evaluation was reasonable, as the material was !
demonstrated to sink and potential for transport to the sump was low. However, the l inspectors also identified that applicable site drawings did not reflect either the old or the j new coupon storage locations within the Unit 1 reactor building. In addition, the new .
coupon locations were also not depicted as being installed in the Unit 2 containment.10 l CFR Part 50, Appendix B, Criterion V, instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be described by documented instructions, procedures, or drawings. Contrary to this requirement, both the old and the new divider barrier test coupons were not shown on applicable drawings. 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 1-M98-2534,
which indicated that the affected drawings were subsequently corrected. It will be identified as NCV 369,370/99-02-07: Failure to Identify Divider Barrier Coupons on Applicable Drawing E8.2 (Closed) IFl 50-369.370/97-20-01: Operation With Elevated Refueling Water Storage Tank (RWST) Temperatures !
This issue involved the inspectors questioning whether previous operating practices of allowing the RWST temperature to be near the TS limit of 100 degrees Fahrenheit (F).
Specifically, the inspectors noted that elevated ambient temperatures raised the control l room indicated RWST temperatures to the 98 to 99 degrees F range prior to the i operators taking action to reduce the temperature via a recirculation flowpath cooled by the containment spray heat exchanger. The inspectors noted that the RWST temperature sensors were located near the bottom of the tank. Given this sensor location, the inspectors were concerned that excessive thermal stratification could cause the bulk average RWST temperature to exceed the TS value. The licensee initiated PlP 0-M97-4682 to resolve the issu The licensee developed a method to determine if excessive tank stratification was occurring during the summer months of 1998 by taking external measurements on the outside of the tank. However, the licensee later determined that the measurements were not taken on the actual shell of the tank, but rather on an outer insulating barrier and thus were unusable. The licensee then took more reliable data by allowing the tank to potentially stratify for sometime during high ambient temperatures and then recirculating the tank without any additional cooling source. This test indicated that the bulk average temperature raised between 1 and 2 degrees F after the contents were thoroughly mixed. The inspectors reviewed RWST design basis information and the results of the test with engineering personnel. Based on the presented test values for potential thermal stratification and a lack of information related to actual past bulk average temperatures, the inspectors could not identify any specific instances when either unit's RWST bulk average temperature definitively exceeded the established TS values. However, the inspectors also concluded that past practices may have challenged the TS limit due to its close proximity to the upper TS limi The inspectors noted that the safety analysis limit used to define the uniform temperature for the tank fluid for a small break loss of coolant accident analysis was 120 degrees F and for the large break accident was 105 degrees F, both of which provided a margin to the TS limit of 100 degrees F. To prevent any future challenges to the 100 degrees F TS limit, the inspector verified that the licensee took actions to modify operating procedures to begin recirculation and cooling of the RWST contents at 95 degrees F. The inspectors also verified that the licensee had clarified large break loss of coolant accident initial conditions for the RWST temperature values as identified in Chapter 15.6 of the UFSAR. The inspectors noted incomplete documentation in the subject PIP in that the full details of the final resolution were ad included. This observation was discussed with the licensee at the exit interview. This item is closed.
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22 E8.3 (Closed) Acoarent Violation (EEI) 50-369.370/97-16-02: Failure to implement Effective Corrective Actions to Prevent Ice Condenser Lower inlet Door Binding This was one of two Eels involving the 10 inoperable lower inlet ice condenser doors for Unit 2 that were discovered in July 1997. The doors became blocked because of door floor growth and upheaval that raised door frame flashing. The door frame flashing interfered with door operation. By letter dated October 8,1997, the first eel (97-16-01)
was closed and a violation was issued (Enforcement Action 97-398) for failure to satisfy the requirements of TS 3/4.6.5.3. This letter also withdrew eel 97-16-02 based on information presented during the pre-decisional enforcement conference held on October 1,1997. Therefore, this eel is closed.
E8.4 (Closed) VIO 50-369.370/98-07-07: Inadequate Vendor Oversight of EDG Refurbishment, Two Examples The licensee's response to the violation dated September 4,1998, listed corrective actions to replace all EDG springs with acceptable material and improve vendor controls to increase the oversight of the responsible vendor. The corrective actions were documented in PIP 1-M98-1761. The inspector reviewed documentation which verified the stated corrective actions were complete. An exception was the replacement of all springs with appropriate material. During surveillance testing and diagnostic review of the 1 A EDG on February 23,1999, indications were identified of an additional broken spring. Further investigation by the licensee determined that the broken and c ne additional spring were of the deficient material quality which had not been replaced consistent with the corrective actions stated in the violation response. PIP 1-M99-0832 was initiated to address this issue. This issue is discussed in Section M2.1. This item is closed.
E8.5 (Closed) IFl 50-369.370/98-06-01. Root Cause and Corrective Actions for Failure of the 1 A EDG Cylinder 6R Exhaust Valve Seat :
This item was initiated to follow up the licensee's analysis and corrective actions for the EDG sub-component failure which occurred on May 19,1998. The NRC reviewed the i
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licensee's analysis and corrective actions in June 1998, as documented in NRC Inspection Report 50-269,270/98-07. The review included the metallurgical report, root cause report, corrective actions and previous licensee audits of the vendor, NAK Engineering. The evaluations and corrective actions were documented in PIP 1-M98-1522. The corrective actions were completed on March 17,1999. This item is closed.
E8.6 (Closed) VIO 50-369.370/97-18-03: Inadequate Design Controls for RWST Setpoint Calculation The licensee's corrective actions stated in the violation response dated February 10, 1998, included correcting the calculation and training to stress the importance of the independent review function. The corrective actions were completed on August 24, 1998, and documented in PIP 0-M98-1774.- This item is closed.
E8.7 (Closed) IFl 50-369.370/98-07-01: Unexpected Relay Actuation During Unit 1 Loss of Offsite Power The inspectors reviewed and evaluated licensee's actions to correct potential relay coordination issues identified as a result of a Unit 1 loss of both offsite buslines on
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June 3,1998. At the time of this event, both Unit 1 essential busses were being supplied from Unit The inspectors reviewed the licensee's action plans established following the event to I prevent similar loss of busline events and also reviewed recommendations developed by I'
a licensee event investigation team to address unexpected relay and breaker actuation The inspectors discussed the corrective actions with licensee personnel and reviewed completed documentation outlining the necessary actions to identify the cause for the l
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unexpected breaker actuation. The inspectors noted that although no definitive root cause for the unexpected breaker actuation was identified, the licensee's investigative team and station personnel had developed and implemented appropriate corrective actions to minimize the potential for recurrence.1 herefore, this IFl is close W. Plant Suooort R1 Radiological Protection and Chemistry Controls )
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R General Comments (71750)
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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 l in the respective area I V. Manacement Meetinos X1 Exit Meeting Summary The resident inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on April 9,1999. 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., 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
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24 INSPECTION PROCEDURES USED IP 37001: 10 CFR 50.59 Safety Evaluation Program IP 37550: Engineering IP 37551: Onsite Engineering IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 62707: Maintenance Observations IP 61726: Surveillance Observations IP 71707: Conduct of Operations
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' IP 71750: Plant Support IP 73753: Inservice Inspection IP 90712: Event Reports IP 92901: Followup - Operations IP 92902: Followup - Maintenance IP 92903: Followup - Engineering IP 92904: Followup - Plant Support ITEMS OPENED AND CLOSED OPENED 50-369/99-02-01 NCV Reactor Operator Failure to Follow Procedure During Loss of Vital Inverter (Section 04.2)
50-370/99-02-02- NCV Failure to Maintain Pressurizer Heatup/Cooldown Limits During Reactor Shutdown (Section 04.3)
50-369,370/99-02-03 NCV Failure to Complete Ice Condenser Surveillance for Lower Turning Vanes (Section 08.1)
50-369,370/99-02-04 NCV inadequate Corrective Action for Diesel Generator Spring Failures (Section M2.1)
50-369/99-02-05 NCV Inadequate Opening Torque Testing of Lower Ice Condenser inlet Doors (Section M3.1)
50-369/99-02-06 NCV Failure to Maintain Electric Cable Separation Criteria (Section E1.3)
50-369,370/99-02-07 NCV Failure to identify Divider Barrier Coupons on Applicable Drawings (Section E8.1)
CLOSED 50-369/98-06-00 LER Noncompliance with ice Condenser Technical Specification Surveillance Requirement 4.6.5.1. (Section 08.1)
50-369/98-02-01 VIO Failure to Follow and/or inadequate Procedures for Unit 1 Containment isolation Valve Maintenance I
(Section M8.1)
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50-370/97-15-01 VIO Failure to Follow Eddy Current Analysis Guidelines (Section M8.2)
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50-396/98-11-01 IFl ice Condenser insulation Effect on ECCS Sump f Operability (Section M8.3)
50-369/98-07-02 URI Divider Barrier Patches Left in Containment j Following Outage (Section E8.1) l 50-369,370/97-20-01 IFl ' Operation With Elevated Refueling Water Storage ;
Tank (RWST) Temperatures (Section E8.2)
50-369,370/97-16-02 eel Failure to implement Effective Corrective Actions to Prevent Ice Condenser Lower inlet Door Binding (Section E8.3)
50-369,370/98-07-07 VIO Inadequate Vendor Oversight of EDG Refurbishment, Two Examples (Section E8.4)
50-369,370/98-06-01 IFl Root Cause and Corrective Actions for Failure of the 1 A EDG Cylinder 6R Exhaust Valve Seat (Section E8.5)
50,369,370/97-18-03 VIO Inadequate Design Controls for RWST Setpoint Calculation (Section E8.6)
50,369,370/98-07-01 IFl Unexpected Relay Actuation During Unit 1 Loss of Offsite Power (Section E8.7)
American Iron and Steel institute AP -
Abnormal Procedure ASME -
American Society of Mechanical Engineers ASTM -
American Society for Testing and Materials CDF -
Core Damage Frequency CFR -
Code of Federal Regulations EDG -
Emergency Diesel Generator eel -
Apparent Violation F -
Fahrenheit GL -
Generic Letter GPM -
Gallons Per Minute IFl -
Inspector Followup Item IC -
Ice Condenser IR -
Inspection Report
ISI -
Inservice inspection LER -
Licensee Event Report LTOP -
Low Temperature Overpressure Protection MNS -
McGuire Nuclear Station ND -
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NDE -
Nondestructive Examination NCV -
Non-Cited Violation NRC -
Nuclear Regulatory Commission NRR -
NRC Office of Nuclear Reactor Regu;ation NS -
Containment Spray NSD -
Nuclear Site Directive NSM -
Nuclear Station Modifications NSRB -
Nuclear Safety Review Board OAC -
Operator Aid Computer OMP -
Operation Management Procedure OTDT -
Over Temperature Delta Temperature PDR -
Public Document Room PIP -
Problem investigation Process PORC -
Plant Operating Review Committee PORV -
Power Operated Relief Valve PRA -
Probabilistic Risk Assessment PSIG -
Pounds Per Square Inch Gauge PT -
Periodic Testing RCA -
Radiologically Controlled Area RCS -
Residual Heal Removal l RP -
Radiation Protection i RWST Refueling Water Storage Tank '%
SA -
Self Assessment SLC -
Selected Licensee Commitments SR -
Surveillance Requirement SRO -
Senior Reactor Operator SWM -
Shift Work Manager SWS -
Service Water System TS -
Technical Specifications TT -
Temporary Test UFSAR -
Updated Final Safety Analysis Report WO Work Order
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