IR 05000369/1997017

Insp Repts 50-369/97-17 & 50-370/97-17 on 970921-1101.No Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20203A213
Person / Time
Site:	McGuire, Mcguire
Issue date:	12/01/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20203A187	List: IR 05000369/1997017 ML20203A182
References
50-369-97-17, 50-370-97-17, NUDOCS 9712120043
Download: ML20203A213 (34)

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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: 50-369/97-17, 50-370/97-17 Licensee: Duke Energy Corporation Facility: McGuire Generating Station. Units 1 and 2 Location: 12700 Hagers Ferry Road Huntersville. NC 28078-8985 Dates: September 21 - November 1. 1997 Inspectors: S. Shaeffer. Senior Resident Inspector M. Sykes Resident Inspector M. Franovich. Resident Inspector R. Chou. Regional Inspector (Sections El.1 and El.2)

N. Economos. Regional Inspector (Sections M4.1 through M4.3)

Approved by: C. Ogle. Chief. Projects Branch 1 Division of Reactor Projects

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Enclosure 9712120043 971201 PDR ADOCK 05000369 i G PM ,

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EXECUTIVE SUMMARY l

McGuire Generating Station. Units 1 and 2 NRC Inspection Report 50-369/97-17, 50-370/97-17 l This integrated inspection included aspects of licensee operation l maintenance, engineering, and plant support. The report covered a six-week period of resident inspection. In addition, it included the results of two

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regional inspections specifically reviewing the Unit 2 steam generator replacement projec Ooerations

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In general, the conouct of operations was professional and safety conscious. (Section 01.1)

. The inspectors concluded that the licensee reported a potential non-conservatism in a Technical Specification in accordance with the requirements of 10 CFR 50.72. The administrative limits established to compensate for the potential non conservatism in Technical

Specifications appeared to be adequate. (Section 01.2)

• General material condition and housekeeping of the Unit 2 ice condenser system ap3 eared good. Observed Unit 2 maintenance activities were being accomplis 1ed with established procedures. The licensee's evaluation and monitoring of Unit 1 ice bed temperature anomalies and floor temperature alarm were adequate. (Section 02.1)

. The licensee took prudent actions to develop procedures specifically for the loss of auxiliary feedwater recirculation capability. The inspectors reviewed the procedures and concluded that adequate guidance was incorporated to respond to events where auxiliary feedwater recirculation capability may be lost. (Section 03.1)

. The inspectors concluded that operators maintained adequate focus during the Unit 2 shutdown and responded appropriately to equipment malfunctions during the evolution. A failure of a rod control system component resulted in additional burden on operators during this

, critical plant evolutio Licensee management was aware of the repetitive nature of the problem and had taken some prior actions to focus additional resources on the problem. (Section 04.1)

. The licensee provided adequate training for station personnel and maintained good command and control during core offload. No problems were identified during the core offload evolution, which was indicative of excellent personnel and equipment performance. Good oversight of generic spent fuel pool storage issues was apparent. (Section 04.2)

. The inspectors concluded that the mispositioning of the non-safety Auxiliary Feedwater Condensate Storage Tank supply system was repetitive in nature, indicated operator inattention to detail, and that the licensee's evaluations of a similar 1995 problem and the 1997 problem with the alignment of supply valves could h6ve been more rigorou The inspectors concluded that this condition had the potential for

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diverting operator focus and resources away from other complicacions that could arise during an event: thereby. challenging overall operator respons (Section 04.3)

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The licensee was currently conducting an extensive review of the safety to non-safety interface of the auxiliary feedwater system, focusing on system design and operator required actions. In addition, the licensee was preparing to perform a root cause assessment of their latest component mispositioning data to contir2e to improve in this are (Section 04.3)

. With regard to the identification of an overpower condition, the operators continue to exhibit a good questioning attitude and good attention to plant operating conditions. Overall, the licensee continues to exhibit heightened awareness to reactivity events and has a low threshold for classifying these type events as significant for root cause analyses to be performe (Section 04.4)

Maintenance

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In general, monitored maintenance and testing activities were completed satisfactoril Overall control of testing activities was good and indicative of management oversigh (Section M1.1)

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The licensee's planned maintenance evolution for the 2B emergency diesel generator was well implemented. Foreign material exclusion controls during the activities provided adequate protection for the open configuration of the engine. The subsequent surveillance testing activities performed were adequate to ensure equipment operabilit (Section M2.1)

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Licensee actions in response to a potentially degraded auxiliary feedwater condition were acceptable. Reducing the acceptance criteria for vent flow in order to eliminate an immediate concern was acceptabl The inspectors also concluded that any further reduction in continuous vent flow rates could challenge the auxiliary feecWater system during a standby shutdown system event ana heightened monitoring and timely corrective actions were warranted to prevent future inoperability of these component (Section M2.2)

. Minor Modification MM-8410 to replace certain isolation drain valves and

?.ssociated piping in the reactor coolant system crossover pipe was being performed following applicable code recuirements. Prefabricated subassemblies and field welds exhibitec good workmanship attributes and material records were retrievable and in order. Quality Control inspections and visual examinations were performed as require Engineering evaluations and input were appropriate. (Section M4.1)

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Welder performance qualifications were consistent with code requirements and were being closely monitored by cognizant licensee personnel. The weld filler metal control program was well organized and capable of supporting steam generator replacement project welding. (Section M4.2)

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. Volumetric and surface inservice inspection of designated welds were performed satisfactorily by qualified and well trained personnel following approved non-destructive examination procedure (Section M4.2)

• The steam generator replacement project was progressing well within the licensee's pre-established timetable. Cutting activities followed approved procedures and were closely monitored. Lifts of heavy components were well planned and implemented in a safe manne (Section M4.3)

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Housekeeping arour.d the steam generator re]lacement work project work area showed significant improvement over t7e two previous Duke facility steam generator replacement projects. (Section M4.3)

• The inspectors confirmed through observation of 3roject activities and discussions with licensee representatives that t1e steam generator replacement project organization was effective in adequately planning and safely executing the Unit 2 : team generator replacement project effort. (Section M6.1)

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The licensee's development of a special test in response to NRC concerns to assure operability of the interior fire suncression loop piping was goo However, initial test performance probins did not allow for valid data to be taken. The problems identified indicated that some fire suppression equipment may have limited preventive maintenance being performe (Section M8.1)

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The required lifting plan, path, load tests, and lifting equipment inspections generated or performed for the safe lifting and transfer operations of the old and new steam generators were adequate. One weakness and one Non-Cited Violation were identified for qualified crane o?erators not signing and dating in the procedures for the steps which t1ey performed, and for performing procedure steps out of sequenc (Section El.1)

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The licensee performed adequate preparations, supporting calculations, and had acceptable drawings and other documents to ensure the installation of the new short segment of guard pipe during the steam generator replacement project. An Inspector Followup Item was identified for a clarification of load and moment sign transformation application from Unit 1 to Unit 2. (Section E1.2)

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Communications between engineering and operations regarding anticipated spent fuel pool temperatures when isolating one spent fuel cooling pump were not effective. Adjustments to the required surveillance monitoring of the pool may also have been beneficial during periods of anticipated temperature increases, particularly when associated computer alarm points were unavailable. (Section E4.1)

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An Inspector Followup Item was identified concerning a potentially non-conservative Technical Specification for the hydrogen mitigation system may exist and that insufficient information was available to determine adequacy of the current Technical Specification. No immediate safety or operability issues existed since plant procedures required testing all installed igniter (Section E4.2)

Plant Suonort

. An October 1.1997, emergency preparedness drill adequately demonstrated the set objectives with two exceptions Appropriate focus was being applied to these exception areas to improve future performance. The licensee's conservative timing of the drill and continued aggressive drill schedule were identified as area strengths. (Section P5,1)

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An Inspector Follow up Item was identified concerning potential problems involving multiple security guards not accurately performing vehicle accountability searches. (Section S4.1)

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Reoort Detai h Summary of Plant Status Unit 1 Unit 1 operated at approximately 100 percent power during the inspection perio Unit 2 Unit 2 began the inspection period at approximately 100 percent power. On October 3. the unit was shutdown in a controlled manner to facilitate the end-of-cycle 11 refueling outage. The outage also included replacement of the Unit 2 steam gcnerators. The licensee com31eted offloading of the reactor core to the Unit 2 spent fuel pool on Octo)er 12. The unit remained defueled for the remainder of the inspection period. At the end of the period, the licensee had accomplished safe disassembly and removal of all the old steam generators and haJ begun installing the new steam generators within the containmen Review of Uodated Final Safety Analysis Reoort (UFSAR) Commitments While performing inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that were related to the areas inspecte The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures, and parameter Ooerations 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: specific events and noteworthy observations are detailed in the sections belo .2 10 CFR 50.72 Notifications Insoection Scope During the inspection period, the licensee made one notification to the NRC. The inspectors reviewed the notification issue for impact on the operational status of the facility and equipmen Observations and Findinos On October 23, 1997, the licensee made a four-hour, non-emergency notification to the NRC in accordance with 10 CFR 50. a requirements concerning potential non-conservativism within a Technical Specification (TS) power versus flow prohibited operation area.

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While reviewing the basis for TS 3/4.2.5. Departure from Nucleate Boiling. (DNB) parameters, a potential non-conservativism was identified by the licensee for reactor power operation with less than 382.000 gallons per minute (ppm) flow. At the time of the notification. Unit 1 was operating at approximately 100 percent power with reactor coolant s system (RCS) flow greater than 382.000 gallons and Unit 2 was defuele In these operating concitions there were no constraints imposed on operation of either unit as a result of this identified potential non-conservatis The licensee established administrative controls to take appropriate operator actions (ie reduce reactor power) if RCS flow parameters went below 382.000 gpm. At the end of the inspection period, the licensee was continuing to evaluate this issue and identifying appropriate actions to adjust the TS as required. The licensee indicated their intention to submit a Licensee Event Report (LER) on the subjec c. Conclusiorg The inspectors concluded that the licensee reported a potential non-conservatism in TS in accordance with the requirements of 10 CFR 50.7 The administrative limits established to compensate for the potential non conservatism in TS appeared to be adequat Operational Status of Facilities and Equipment 0 Ice Condenser System Goerability a. Insoection Scooe (71707. 62707)

The inspectors evaluated the material condition and maintenance activities of the Unit 2 ice condenser system (ICS) and reviewed operational issues with the Unit 1 ICS. During the Unit 2 outage the inspectors also walked down the ICS to examine its overall condition and followup on a recent event involving mechanical hinding of the lower inlet doors (previously discussed in inspection Report 50-369.370/97-16).

b. Observations and Findinas During outage ice making operations for Unit 2 the Unit 1 ice condenser average ice bed temperatures started to trend upwards at a slow rate of approximately 0.4 degrees Fahrenheit per day. Normally. the averge ice

, bed temperatures are typically in the mid-teens (degrees Fahrenheit).

At the same time. floor cooling indication alarmed in the control roo The overall ice bed temperature increase was attributed by the licensee to two conditions. First chillers for Unit 1 operations were diverted to Unit 2 for ice making operations and second. normal cooling water temperatures had increased due to a temperature inversion in the Lake Norman cooling supply. The licensee diverted chillers back to Unit 1 service to recover ice condenser temperatures. At no time did the average ice bed temperature challenge TS requirements. The floor cooling alarm was attributed to a temperature setpoint drift in the

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3 temperature indicator for the alar The floor cooling system was not affected since this indicator has no control function for the floor cooling syste The inspectors performed a walkdown of the Unit 2 ICS during ongoing maintenance activities, including ice basket settling and refill operation The inspectors examined the floor for foreign material and identified two metal plates that were too large for the vacuum system to pickup. The inspectors questioned ICS technicians to establish the type and magnitude of debris collected through vacuuming ice and cleaning of the waste ice removal system. Technicians responded that minor amounts of debris which were collected in the waste system were composed mostly of tape and materials used during outage ice condenser servicing. The inspectors discussed with licensee management the im)ortance of inspecting vacuumed debris to ensure no evidence of 3roken ICS components were overlooked (for example, sheet metal screws). The P

inspectors also examined the floor for signs of deterioratio Superficial mechanical damage to ohe wear slab was noted from previous maintenance activities such as scraping of floor ice, c. Conclusions General material condition and housekeeping of the Unit 2 ICS appeared good. Observed Unit 2 maintenance activities were being accomplished with established procedures. The licensee's evaluation and operational monitoring of the Unit 1 ice bed temperature anomalies and floor temperature alarm were adequat Operations Procedure and Documentation 03.1 Loss of Auxiliary Feedwater (AFW) Recirculation Caoability Insoection Scoce (71707)

The inspectors evaluated the licensee's actions to correct procedural deficiencies identified following the September 6.1997, dual unit reactor tri Observations and Findinas During the dual unit trip that occurred on September 6.1997, the operators lost Unit 1 AFW recirculation capability due to the recirculation valves failing closed upon de-energization of the KXA power supply. The loss of recirculation capability was not immediately recognized by control room operators during the event and was also not recognized during the post-trip review (see Inspection Report 50-369.370/97-15). In an effort to provide additional guidance to operators, the licensee developed and a3 proved Procedures AP/1/A/5500/05 and AP/2/A/5500/05. Loss of Unit 1 and Jnit 2 Auxiliary Feedwater Recirculation Capability. These procedures identify symptoms associated with a loss of AFW recirculation capability and provide instructions on how to control AFW flow when the AFW miniflow valves are not available

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to ensure pump minimum flow requirements are me The newly developed procedures also provided requirements on motor-driven pump starting / duty cycles and turbine-driven pump startin Additional guidance for turbine-driven pump operation was also provided for locally resetting turbine trip throttle valve c. Conclusions The inspectors concluded that the licensee *s action to develop procedures specifically for the loss of AFW recirculation capability was prudent. The inspectors reviewed the procedures and concluded that adequate guidance was incorporated to respond to events where AFW recirculation capability may be los Operator Knowledge and Performance 04.1 Shutdown For Unit 2 End-0f-Cycle 11 (2E0C11) Outaae Insoection Scoce (71707)

The inspectors reviewed and evaluated the shutdown of Unit 2 to Mode 3 for the 2EOC11 steam generator replacement and refueling outage. The inspectors focused on activities that could impact nuclear and personnel safety to verify that licensee controls were sufficien b. Observations and Findinas On October 2. 1997, control room operators began a controlled shutdown of Unit 2 in accordance with Procedure OP/2/A/6100/02. Controlling Procedure for Unit Shutdown. The inspectors reviewed scheduled work activities to confirm that the licensee performed adequate risk evaluations of shutdown activities prior to the outage and monitored the shutdown activitie During shutdown load reduction, the operators recognized that rods failed to respond with a Taverage (Tavg) and Treference (Tref) error of approximately +2.2 degrees Fahernheit. Control rod response was expected at a temperature error of 1.5 degrees Faherenheit. The operators halted the load decrease and took manual rod control in accordance with Procedure AP/2/A/5500/14 Rod Control Malfunction to correct the temperature error. Maintenance personnel were contacted to evaluate the reactor control system malfunction. The licensee continued the controlled shutdown with rod control in manual. Operators brought Unit 2 to hode 3 (Hot Shutdown) on October 3, 1997, at 4:16 The licensee conducted an evaluation of the reactor control system failure. The licensee identified a short circuit trip condition at a 7300 control card as the ap)arent cause. The failed card prevented inward control rod motion w1ile rods were in automatic. The card was replaced and tested to verify operability. The inspectors verified that the failure of the 7300 control card did not prevent manual operation of

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the control rods and would not have prevented control rod insertion due to a manual or automatic reactor trip signa The inspectors performed a review of similar events and confirmed that a similar card failure occurred on January 20, 1997, preventing automatic control rod operation during a Unit 2 load reduction following the loss of the Unit 2 isolated phase bus cooling fans. Although the control card failures experienced have not affected safe shutdown of the uni additional operator effort was necessary to complete the load reductions. The inspectors recognize tnat although the affected portion of the rod control system is not safety-related. operators rely upon the system to operate properly during routine and abnormal load change The inspectors reviewed the McGuire UFSAR and confirmed that no credit was taken in UFSAR accident analyses for the rod control syste Conclusions The inspectors concluded that operators maintained adequate focus during the Unit 2 shutdown and responded appropriately to equipment malfunctions during the evolution. The inspectors noted that the failure of a rod control system component resulted in a burden on operators during this critical plant evolutio Licensee management was aware of the repetitive nature of the problem and had taken some prior actions to focus additional resources on the proble .2 Unit 2 Core Offload Insoection Scooe (71707)

The inspectors reviewed the licensee's reactor core offloading plans to verify adequate training of fuel handling personnel. Spent fuel pool (SFP) criticality management was also evaluated. Recently discovered boraflex degradation of the Unit 2 spent fuel racks was also evaluated to confirm no potential adverse impact on spent fuel loading was experience Observations and Findinas The inspectors reviewed training documents and established procedures and verified that the fuel handling senior reactor operator (FHSRO) was responsible for direct supervision of core alterations and was expected to have no concurrent responsibilities. The documents adequately emphasized that reactivity additions or core alterations were not allowed without the direct supervision of the FHSRO. Additionally, the inspectors observed that the FHSRO was actively in charge of the fuel handling bridge during core alterations. During the evolution, there were no indications of fuel damage, unexpected reactivity changes or

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changes in refueling or spent fuel pool water levels. Control rod shuffling and control rod drag testing were also successfully performed in the spent fuel pool without incident. The inspectors also 3eriodically reviewed plant parameters and other requirements stipulated

)y the TS refueling section, Operators were actively monitoring all TS related parameter No non-compliances were identifie Prior to fuel movement, the licensee increased SFP boron concentration in accordance with the core operating limits report and the TS for refueling operations. Boric acid was added directly to the SFP by dumping boron through a funnel and chute. Appropriate attention was 1 applied to ensure adequate mixing in the pool and to minimize introduction of foreign material. To ensure k,rr would be less than or equal to 0.95 more conservative limits were imposed for unrestricted storage of fuel in Region 1 of the SFP than required by TS Table 3.9- Minimum Qualifying Burnup Versus Initial Enrichment for Unrestricted Region 1 Storage. These administrative limits were generated to account for degraded boraflex material in the spent fuel racks. However, the fuel discharged from the reactor to Region 1 of the pool was significantly less reactive than the limits for Region 1 unrestricted storage. Spent fuel pool water clarity and lighting were adequate to support fuel movemen Conclusions The inspectors concluded that the licensee provided adequate training for station personnel and maintained good command and control during core offload. No problems were identified during the core offload evolution, whicn was indicative of excellent personnel and equipment performance. Good oversight of generic spent fuel pool storage issues was apparent.

. 04.3 Valves Miscositioned in the Auxiliary Feedwater System Insoection Scooe (71707. 40500)

The inspectors reviewed the facts and circumstances related to auxiliary feedwater condensate storage tanks (AFWCSTs) supply valves being discovered in the wrong with station personnel, positio reviewed The inspectors the AFW discussed operating procedure, theand issues also performed field verification and evaluation of the equipment. The inspectors reviewed the event as part of a continuing followup on the licensee's efforts to reduce the rate of plant system misposition r Obgr_vations and Findinas On September 23, 1997, the licensee discovered that two nonsafety-related su) ply vaives (ICA157 and 1CA158) were open and supplying the AFWCSTs. w1en only one valve should have been ope Valve 1CA157

]rovides a makeup oath from the Unit I condenser hotwell pump discharge leader and valve ICA158 provides makeup from the Unit 2 condenser hotwell pump discharge. Normally, one valve is open and limited by

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procedure to be throttled to pass no more than 100 gp Plant personnel discovered ICA157 was open to pass 100 gpm and 1CA158 was open fully, with a flow through the valve of approximately 120 g)m. According to the licensee, this configuration occurred between t1e time of the dual unit reactor trip that occurred on September 6, 1997, and the discovery date of September 23, 199 During the dual unit trip, in response to decreasing levels in the AFWCSTs. the control room SRO dispatched an o?erator to the valves to investigate and to increase makeup to the tancs. According to the

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licensee's Problem Investigation Process (PIP) 0-M97-3474, the operator went to Unit 1 and misread the sight glass flow element as reading no flow and therefore believed valve ICA157 was closed. Poor lighting, location, and condition of the flow element apparently contributed to this error. The operator then proceeded to Unit 2 with the mindset that Unit 2 was supplying flow to the AFWCSTs. Valve ICA158 was found open and set to deliver 100 gpm. The operator then fully opened valve ICA158 to approximately 120 gpm. The caerator did not fill out a configuration control card (CCC) to document t7e new position of ICA15 The inspectors discussed the following issues with operations management. The inspectors were concerned that CCC cards were not used and, more importantly.-that 1CA158 was opened-beyond the procedural limit of 100 gpm. as specified in Procedure 1/0P/A/6250/02. Revision 6 Auxiliary Feedwater Syste )erations management responded that operators have been reminded tlat valve position is controlled by procedure, the repair and restoration process, or CCCs. It was also the responsibility of the individual who manipulates a valve to fill out g CCC Based on the discussions. it appeared that the control room SRO directed the operator to exceed the 100 gpm limit. The inspectors considered that this problem may have been the result of unclear expectations or communications. The licensee initially investigated these procedure adherence issues and determined that, although inappropriate. the limits provided in the operating procedure were not overly restrictive. One of the immediate corrective actions was for an engineering review of the flow limits. This determined that a revision to the AFW operating procedure could be made to increase the flow limit to 120 gpm without detrimen The inspectors identified two additional human factors related observations that may have contributed to the misposition. A review of the operating procedure for valve alignment revealed that both valves have a Unit 1 prefix (i.e. . ICA157 and ICA158) although one supply path was from the Unit 2 condenser hotwell. This condition could mislead operators to believe that only one unit was replenishing the AFWCST Also, scaffolding for the 1CA158 was positioned to access the valve but not to easily read the associated flow elemen The inspectors also reviewed a previous configuration issue involving 1CA157 and 1CA15 In 1995. following a Unit 1 reactor trip, a control room SRO dispatched an operator to investigate decreasing AFWCST level during the event (note: there was only one AFWCST at that time). The

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operator identified that both valves were closed and proceeded to open one valve to deliver 50 gpm (the procedural limit at that time). PIP 0-M95-0357 was written and dispositioned as a potential valve misposition. 9 The licensee concluded that one valve must have been open prior to the event or the level in the AFWCST would have decreased from the water draining through idle AFW pumps, through the recirculation lines, and returned to the upper surge tanks, which are under a vacuum. No engineering analysis was presented in the PIP to support this conclusio ~The inspectors were aware that the licensee was conducting an extensive review of the safety to non safety interface of the AFW system, focusing on system design and operator required actions. In addition, the licensee was preparing to perform a root cause assessment of their latest component mispositioning data to continue to improve in this are Conclusions The inspectors concluded that the mispositioning of the non-safety auxiliary feedwater condensate storage tank supply system was repetitive in nature, indicated operator inattention to detail, and that the licensee's evaluations of a similar 1995 problem and the 1997 problem-with the alignment of supply valves could have been more rigorou The inspectors concluded that this condition had the potential for diverting operator focus and resources away from other complications that could arise during an event: thereby, challenging overall operator response. The licensee is conducting an extensive auxiliary feedwater system interface review and preparing to perform a root cause review of this latest mispositionin .4 M C. tor Overoower Condition Insoection Scooe (71707)

The inspectors reviewed the facts and circumstances related to an overpower condition that occurred on Unit Observations and Findinos On October 15. 1997, operators noticed Unit 1 reactor power was exceeding 100 percent of rated thermal power. Reactor power was approximately 100.11 3ercent for c P iod of 4 minutes and 12 second Operators reduced tur3ine power by 1 negawatt to compensat A review of plant information revealed that secondary steam pressure had decreased before the event, the pressurizer level had also some minor fluctuations, and Tavg decreased a small amount. The licensee determined that some steam drains did cycle during this time but were not considered to be the root cause of the steam pressure decrease. The licensee classified this as a potential significant problem and was continuing the performance of a root cause analysis. Preliminary

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results were focusing on governor valve position control or possible grid fluctuation as contributing factors to the steam pressure decreas Conclusions The inspectors concluded that the operators continue to exhibit a good questioning attitude and good attention to 31 ant operating condition Overall, the licensee continues to exhibit leightened awareness to reactivity events and has a low threshold for classifying these type events as significant for root cause analyses to be performe Miscellaneous Operations Issues (92901)

0 (Closed) LER 50-369/96-07: Mcde Related Missed TS Surveillance on Containment Integrity Due to a Technical Inaccuracy

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(This item was previously reviewed as Non-Cited Violation 50-369/96 10 02.) The inspectors evaluated the licensee's planned and completed actions identified in the LER. The inspectors confirmed that the licensee had immediately revised the procedure to included the proper surveillance frequency for the shutdown containment integrity verification and provided additional guidance to guard against subsequent inadequate reviews of mode related surveillances. The licensee also developed a Quality Improvement Team to review the event and identify necessary changes to the process. The team completed the review, identifying areas for improvement and initiated revisions to correct the deficiencies identified by the team. This item is close I Maintenance M1 Conduct of Maintendnce M1.1 General Comments (61726 and 62707) Insoection Scoce The inspectors reviewed all or portions of the following work activities:

PT/2/B/4350/02B 2B Emergency Diesel Generator Operability Test PT/1/A/4200/08 Auxiliary Feedwater Suction Pipe Venting PT/2/A/4209/12A Centrifugal Charging Pump 2A Head Curve Performance Test PT/2/A/4206/15A Safety injection Pump Head 2A Curve Performance Test

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10 Observations and Findinos The inspectors witnessed selected surveillance tests to verify that approved procedures were available and in use, test equipment in use was calibrated, test prerequisites were met system restoration was completed, and acceptance criteria were met, in addition, the inspectors reviewed and witnessed routine maintenance activities to verify where applicable, that approved procedures were available and in use, prerequisites were met, equipment restoration was completed, and maintenance results were adequat Conclusion The inspectors concluded that these and other monitored activities were completed satisfactorily. Overall control of testing activities was good and indicative of involved management oversigh H2 Status of Haintenance Facilities and Equipment M2.1 2B Emeraency Diesel Genernor (EDG) Overhaul Inspection Scone (62707)

'lhe inspectors observed 2B EDG preventive maintenance activities to evaluate preventative maintenance activities and diesel engine condition as a result of an extensive engine overhau Observations and Findinos The inspectors conducted routine observations of EDG maintenance activities and held discussions with licensee personnel to evaluate maintenance activities. The consplete overhaul of the unit was the first complete rebuild for the engine. The licensee disassembled the diesel engine and evaluated critical component conditions. Magnetic particle inspection of equipment was performed to identify indications in cylinder liners and pistons, as well as the crankshaft and bearing The licensee discovered minor component wear; however. no major concerns were identified. Wear indications were noted at the first idler gear, indicative of abrasives in the diesel engine lube oil system. The licensee was aware that lube oil contamination had occurred previously when abrasives were introduced into the lube oil system years befor The idler gear indications did not cause engine performance degradation, yet the licensee opted to replace the idler gear to ensure engine reliabilit The licensee did not identify any significant piston, crankshaft, or camshaft wear. The licensee also identified minor abrasions on the main bearings, hany components were replaced, including cylinder liners and most rubber items. The engine was reassembled and tested. The inspectors periodically reviewed maintenance activities in progress and inspected the as found condition of the components. No specific problem were noted.

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The licensee performed the TS 4.8.1.1.2e required 24-hour diesel run arior to the unit overhaul in accordance with Procedure PT/2/A/4350/36 )/G (Diesel Generator) 28 24-Hour Run. The testing was completed satisfactorily. Following the overhaul, the licensee completed manufacturer recommended break-in runs and a 12-hour hot soak run. The licensee confirmed component conditions (hot bearing deflection) were within acceptance limits. Technical Specification 4.1.1.2 required operability testing was performed and the unit was returned to servic c. Conclusion The inspectors concluded that the licensee's planned maintenance evolution for the 2B EDG was well implemented. Foreign material exclusion controls during the activities provided adequate protection for the open configuration of the engine. The subsequent surveillance testing activities performed were adequate to ensure equipment operabilit M2.2 Flow 't uction d Throuch Nuclear Service Water Vent line a. Insnec 4;tScooe (62707)

The inspectors reviewed licensee actions to resolve items identified during quarterly venting of the auxiliary feedwater system suction pipin b. Observations and Findinas On October 31. during performance of Procedure PT/1/A/4200/08. Auxiliary Feedwater Suction Pipe Venting, the flow acceptance criteria of 3 gpm through 1RN1066 (the standby shutdown system nuclear service water supply to auxiliary feedwater continuous vent) was not met. The licensee determined the flow rate as 1.2 gpm. The Standby Shutdown _

System (SSS) was designed to respond to fire or sabotage events utilizing the turbine driven auxiliary feedwater (TDAFW) pump as the relied upon heat removal pump during SSS events. The nuclear service water system is the safety-related assured suction source for the AFW System. The continuous vents were established at various high point locations to ensure that nuclear service water offgassing did not result in voiding of TDAFW pum thereby. rendering the TDAFW pump inoperable. p suction supply piping:The vents were routed to th system. Given this low flow and because of potential voiding. the licensee declared the TDAFW pum) and the SSF inoperabl The licensee postulated that the vent lines 1ad become partially plugged with sediment from the normal lake source and were evaluating if future replacement was required.

The licensee took actions to identify the cause of the reduced vent flow. The licensee attempted to flush the portion of piping with air and water to dislodge any material that may have been present. Only a minor increase in flow rate was obtained. The licensee also performed additional evaluations of the established acceptance criteria and

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! 12 determined that a 1 gpm flow rate was adequate to maintain system operability. The acceptance critcria specified in Procedure PT/1/A/4200/08 was revised to reflect a 1 gpm acceptance criteri Subsequently, the TOAFW and SSS were declared operable. The Unit 2 continuous vent flow rate was verified greater than 3 gpm during surveillance testing performed September 24, 1997, Conclusions Licensee actions to revise the procedure reducing the acceptance

' criteria were acceptable. The inspectors also concluded that any further reduction in continuous vent flow rates could challenge the auxiliary feedwater system during an SSS event and heightened monitoring ano timely corrective actions were warranted to prevent future inoperability of these component H4 Maintenance staff Knowledge and Performance M4.1 Modification to Reolace Certain Isolation Drain Valves and Associated Pioina in the Reactor Coolant (NC) Crossover Lines (Unit 2) Insoection Scone (62700/55050)

The inspector determined by observation and document review, the adequacy of work activities ir regard to the replacement of certain 1 isolation drain valves and associated piping in the NC system crossover piping, Observation and Findinas Backaround Minor Modification MM-8401 was issued to control the work for replacing NC crossover loop isolation drain valves 2NC0005. 2NC0095. 2NC0106. and 2NC025 The licensee determined that the existing valves could not adequately perform their design function due to material degradatio These valves leaked during startup and caused water hammer damage to the NC drain tan Observation By review of the modification package. the inspector ascertained that the licensee planned to replace the existing two-inch Kerotest globe valves with the same size Anderson Greenwood bellows sealed type globe valves. Also, the licensee planned to install blank flanges downstrean of each of the replacement valves to provide additional protection against NC system leakage. Although these flanges were not required by design. they were being installed to provide additional conservatism and protection against leakag This modification involves Duke Class A and E piping. The code class break occurs at the secondary drain valves and involves only one wel l

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Also, the downstream piaing and blank flange assemblies were Code Class E. but were rated for tle higher side pret,ure of 2485 psig for 4 conservatis The licensee determined this modification would have no adverse impact on the operation of the NC system or interconnecting system The licensee's code reconciliation evaluation determined that the design requirements of the code used for the manufacture of the replacement valves (i.e.. American Society of Mechanical Engineers (ASME) Code Section III.1980) was consistent with design conditions. under the

' construction code of record, ASME Code Section III. 1971 Edition. For example. the pressure /temperture design parameter for this line was 2485 pounds per square inch gauge (psig) at 650 degrees Fahernheit versus 2675 psig at 650 degrees Fahernheit under the 1980 Edition of the aforementioned code. Additional dccaments reviewed included replacement valve quality records, coastruction and post-maintenance testing requirements, the unreviewed safety question evaluation and piping material control records. The subject valves and associated piping w re prefabricated on site as subassemblies and subsequently tied into * 1 system by welding. This activity was performed in accordance with Procedure SM/0/A/8140/001. Revisions ON and 001. Welds downstrea:: of the replacement valves were classified as Duke Class E and were fabricated in accordance with American National Standards Institu (ANSI) Code B31.1. 1973 Edition. The tie-in weld to the NC system, upstream of the replacement valve was classified as Duke Class A :nd was fabricated and tested to ASME Code Section III 1971 Edition thrc.gh Winter 1971 Addend The inspector observed completed welds and welding in 3rogress on Lia n -

E welds in NC Loop A to determine weld appearance, wor (manship, cleanliness and documentation as required by the applicable code Welds inspected and the associated process control sheets reviewed, were as follows: WL2FW 116-21. 22. 23. 24. 25. 41, 42, 43. and 44. All welds except 43 ano 44 were fillet welds. Welds 43 and 44 were full penetration groove welds. All the aforementioned welds were fabricated and inspected in accordance with ANSI Code B31.1 requirements. All records and isometrics reviewed were in orde Conclusion Minor Modification MM-8410 to replace certain isolation drain valves and associated piping in the NC system crossover pipe was being performed following applicable code requirements. Prefabricated subassemblies and

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field welds exhibited good workmanship attributes and material records were retrievable and in order. Quality Control inspections and visual examinations were performed as require Engineering evaluations and input were appropriat i a

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M4.2 Inservice Insoections of Safety-Related Welds (Unit 2) Insoection Scooe (73753)

Through work observation, procedure and records review, the inspector determined the adequacy of inservice inspection activi+ies durine the current Unit 2 EOC11 refueling outage. InserviceInspection(ISI)  ;

examined welds had been scheduled for this outage by the licensee's approved 10 year Inservice Inspection Pla bservations and Findinas The inspector observed surface and volumetric examination on one weld of the chemical and volume control system. Thi: weld was identified as follows:

its Held N Examination Tvoe bul_tji C05.021.057 2NV2FW189-14 Ultrasonic (UT) No rejectable indications (NRI)

C05.021.057A 2NV2FW189-14 Liquid Penetrant NRI The ultrasonic examination was aerformed with Procedure NDE-60 P.evision 10, which complied wit 1 the requirements of ASME Code Secticn 1 XI, 1989 Edition. This procedure had been reviewed and approved by the Authorized Nuclear Inspector (ANI) and the licensee's Level III  :

examiner. The examination was performed by well trained personnel in a conservative manner as demonstrated by the use of supplementary transducers to further it.vestigate apparent indications. The surface examination (i.e., liquid penetrant examination) was performed w'th Procedure NDE-35. Revision 16, which complied with applicable cooe requirements. The examination was performed in a satisfactory manner by well trained personnel. Results of this examinetion revealed that the subject weld was free of rejectable indir.ation In addition, the inspector reviewed records of completed ISI examinations to verify completeness and accuracy. These records were associated with the following welds:

ISI Item Weld N _ Descriotio- Results Liauid Penetran+

B09.021.002 2NC2FW15-25 Reducer to Tee NRI B09.021.010 2NC2FW49-19 Pipe to Valve NRI B09.040.122 2NV255RC2C-1 Pipe to RCP-2 NRI Cold leg i

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C05.011.148A 2N12FW26-14 Pipe to elbow NRI Ultrasonic G01.001.004 2RCP-20 Flywheel NRI Visual F01.020.258B 2MCASNV53215 Rigid Support Acceptable Revision 1 F01.020.261B 2MCRNV5140 Rigid Support Acceptable Revisicn 2 F01.020.266B 2MCRNV4788 Mechanical Acceptable Revision 3 Snubber F01.020.436C 2MCASMH141 Hydraulilc Acceptable Revision 6 Snubber A review of personnel qualifications, material and equipment certifications showed that the records were in orde Conclusion Volumetric and surface inservice inspections on designated welds were performed satisfactorily by qualified and well trained personnel who followed applicable non-destructive examination (NDE) procedure Examination records were complete and accurat M4.3 Steam Generator Reolacement Proiect (SGRP) (Unit 2) Insoection Scooe (S0001)

The inspector observed and evaluated the adequacy of cutting the primary and secondary piping for SGRP purposer and transporting the vertical enclosures. The inspector also reviewed housekeeping in the lower containment and observed weld material issue activitie Observations and Findinas Severina Existina Pioina from Steam Generators (SGs)

At the time of this inspection. October 20-24, 1997, the licensee was in '

the process of completing the cuts to sever the existing SGs from associated piping. Through discussions with cognizant personnel and field inspections, the ins)ector observed cutting activities on NC piping in loops B. C. and 1 The cutting operation was progressing smoothly using the same equipment utilized for McGuire 1 SGRP. Material removal per cut was kept low, about 0.004 inches, which meant that heat generation was kept relatively low, also minimizing machining stresses, increasing cutting tool life and making chip removal more manageabl I

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Housekeeping around the work area showed significant improvement over the two previous Duke facility SGRPs. For example unnecassary tools were kept to a minimum, metal chips were being gathered and stored for easy removal, debris was essentially absent from the work area and throughout the upper and lower containment area This same observation was noted on the NC pipe cuts. The location where the severance cut was made on the NC pipe was moved closer to the final

, weld prep surface than it was on the two previous SGRPs. This action was taken to minimize the amount of material on )ipe-ends that needed to be beveled and was based on previous knowledge tlat material removal on earlier SGRPs was conservative. Accordingly, the licensee determined that the severance cuts would be made such that the material left would be between 0.0 inches to + 0.125 inches on the SG side of the old weld centerline. Weld centerlines were located with the use of photogametr The bi-metallic interface on the old weldments was determined by the licensee with the aid of eddy current. Finally Framatome Technologies used this photogametry data to machine the weld preas on the replacement SGs stored in the onsite manufacturing facility. T1e licensee used UT

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measurements during the severing process to determine remaining material thickness and to make adjustments as necessary to assure concentricity with piping internal diamete In addition. the inspectors noted that the cuts on the main-steam lines, at the nozzle and on the vertical sections (candy cane) were made with the use of a specially designed cutting torch. The material next to the cut exhibited a minimum amount of discoloration that was associated with the torch cutting process. This indicated that the process was well controlled and the thickness of the effected material was negligibl In addition. the inspectors noted that the degree of component movement associated with these cuts was negligibl Iift and Transoort Vertical SG Enclosures SG enclosures were being lifted from existing locations. out of the reactor containment building and transported to a temporary storage area. This activity was performed by the same contractor who performed heavy lifts in the two previous Duke facility SGRPs. The inspectors observed the lift and transportation of the subject components for SGs B and The work was performed in a safe manner with conservatism and appropriate controls to minimize the risk of personnel injury. The lifting devices used (i.e., polar crane and outside lift system) had been properly tested, as required and were in compliance with applicable requirement Insoection of Filler Metal Issue Station Control of filler metal material was implemented through Procedure CF-426. Revision 0. Issue and Control of Weld Materia The inspectors reviewed the arocedure for completeness and clarity and performed an inspection of t7e filler metal issue statio As such the a

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inspectors verified material segregation, storage, rod oven temperature control, and instrument calibration. Warming ovens were being monitored for proper temperature and results were documented. In addition, the inspectors reviewed warmin completeness and accuracy.g oven loadin y of the logs subject and issue procedure wasslips fora co located at the subject issue station. T1e inspectors also determined that housekeeping was satisfactor Review of Welder Performance Oualification Records Qualification of welders scheduled to perform welding on the NC pipe welds was done at Framatome Technologies main facility. The actual test was done on a plate, in the flat 1G position, using ER 309 stainless steel filler metal wire. The licensee used the gas tungsten arc welding process documented in Data Sheet L-1658, Revision 3. As permitted by the ASME Code Section IX, Paragraph QW-302.2 the welder test coupons were radiographed for acceptance at McGuire by the licensee's non-cestructive examinaticn group. The radiographic procedure used for this work effort was RT-104. Revision 7, Acceptance Standard C. The inspectors reviewed radiographs of 10 welder test coupons to verify weld quality and found them to be acceptabl c. Conclusion Steam generator replacement activities were progressing well within the licensee's established schedule. Severing of NC loop piping and other secondary piping was well planned, executed and closely monitored by the licensee to assure good results. Similarly, heavy lifts were performed conservatively with adequate licensee oversight. Weld material control activities and welder performance qualification records were consistent with applicable recuirements and the licensee's procedure Housekeeping arounc the work area showed significant improvement over the two previous Duke facility SGRPs.

M6 Maintenance Organization and Administration M6.1 SGRP Oraanization and Administration Activities Insoection Scooe (50001)

The inspectors reviewed the current SGRP organization and administration to evaluate the effectiveness in supporting SGRP activities, b. Observations and Findings The licensee's organization and administration of the Unit 2 SGRP remained essentially the same as that for the Unit 1 SGRP. The inspectors noted that staffing reductions occurred in both the engineering and maintenance workforce. The reductions have not significantly affected organizational effectiveness or impacted safe steam generator re)lacement. The inspectors performed routine evaluations of worc activities and confirmed adequate staffing and I

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support to effectively implement the replacement project activitie The licensee established aggressive personnel exposure and safety goals for the Unit 2 SGRP. The inspectors periodically attended daily project management meetings and confirmed that the goals and actual project performance were reviewed and evaluated. Departures from expected performance received additional review arid evaluation, Conclusions

'The int?ectors confirmed through observation of 3roject activities and discussions with licensee representatives that tie SGRP organization was effective in adequately planning and safely executing the Unit 2 S3RP effort.

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M8 Hiscellaneous Maintenance Issues (92902)

M (Ocen) Insoector Followun Item (IFI) 50-369.370/97-09-03: 3-Year Fire System Testing This item was previously identified based on the inspectors * concerns that no periodic testing of the McGuire fire suppression system interior loop piping was being performed. Subsequently, the licensee developed a soecial flow test designed to verify operability of the subject syste The inspectors witnessed portions of an initial test of the auxiliary building loop piping and attended pre-job briefing for the test. The inspectors considered that the briefing was adequate for the evolution and that all involved personnel were made aware of their expectation During the collection of test data for the procedure, system indications fluctuated, which brought into question the validity of the data. Upon further investigation, the test performers identified that one of three pressure control valves (PCV) in the system was opening prematurely, causing inaccurate data measurement. The licensee secured the test configuration and evaluated the degraded condition for operabilit Based on the data and the redundancy within the system, the licensee determined that the fire suppression system was operable: however, one PCV was inoperable. A priority work request was written to adjust the PCV to its proper setpoint and verify operability of the other two PCV The inspectors monitored the licensee's test recovery actions and concluded they were adequate. The inspectors discussed the PCV problem with licensee fire protection personnel. Based on the preliminary information, it appeared that the PCVs for the system may receive only limited preventative maintenance, which may have contributed to the problem. The licensee plans on reperforming the loop flow test at a later date once all known problems are correcte The inspectors concluded that the licensee's development of the test to assure operability of the interior fire suppression loop piping was good. However. initial test performance problems did not allow for valid data to be taken. The problems identified indicated that some fire suppression equipment may have limited preventative maintenance

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being performe The inspector will continue to monitor the licensee's activities in this are II Enaineerina El Conduct of Engineering El.1 Review of Installation of SGRP Outside Liftina System (0LS) for Unit 2 a. Insoection Scooe (50001)

The inspectors: ex bined the Steam Generator Replacement Project (SGRP)

Outside Lifting Syster. '0LS) components erected outside of the Unit 2 equipment staging bui Cng: reviewed the adequacy of the SGRP lifting and transport programs and load test records, ensuring that they were prepared and tested in accordance with regulatory requirements, appropriate industrial codes, and standards: and verified that the maximum anticipated loads to be lifted would not exceed the capacity of the lifting equipment and supporting structures.

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b. Observations and Findinas The lifting and transporting systems for the SGRP for McGuire Unit 2 were eithe- identical or similar to the systems used in the Catawba or McGuire Nuc~aar Plant Unit 1 SGRP, The Catawba Nuclear Plant is another Duke Power nuclear plant with similar design. Duke successfully replaced the steam generators in both units in June 1906 and April 199 Therefore. Duke power had adequate experience in the replacement of the steam generator The inspectors reviewed the lifting programs, documents, drawings, and load test records that control the SGRP activitie The licensee listed ANSI codes and NUREG 0612. " Control of Heavy Loads at Nuclear Power Plants." 1980. as references in the SGRP Lifting Program. These references will be used as guidelines or standards for the SGRP lift activities. As specified in ANSI N45.2.15, Hoistin Rigging. and Transporting of Items for Nuclear Power Plants. 1981. the licensee performed a 110 percent load test for the OLS and transporters which will transfer tne steam generators to or from the storage facilit The crane inspection and load test records performed for preparation of the SCRP lif* 3 were reviewed by the inspectors to verify that the licensee successfully Jerformed the required inspections and load test During the review on t1e load test record for the procedures TN/2/B/9260/00/02C. Outside Lifting System Load Test. Revision 0 and TN/2/B/9205/00/25C. Proof lest the Steem Generator Haul Route Inside the Protected Fence Area. Revision 0, the inspectors found that the persons who signed and dated for the steps of the crane operation were not qualified crane operators. The licensee, however, stated that the steps

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were performed by qualified crane operators, although they were not the ones to sign and date the steps of the procedures. Qualified crane o)erators indeed performed the entire crane operation and signed in on t1e job briefing sheet, Hcwever, a craft foreman on the ground signed in the locations of the procedure steps for the crane operators in order to verify that those steps were performed and completed because these operators were seated inside the elevated crane cab during the crane lift operations, The inspectors verified that these operators were qualified crane operators,

-The above problem was also identified to the licensee during the Unit 1 SGRP operatio The leensee stated that they are still in the process of revising the procedures to add space for both supervisor or foreman in charge and crane operators to sign and date in the steps pecformed by the qualified crane operators. This is identified as a weaknes The inspectors also found that steps 4.3.25, 4.3.26, and 4.3.27 of the Procedure TN/2/B/9260/00/02C were performed out of sequence and required approvals prior to performing the steps out of sequence. PIP 2-M97 3707 was issued to evaluate the root cause and to resolve the problem for the steps performed out of sequence in Procedure TN/2/B/9260/00/02C, This failure constitutes a violation of minor significance and is being treated as a Non-Cited Violation (NCV), consisted with Section IV of the NRC Enforcement Manual. This is identified as NCV 50-370/97-17-03:

Procedure Steps Performed Out of Sequenc The inspectors walked down the OLS outside the equipment stage building. The OLS consists of an overhead crane and a similar rail road system. The railroad system extends into the inside of the reactor building for picking up or delivering the steam generators. Then the overhead crane system will lift the steam generators to or from a transporter. The transporter will transfer the old steam generators to the storage facility for temporary storage until the licensee decommissions the reactor vessel at the permanent storage location. The inspectors decided the erected lifting system and the rail system were adequate and could achieve the intended function for the SGRP.

, Conclusions The required lifting plan, path, load tests, and lifting ecuipment inspections generated or performed for the safe lifting anc transfer operations of the old and new SGs were adequate. One weakness and one NCV were identified for qualified crane operators not signing and dating in the procedures for the steps that they performed, and for performirg procedure steps out of sequenc >

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21 E1.2 Evaluation of Modification of Main Steam Guard Pioe for Unit 2 Steam Generator Reolacements Insoection Scooe (50001)

The inspectors reviewed the licensee's plan to modify the main steam guard pipe during the SGRP to verify the adequacy of these activities, Observations and Findinos The guard pipe to protect against a rupture of the main steam pipe for Unit 1 was cut into two portions near the nozzle of the Steam Generator (SG) in order to cut the main steam pipe around that area during Unit 1 SGRP in April 199 The top portion of the guard pipe was removed along the main steam 31pe. The lower portion was cut into several pieces for removal. Juring the reconnection of guard pipes to restore the original design after the new SG was in place, the licensee encountered difficulty in the alignment and fit-up before welding them together. The problem of the reconnection of the guard pipes increased worker radiation dose Based on NRC Generic Letter 87-11. Relaxation in Arbitrary Intermediate Pipe Rupture Requirements, the arbitrary intermediate pipe break protection is no longer required. However, the terminal end break protection is still required. Therefore. the guard pipt is not required except at the terminal ends such as nozzle Thus, the short segment of the guard pipe around the SG nozzle is still required for restriction of steam flow into the cavity due to a break at the nozzle area. The short segment of guard pi)e is not required to reconnect to the top portion of the guard pipe whic1 is integrated with the main steam pip The licensee plans to modify the original design by providing a short segment of guard pipe around the SG nozzle area without reconnecting it to the top portion of the original guard pipe. A new short segment of guard pipe with two horizontal half circular restrictor plates welded to it, called a guard pipe collar, will be installed and the restrictor plates will rest on the SG nozzle transition area with no weld between the new SG and collar. The short segment will remain in place under its own weight. In the event of a nozzle break event, the pressure above the internal restrictor ) late is greater than the pressure below the restrictor plates, t1us creating a significant downwara force holding the collar to the SG piping. This force, along with the collar's weight, will act to resist any upward drag forces resulting from steam

, rushing out of the colla The inspectors considered that the new design of the guard pipe collar 1 is adequat However, the design drawing MC-2419-13.20-05. Revision did not specify the location of the restrictor plates relative to the SG nozzle weld line in order to assume that the restrictor )lates will always remain below the SG nozzle weld line to prevent t1e uplift of the collar. After discussing this with the inspectors, the licensee's engineers issued a Variation Notice VN-29510/P2F to add a section view

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to the drawing with a control dimension for OC verification that the top of the guard pipe collar restrictor plates are installed below the SG nozzle weld line for the terminal end break protection. The inspectors reviewed this VN and considered it to be adequat The inspectors reviewed the following calculations in the areas related to the modification for the guard pipe collar:

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MCC-1206.48-07-1101. Calculation of Pipe Rupture 9ad by Computer Analysis for Main Steam System Revision 3

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MCC-1206.02-71-0025. Guard Pipe Flow Area. Revision 13

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MCC-1206.02-71-0091. Rigorous Stress Analysis of Piping Problem 2 SMA. Revision 15 The break cpening area in the snort segment of guard pipe of Unit 2 is 3.75 square feet and is less than the maximum allowable break area of 3.85 square feet stated in the safety analysis report. The inspectors considered the calculations were adequate to reflect the modifications except for the discrepancies stated belo During the review of calculation MCC-1206.02-71-0091, the inspectors found that discrepancies existed in the transformation signs for forces and moments among three coordinates for )lant Global. Unit 1. and Unit 2 (mirror image of Unit 1) in sheet 7 of tie calculatio The license's engineers quickly responded to the inspector's question and generated a simple three-dimensional stick model using the SUPERPIPE program. The stick model used the mirror image location and direction for Units 1 and 2. There was one coordinate used for Units 1 and The results showed the correct sign transformation as shown on sheet 7 of the calculations. However. for the unique coordinate shown, this demonstration model is different from the three coordinates shown in the sheet 7 of the calcuk.tions. If the calculations used are just one coordinate for both U 6cs 1 and 2 and the calculation changed the signs in forces and moments for Unit 2 due to the mirror image of Unit 1. the sign transformation shown in sheet 7 is correct. However, the additional coordinate was clearly indicated on that sheet for Unit 2 for the mirror imag The licensee also quickly reviewed the stress and support calculation The results indicated that no incorrect application of load or movement direction occurred. The calculation concluded that it was highly unlikely that there are ony components or structures which are not

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qualified due to inappropriate directional interpretation of sheet 7 in the Unit 2 main steam piping analysis calculations file. However, the inspectors consider that it is necessary to examine further several samples of stress and support calculations and verify accuracy of the conclusion made by the licensee for Unit 2 in order to make sure that no incorrect application of loads or moments transformed from Unit 1 to Unit 2. The above coordinate problem is identified as Inspector

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Followup Item (IFI) 50-370/97 017 04: Load and Moment Sign Transformation Application from Unit 1 to Unit c. Conclusions

. The licensee performed adequate preparations, supporting calculations, and had acceptable drawings and other documents to ensure the installation of the new short segment of guard pipe during the SGRP. An Inspector Followup Item was identified for a clarification of load and moment sign transformation application from Unit 1 to Unit E4 Engineering Staff Knowledge and Performance E4.1 Soent Fuel Pool System Monitorino Durina AnticiDated Chances Insoection Scoo_e The inspectors reviewed the licensee's control of the Unit 2 spent fuel SFP cooling system during anticipated changes in system operating parameter b. Observations and Findinas_

During the Unit 2 outage the normal, train B power supply to safety-related components. 2ETB. was scheduled to be interrupted to >erform scheduled maintenance for approximately 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. Based on t1e extent of the work, the licensee estimated that if needed. 2 ETB could be restored within several hours. The primary impact of this activity on Unit 2 safety-related components was the loss of power to the train B SFP cooling pump. During the evolution. both the normal and the emergency power supplies for the 2B SFP pump were unavailable due to 2ETP being taken out of service. However both the normal and emergency power supplies were available to supply power to the A train SFP cooling pun Coincidentally, operators were monitoring the Unit 2 SFP via a 12-lour conditional surveillance, due to the normal Unit 2 SFP computer monitoring point being out of servic Initial conditions for the evolution were that both trains of the SFP cooling system were in operation due to the recent reactor core offload to the Unit 2 SFP completed on October 12.199 On October 23. 199 the licensee isolated the B train SFP cooling pump two days prior to taking 2ETB out of service. At this time, the calculated time for SFP boiling was approximately 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> without any coolin After the operating shift took the B train SFP cooling pump out of service, the SFP temperature started to rise due to the decreased SFP cooling. The operators were aware of the condition and were applying increased attention to the SFP temperature. However, after

, approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, the SFP temperature had risen 12 degrees ..

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l 24 0)erators questioned whether this heat-up rate was expected and where tie SFP temper?ture would peak. The operators elected to restart the 2B SFP pump to provide additionai cooling to the SFP while further exploring the expected temperature rise with engineerin On October 24. 1997, the inspectors discussed the evolution with engineering and operations personnel. The inspectors determined that although engineering )ersonnel had established that isolating one of the SFP pumps would not c1allenge the design basis temperature for the SF operators were not informed on the expected system res>onse. The licensee documented this communication and control pro)1em via PIP 2-M97 3959 and agreed with the inspectors' observation The inspectors also reviewed the abnormal operating procedure associated with the SFP cooling system. Procedure AP/2/A/5500/41. Loss of Spent Fuel Cooling or Level. The entry symptoms for the procedure were 1)

operator aid computer (OAC) alarm spent fuel pool temperature high or ?)

both SFP cooling pumps off. The inspector noted that due to the coincident 0AC replacement project, the normal anticipatory 0AC alarm point for the SFP temperature high alarm was not availabl Consequently, operators were required to perform conditional surveillances of the SFP temperature every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> via a control room indication. Operators indicated they were monitoring the tem)erature of the SFP more frecuently after stopping of the 2B SFP pump. T1e inspectors consicered that the minimum conditional surveillance frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> may not have been ideal during the anticipated SFP temperature increas Conclusions The inspectors concluoed that communication between engineering and operations regarding anticipated spent fuel pool temperature increase following isolation of one spent fuel cooling pump were not effectiv Formal adjustment to the required surveillance monitoring interval of the SFP may also have been warranted given that the associated computer alarm points were unavailabl E4.2 Hydroaen Mitiaation System !HMS) Ooerability Reauirements Insoection Stone The inspector reviewed the facts and circumstances related to an NRC identified discrepancy between the UFSAR and TS pertaining to the HM Observations and Findinas According to UFSAR section 6.2.7 and station drawings for the HMS. the HMS consists of two trains of igniters with a total of 70 igniter glow plugs and associated transformers for each unit. However, the inspectors noted that TS 3/4.6.4.3 reflects a total of 66 igniters with 32 of 33 per train required operable. The inspector verified that all 70 igniters were surveillance tested by Periodic Test 435e/23A and B

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25 Hydrogen Mitigation Igniter Current Verificatio The inspectors reviewed the NRC's supplemental Safety Evaluation Re) ort Nunber 7 on the McGuire Nuclear Station and identified that during t1e licensing of Unit 2. a~ licensing condition was noted indicating four additional )

igniters would be added to the 66 at the next refueling outage for Unit 1 and the first refueling outage for Unit 2. The four igniters were added to both units: however, the TS were not updated to reflect the new total. The licensee responded that the new Improved Standard Technical Specification future u> grade project had accounted for the 70 igniters, although it would not se implemented for some time, c. Conclusions The inspector identified an inconsistency between the number of installed hydrogen igniters and TS. No immediate safety or operability issues existed since plant procedures required testing all installed 70 igniters. This is identified as Inspector Followup Item 50 369.370/97-17 01.: Adequacy of Hydrogen Mitigation System Operability Requirement This item will remain open )ending further review of the adequacy of the current TS in relation to t1e design and licensing basi E8 Hiscellaneous Engineering Issues (92903)

E (Closed) Violation (VIO) 50 369/96-11-02: Failure to Implement irsnporary Modification Process

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This violation dealt with the inappropriately controlled installation of a temporary security fence on a Unit 1 exterior valve vault. The inspectors reviewed the licensee's actions to prevent implementation of modifications without completely executing the requirements of the McGuire Modifications Manual. Written guidance was provided to i

supervisors, managers, and engineering staff on adhering to station processes. Formal training was provided to the operations staff and drills were conducted to validate expected response times following installation of the security barrier. The licensee's actions included revisions to the McGuire Modifications Manual to provide additional guidance on the initiation criteria for temporary modifications. The inspectors concluded that the identified corrective actions have been completed. These corrective actions, coupled with the current licensee processes for evaluating changes to facility structures, systems, and components were considered adequate. This item is close IV. Plant Support P5 Staff Training and Qualification In Emergency Preparedness P5.1 faroency PreDaredness (EP) Staff Trainino and Oualification (71750)

a. Inspection Scong

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The inspectors monitored the results of EP drill 97-4 conducted with

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shift A in the simulator control room on October 1,199 Observations and Findinas During this 'll. the Technical Support Center.-Operations Support Center, and L rgency Operations facility (EOF) were fully activate State and County participation was limited to receiving emergency notification messages only. Based on the inspectors' observations and results of the licensee's drill critique summary, the inspectors concluded that the drill adecuately demonstrated the set objectives with two exceptions. One involvec the site assembly time not being met in that all personnel were not accounted for within 30 minutes and the other was that the EOF was not considered operational within 75 minutes of event declaration. The inspectors discussed the identified concerns with EP management and considered that appropriate focus was being applied to these areas to improve future performance. The inspectors also recognized that the current drill was conducted during a very conservative time (ie, beginning of a major unit outage) and this was indicative of the licensee's continued emphasis on challenging the EP area performanc The licensee's conservative timing of the drill and continucd aggressive drill schedule was identified as an area strength.

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c. Conclusion An October 1, 1997 emergency preparedness drill adequately demenstrated the set objectives with two exceptions. Appropriate focus was being applied to these exception areas to inprove future performance. The licensee's conservative timing of the drill and continued aggressive drill schedule was identified as an area strength. (Section P5.1)

S4 Security Staff Knowledge and Performance S4.1 Security Performance Problems Durina Protected Area Vehicle Verifications (71750) Incoection Scooe The inspectors reviewed activities associated with the licensee's identification of security guard performance issues at the McGuire Nuclear Station, b. Observations and Findinas The inspectors were made aware of a potential problem involving multiple security guards not accurately performing vehicle accountability searches. The inspectors discussed the matter with licensee security management and were informed that actions had been taken to address the identified problem and that no current concern regarding security guard performance existe ,

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27 Conclusion Based on the provided information, the inspectors identified an IFl to allow further NRC review of the issue. This item is identified as IFl 50 369.370/97-17 02: Potential inaccurate Records Associated with Vehicle Searche Manaaement Meetinas X1 Exit Heeting Summary The inspection results were presented to members of licensee management at the conclusion of the inspection on November 4,1997, and on November 13, 199 The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified, PARTIAL LIST OF PERSONS CONTACTED Licensee Barron, B., Vice President, McGuire Nuclear Station Boyle, J.. Civil / Electrical / Nuclear Systems Engineering Byrum, W., Manager, Radiation Protection Cash M., Manager, Regulatory Compliance Cross, R., Regulatory Compliance

- Dolan. B., Manager, Safety Assurance Geddie. E., Manager, McGuire Nuclear Station Herran, P., Manager. Engineering Loucks L , Chemistry Manager Morgan, R., Steam Generator Replacement Project (SGRP) Supervisor Rhyne, K , SGRP Engineering Supervisor Thomas. K., Superintendent. Work Control Travis, B. , Manager. Mechanical Systems Engineering Tuckman, M., Senior Vice President, Nuclear Duke Power Company NRC S. Shaeffer. Senior Resident inspector McGuire M. Franovich Resident Inspector, McGuire M, Sykes, Resident Inspector. McGuire N. Economos Regional Inspector R. Chou, Regional Inspector INSPECTION PROCEDURES USED IP 71707: Conduct of Operations IP 62707: Maintenance Observations IP 61726: Surveillance Observations v i

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l IP 40500: Self Assessment t

IP 37551: Onsite Engineering

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IP 71750: Plant Suppt t

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IP 92901: Followup - Operations IP 92902: Followup Maintenance IP 92903: Followup - Engineering ITEMS OPENLD, CLOSED. AND DISCUSSED i

(CEQ 50 369.370/97-17 01 IFI Adequacy of Hydrogen Mitigation System

Operability Requirements (Section E4.2)

l 50-369.370/97 17 02 IFI Potential Inaccurate Records Associated with j Vehicle Searches (Section 54.1)

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50 370/97 17-03 NCV Procedure Steps Performed Out of Sequence (Section El.1)

i 50 370/97-17-04 IFI 3 LoadandMomentSi!nTransfccmationApplication from Unit 1 to Uni 2 (Section El.2)

l CLOSEQ

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50 369/96 07 LER Mode Related Missed TS Surveillance on 1 Containment Integrity due to a Technical j Inaccuracy (Section 08.1)

50 369/96 11 02 VIO Failure to implement Temporary Modification

!

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Process (Section E8.1)

DISCUSSED

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l 50-369 370/97-09 03 IFI 3-Year Fire System Testing (Section M8.1)

LIST OF ACRONYMS USED ALARA -

As Low As Reasonably Achievable AFW -

Auxiliary Feedwater AFWCST - Auxiliary Feedwater Condensate Storage Tanks ANI -

Authorized Nuclear Inspector

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ANSI -

American National Standards Institute ASME -

American Society of Mechanical Engineers CCC - Configuration Control Cards CF Code of Federal Regulations DNB -

Departure from Nucleate Boiling EDG -

Emergency Diesel Generator EOC - End of Cycle

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.

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E0F -

Emergency Offsite Facility-LEP - Emergency Preparedness EST - Engineered Safety Feature FHSRO -

Fuel Handling SRO GL -

Generic letter-GPM -

Gallons Per Minute HMS -

Hydrogen Mitigation System -

ICS -

Ice Condenser System IFl -

Inspector Followup Item IR -

Inspection Report

ISI -

In Service Inspection MOV - Motor 0perated Valve MSSV - Main Steam Safety Valve hC -

Reacter Coolant System NCV -

Non Cited Violation NRC -

Nuclear Regulatory Commission NRI - No Rejectable Indication NRR -

NRC Office of Nuclear Reactor Regulation 0AC -

Operator Aid Computer OLS -

Outside lifting System PCV -

Pressure Control Valves PDR -

Public Document Room PIP -

Problem Investigation Process PM/PT -

Preventive Maintenance / Periodic Testing PSIG -

Pounds per Square Inch Gauge OC -

Quality Control RCA -

Radiologically Controlled Area RCS -

Reactor Coolant System RWP -

Radiation Work Permit RWST -

Refueling Water Storage Tank SFP - Spent Fuel Pool SG -

Steam Generator SGRP -

Steam Generator Replacement Project SSS -

Standby Shutdown System SRO -

Senior Reactor Operator TDAFW -

Turbine Driven Auxiliary Feedwater TM -

Temporary Modification TS -

Technical Specifications UFSAR -

Updated Final Safety Analysis Report URI -

Unresolved item USQ -

Unreviewed Safety Question UT -

Ultrasonic Test VN -

Variation Notice VIO -

Violation WO -

Work Order

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