IR 05000282/1998003

Insp Repts 50-282/98-03 & 50-306/98-03 on 980114-0224. Violations Noted.Major Areas Inspected:Licensee Operations, Maint,Engineering & Plant Support

ML20216E484
Person / Time
Site:	Prairie Island
Issue date:	03/12/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20216E445	List: ML20216E439 ML20216E462 ML20216E484
References
50-282-98-03, 50-282-98-3, 50-306-98-03, 50-306-98-3, NUDOCS 9803180063
Download: ML20216E484 (29)

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.s U.S. NUCLEAR REGUI.ATORY COMMISSION REGIONlli Docket Nos: 50-282; 50-306 License Nos: DPR-42; DPR-60 i

Report No: 50-282/98003(DRP); 50-306/98003(DRP)

Licensee: Northem States Power Company l Facility: Prairie Island Nuclear Generating Plant j

Location: 1717 Wakonada Driva East Welch, MN 55089  ;

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Dates: January 14,1998, through February 24,1998 j inspectors: S. Ray, Senior Resident inspector P. Krohn, Resident inspector S. Thomas, Resident inspector Approved by: J. W. McCormick-Barger, Chief Reactor Projects Branch 7 l

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9803180063 900312 PDR ADOCK 05000282 G PDR

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EXECUTIVE SUMMARY i j

Prairie Island Nuclear Generating Plant, Unit 1 and Unit 2 NRC Inspection Report No. 50-282/98003(DRP); 50-306/98003(DRP) '

This inspection included aspects of licensee operations, maintenance, engineering, and plant i support. The report covers a six-week period of resident inspectio Operations i e Control room access control, communications, and professionalism were improved compared to previous inspection observations. Control room operators consistently i managed access to the areas designated "at the controls" and ensured that no personnel l with food, drinks, hard hats, or other unauthorized material approached the control l panels. The inspectors also noted improvements in timely attendance at shift briefing l meetings by crew members and overall improvements in control room professionalism.

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(Section 01.1)

• Operations personnel responded rapidly and property to a failure of a main feedwater valve and to the loss of the 10 transformer, which resulted in the momentary loss of )

power to a Unit 2 safeguards bus. (Section 01.1)

. The winter plant operation procedure was adequate to ensure that equipment in all of the buildings inspected was wann, dry, and adequately protected from the cold. The inspectors identified one minor procedure problem. (Section 01.2)  :

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l . A reactor coolant system leak on Unit 2 was rapidly identified and conservative action <

was taken to shut down the plant for repairs. The operators performed a well-controlled, i deliberately paced shutdown. (Section 01.3)

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l . Draining of the Unit 2 reactor vessel head to conduct welding was well-controlled. An excellent pre-job briefing was held and diverse indications and inventory balance calculations were used throughout the evolution. (Section 01.3) 1

. Increased monitoring for potential Unit i reactor coolant system leakage was slow to be established even after new information concoming tile flaw size in the Unit 2 reactor coolant system pressure boundary became known. In addition, the basis for evaluating operability of Unit 1 was not adequately documented. Once established, the ,

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compensatory actions were comprehensive and reasonable. (Section 01.3) '

. The safeguards ventilation systems inspected were in good material condition with no deficiencies noted. The inspectors identified one minor Updated Safety Analysis Report discrepancy. (Section 02.1)

• Operators demonstrated a significant increase in awareness of procedure adherence requirements. They frequently stopped to revise steps that wore unclear or could not be accomplished as written, in the lest seven months, only one minor case of an operator failing to follow procedures was identified. Licensee corrective actions to improve operator procedure adherence appeared to be effective. (Section 08.2)

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Maintenance

• Maintenance and surveillance test activities were performed well with no discrepancies noted. However, examples of surveillance test procedures needing improvement continued to be identified as highlighted by the inspectors' identification of inaccurately indicating source range meters at the hot shutdown panels. (Section M1.1)

• Following the identification of a leak on Unit 2 partial length control rod drive mechanism Gg, removal, nondestructive examinations, and repair activities associated with all of the Unit 2 partial length control rod drive mechanisms were conducted wel The methods, tools, and techniques used during the nondestructive examinations were adequate for the inspections performed. An effective task force wss established to manage the repairs. Contractors were carefully supervised by system engineers and performed the component removal and repairs in a deliberate, controlled manner. Quality services (quality assurance) oversight of the project was good. (Section M1.2)

• The backlog of corrective maintenance work orders was relatively small and stabl Priority work and control room deficiencies received adequate attention. Equipment failures which led to entry into Technical Specification Limiting Conditions for Operation were infrequent and rapidly resolved. There were very few temporary modifications in place. Work was completed in a timely manner and was generally done correctly the first time. Operability decisions because of degradsd equipment were conservativelv mad Overall, a review of the maintenance backlog indicated a strong maintenance program which was receiving suitable management attention. The backlogs were about 1100 non-outage work orders of all kinds, about 70 power block corrective maintenance work orders, 3g control room deficiencies,12 " operator workarounds," and 5 temporary modifications. There were 10 Limiting Condition for Operation entries due to equipment issues in the previous six weeks, no missed surveillance tests or preventative I msintenance tasks in the previous year, and about i repeat work order per month in the '

previous year. (Section M2.1)

• An inadequate review of the 1H3 breaker protection logic led to an inappropriately sequenced work order for a non-routine maintenance activity. This resulted in an engineered c;Yy feature system actuation. The event was the fourth documented case in a little ovo e par in which an inadequate review of logic circuits led to problems during maintenance c testing activities. All of the events occurred during either first-time evolutions or infrequent and emergent work activities. A violation was identified for failure to provide an appropriate work order. (Section M3.1)

Enaineerino

. The results of special control room ventilation envelope testing, initiated in response to previous NRC concems, indicated that potential in-leakage into the control room was greater than design assumptions from both steam exclusion and dose control standpoints. Although design assumptions could have been exceeded, the control r.>om would probably have remained habitable. Confirmatory calculations were in progres (Section E8.5)

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The inspectors observed several instances of good radiation control practices to maintain

dose as low as reasonably achievable during the Unit 2 partial length control rod drive l mechanism repairs. (Section R1)

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Report Details Summary of Plant Status Unit i operated at or near full power for the entire inspection period. Unit 2 operated at or near full power until January 24,1998, when it was shut down because of a reactor coolant system

- leak. Unit 2 remained in cold shutdown for the remainder of the inspection perio I, Operatient 01 Conduct of Operations 01.1 General Comments Inspection Scope (71707. 92901)

The inspectors conducted frequent reviews of plant operations. The reviews included observations of control room evolutions, shift tumovers, pre-job briefings, communications, control room access management, logkeeping control board monitoring, and general control room decorum. Updated Safety Analysis Report (USAR),

Section 13, " Plant Operations," Revision 15, was reviewed as part of the inspectio Observations and Findinas

• On January 14,1998, the Unit ? "B" main feedwatar valve, CV-31136, failed

"as-is" when a fuse blew in a steam generator water level control system circuit card. This caused a decreasing water level in the 22 steam generator, Control room operators rapidly diagnosed the problem, took manual control, and opened the "B" main feedwater bypass valve, CV-31372. This restored steam generator water level to the programmed band. The "B" main feedwater valve wat placed in local /marual control while the 22 steam generator level was controlled with the l

"B" bypass valve in automatic The "B" main feedwater valve was repaired m.'d i retumed to service on Januar) da 1998. Control room operators acted prompiv and appropriately to the steani generator water level control proble l

• On January 21,1998, while operators were performing electrical isolation activities in the substation, a 10 transformer lockout occurred. This resulted in the loss of the 12 cooling tower transformer and a momentary loss of the 26 safeguards bus on Unit 2. The inspectors monitored the operators' response to l'iw event. Loads on Bus 26, including the 22 component cooling water pump

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and the 23 charging pump, were automatically shed. The loss of the charging pump caused an automatic isolation of the charging and letdown lines. Power to Bus 26 was automatically restored from the attemate 2RY reserve transformer within seconds. The 21 component cooling water pump automatically started on low header pressure, and the operators manually started the 22 charging pump and restored normal charging and letdown flow ,

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The inspectors noted that the operators followed the proper response and recovery procedures, entered the proper Technical Specification (TS) Limiting Condition for Operation, performed the proper surveillance tests required for a loss of one offsite power source, and ensured oat a timely report was made to the NRC in accordance with 10 CFR 50.72. All plant equipment responded as designed during the event. The maintenance aspects of this event are discussed in Section M3.1 of this repor . Throughout the inspection period, the inspectors noted improved control room access management by operations personne.l. Section Work Instruction (SWI) 0-47, " Control Room Access," Revision 0, was issued on January 23,1998, establish'ag standards for control room access. Control room operators constantly mtnaged access to the areas designated "at the controls" and ensu,.3d that n" ps,rsonnel with food, drinks, hard hats, or other unauthorized material approached the control panels. The inspectors air,o noted improvements in timely attendance at shift briefing meetings by crew menibers and overall improvements in control room professionalis Conclusions Control room decnrum and professionalism were improved compared to previous inspection observations. Operations personnel responded rapidly and property to a failure of a main feedwater valve and the loss of the 10 transforme .2 Cold Weather Preparations Inspection Scope (71714)

The inspectors reviewed the licensee's preparations for cold weather operations. The !

inspection focused on the free-standing, out-plant buildings to ensure that the prescribed j cold weather protective features were in the condition required by procedures and l adequately performing their intended functions. The inspectors reviewed the following l procedures as part of this inspection-

= Periodic Test Procedure (TP) 1637, " Winter Plant Operation," Revision 21;

• Operating Procedure C28.6, " Condensate Storage Tank Freeze Protection System," Revision 5; and

. Operating Procedure C37.5, "Screenhouse Normal Ventilation," Revision Observations and Findinas The inspectors verified that TP 1637 had been completed before the cold weather season. To evaluate the adequacy of the licensee's winter plant operation procedure, the inspectors toured the following remote buildings: intake screenhouse, plant screenhouse, ,

cooling tower equipment houses, cooh.'q tower pumphouse, cooling towers, security emergency diesel building, water treatmei.: building, and the deepwell pumphouses. The inspectors noted that the buildings were warm and dry, and that the lineups specified by TP 1637 were stillin effec .

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The inspectors noted a minor procedure problem in that Steps 7.6.4,7.7.2, and 7.12.1 of TP 1637 required that the unit heaters located in the cooling tower equipment, control and radiation monitor houses, cooling tower pumphouse, and intake screenhouse have their thermostats set at 55'F. Out of the 23 thermostats inspected, only 4 were est at 55'F. The remainder were set between 55 and 70*F. The general superintendent plant operations confirmed that 55'F was considered a minimum setting, with upward adjustments allowed for comfort. He agreed that the procedure should be clarified on that poin Conclusions For all the buildings inspected, the licensee's winter plant operation procedure was adequate to ensure that equipment was warm, dry, and adequately protected from the cold. The inooectors identified one minor procedure problem which will be addressed by the license .3 Unit 2 Forced Shutdown to Repair Reactor Coolant System (RCS) Leak Inspection Scope (71707)

On January 24,1998, Unit 2 was shut down due to a 0.2 gallon per minute RCS leak from the G9 partial ler.gth (P/L) control rod drive mechanism (CRDM). The inspectors monitored the shutdown and subsequent operations activities. The inspectors reviewed the following documents as part of this inspection:

. Surveillance Procedure (SP) 1001AA, " Reactor Coolant System Leakage Test,"

Revision 27;

. SP 2001 AA, " Reactor Coolant System Leakage Test," Revision 26;

• Section Work Instruction (SWI) 0-47, " Control Room Access," Revision 0;

. Operating Procedure 2C1.3, " Unit 2 Shutdown," Revision 40;

. Operating Procedure 2C1.4, " Unit 2 Power Operation," Revision 15; l

. Operating Procedure 2C4.1, "RCS Inventory Control- Pre-Refueling," Revision 4;

• Temporary instruction 98-07, dated February 10,1998;

. Temporary Instruction 98-08, dated February 10,199 Observations and Findinas Early on January 23,1998, unidentified RCS leakage increased by about a factor of ten to 0.2 gallon per minute. This increase was first detected by the operators during performance of test SP 2001 AA and confirme,d by operators noting increased i containment sump pump run times and increased containment radiation monitor readings. Operators, engineers, and radiation protection personnel entered the Unit 2 containment and identified that the leak was from P/L CROM G9. Licensee engineers

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surmised that the most likely source of the leak was the intermediate canopy seal weld, a weld that was not considered part of the RCS pressure boundary. Nevertheless, licensee 1

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management conservatively decided to shut down Unit 2 to repair the leak, even though the leak rate was well below the TS limits for unidentified or identified leakage. (It was later determined that the leak was actually from an RCS pressure boundary weld for which the TS would have requimd that, within one hour, actions be initiated to place the unit in hot shutdown within the next six-hours.) Unit 2 was taken off line on January 24, i and reached cold shutdown on January 2 l During the shutdown, the operators property followed procedures and used formal, three-way communications. The operators were attentive to plant indications and  !

exhibited positive control of the plant. The inspectors noted that the operatcrs rigorously applied the access control requirements of the recently issued instruction SWI O-47. The shutdown was well-controlled and deliberately pace j On January 29,1998, the inspectors monitored the draining of the reactor vessel to one foot below the reactor vessel flange in accordance with Procedure 2C4.1 Reactor vessel level had to be lowered to create the proper welding conditions for repair of the G9 P/L CRDM. The inspectors attended the pre-job briefing for the draining in which RCS flow and drain paths, personnal assignments, communications, precautions, limitations, and i decay heat removal methods were discussed. In addition, RCS vent paths, RCS inventory controls, calculations to be performed during the draining evolution, RCS drain rates, abnormal indications that would require the draining to be stopped, and problems with previous draining evolutions were discussed. The general superintendent of plant operations attended the briefing and discussed management expectations, diverse <

reactor vessel level indication methods, relevant emergency plan sections, and abnormal operating procedures associated with draining water from the reactor vo se The inspectors monitored both control room and containment activities during the actual draining evolution. The operators used good communications, checked diverse level indications, and performed mass transfer calculations throughout the evolution. The licensee placed the proper focus and attention on this critical plant evolution that had caused past problem i On February 1,1998, the licensee identified that the leak originated above the intermediate canopy seal weld in a flaw in the motor tube base. This RCS pressure boundary leak was reported to the NRC in accordance with 10 CFR 50.72. Beginning on February 1, the licensee developed defect repair and root cause determination plans for the flaw. Operability of Unit 1 was evaluated based on the revised determination of the Unit 2 flaw location. Trends for Unit 1 RCS leak rate, containment radiation, and containment sump run times were reviewed and found to be stabl Late on February 8,1998, a licensee contractor performed an unqualified manual ultrasonic test examination of P/L CRDM G9. The preliminary results showed two inside diameter indications, one approximately 5 inches long and one approximately 3 inches long. Licensee management was informed of the findings on the moming of February On the aftemoon of February 9, NRC management expressed their concem to licensee management that the licensee staff had not adequately reevaluated operability and compensatory actions for Unit 1 in light of the apparent size of the defect in Unit 2. Later that evening, the licensee commenced additional monitoring of the Unit 1 RCS conditions

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via temporary instructions 98-07 and 98-08 from the general superintendent of plant operations. In addition, the engineering staff expanded the documented operability evaluation for Unit 1 with more information on the basis for the determinatio Enhanced monitoring of the Unit 1 RCS included performing RCS leak rate calculations j

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(SP 1001AA) once per shift instead of daily, placing containment radiation monitors and humidity readings on continuous trend displays in the control room, and increasing the monitoring of containment fan coil unit collection pot levels to twice per shift. In addition, no elective work was allowed on Unit i emergency core cooling system components I without management approval. Training department personnel verified that all crews had l recently practiced small-break Loss-of-coolant-accident scenarios. The compensatory l actions were comprehensive and reasonable.

I Conclusions The leak on Unit 2 was rapidly identified and conservative action was taken to shut down the plant for repairs. The operators performed a well-controlled, deliberately paced shutdown. Draining of the Unit 2 reactor vessel head to conduct welding was also well-controlled. An excellent pre-job briefing was held and diverse indications and inventory balance calculations were used throughout the evolution.

i increased monitoring actions for Unit 1 RCS leakage indications were slow to be established once new information concoming the flaw size in the Unit 2 RCS pressure boundary became known. In addition, the basis for evaluating operability of Unit 1 was not adequately documented. Once established, the compensatary actions were nmprehensive and reasonabl )perational Status of Facilities and Equipment O2.1 Enaineered Safety Feature (ESF) System Walkdown of Safeauards Ventilation Systems Inspection Scope (71707)  ;

I The inspectors performed a walkdown of the screenhouse safeguards ventilation system, ,

Unit 2 containment vessel air handling system, Unit 1 and Unit 2 shield building ventilation systems, and the spent fuel pool ventilation systems. The inspectors reviewed design basis information associated with each of the ventilation systems, and v6rified that design performance requirements were being tested through the periodic performance of specific surveillance tests, j The inspectors reviewed the following documents as part of the inspection:

• USAR, Section 5, " Containment System," Revision 15;

. USAR, Section 10.3.4, " Auxiliary Building Special Ventilation System,"

Revision 14;

. USAR, Section 10.3.7, " Spent Fuel Pool Ventilation Systems," Revision 14;

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• Final Safety Analysis Report (FSAR), Section 14.2.1, " Fuel Handling Accidents,"

Revision 0; e FSAR, Section 5.4, " Containment Vessel Air Handling System," Revision 0;

• Operating Procedure C37.8, "Screenhouse Safeguard Equipment Cooling,"

Revision 6;

. Operating Procedure C18.1, " Engineered Safeguards Equipment Support Systems," Revision 6;

= Operating Procedure 1C19.1, " Containment System Ventilation Unit 1,"

Revision 0;

. Operating Procedure 2C19.1, " Containment System Ventilation Unit 2,"

Revision 0; e Nonconformance Report 19970525, " Containment Purge System ESF Logic is Pooriy Designed";  !

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. SP 1106A, "12 Diesel Cooling Water Pump Test," Revision 53;

. SP 11068, "22 Diesel Cooling Water Pump Test," Revision 52;

• SP 1106C, "121 Cooling Water Pump Quarterly Test," Revision 9; I I

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. SP 1263, " Unit 1 - Containment Purge Effluent Rad Monitor Test," Revision 4;

. Drawing NF-40750-6, " Interlock Logic Diagram Nuclear Steam Supply System Radiation Monitoring System Units 1 and 2," Revision G;

• Drawing NF-40763-1, " Interlock Logic Diagram Screenhouse Heat and Vent System, Units 1 and 2," Revision K;

• Drawing NF-40762-1, " Interlock Logic Diagram Containment Purge, in-Service Purge and Spent Fuel Special Units 1 and 2," Revision L;

• Drawing NF-40762-2, " Interlock Logic Diagram Containment Purge, In-Service Purge and Spent Fuel Special Units 1 and 2," Revision L;

• Drawing NF-40762-3, " Interlock Logic Diagram Containment Purge, in-Service Purge and Spent Feel Special Units 1 and 2," Revision M; and

. Work Order 9712943, " Electrical Maintenance Procedure PE 0112D 52." Observations and Findinas Both FSAR Section 5.4.2 and USAR Section 5.2.3.3 stated, " Purge flow will be controlled from a local control station where a remote readout from the Vent Radiation Monitor will

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be provided." Although the purge supply and exhaust flow from both the Unit 1 and Unit 2 j containment could be controlled from a local station located on the 755-foot elevation of l the auxiliary building, the inspectors determined that no remote vent radiation monitor l readout existed at or near the station. Criterion lli of Appendix B of 10 CFR Part 50, l

" Design Control," states, " Measures shall be established to assure that apphcable regulatory requirements and the design basis, as defined in Part 50.2 and as specified in the license application, for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and l instructions." Thus, failure to supply the remote radiation monitor readout at the local l control station was a violation of Criterion Ill.

l l The licensee had recently initiated a comprehensive USAR review and update project, l which was described in a letter to the NRC dated September 26,1997. The inspectors j

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brougl t the local purge supply and exhaust radiation monitor discrepancy to the attention

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of an engineer on the project team. The review team had already completed a Phase One review (a review of documentstion associated with the design basis) of this portion of the USAR but had not started the Phase Two review (a walkdown and physical I comparison between the equipment described in the USAR and actually installed). The l engineer acknowledged that, for the Phase One portion of the USAR update project, the )

licensee had not identified the lack of a ventilation radiation monitor readout at the purge j supply and exhaust local control station. The system engineer added the discrepancy to j the USAR update list and stated that the discrepancy would be corrected during the next <

USAR revisio The inspectors have previously noted several good findings by the USAR review team ,

since it was formed and concluded that Phase Two of the USAR review project would l

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likely have identified the local radiation monitor discrepancy noted by the inspectors. The containment purge and exhaust system was seldom used and would normally be controlled remotely from the control room where radiation monitoring instrument 4 Indications were available. Thus, the failure to install a remote radiation monitoring readout at the local containment purge and exhaust system control panel as described in )

the FSAR and USAR constitutes a violation of minor significance and is being treated as a Non-Cited Violation (NCV), consistent with Section IV of the NRC Enforcement Policy (50-282/98003-01(DRP); 50-306/98003-01(DRP)).

Durir.g the walkdown, all ducting, filter housings, fan motors, and dampers were examined by the inspectors. Material condition was found to be good and no discrepancies were note The inspectors also reviewed the engineering calculations and methodology associated '

with changing the thermal overioad trip setpoints of the 121 spent fuel pool inservice purge fan breaker. The thermal overlosd trip setpoints were changed as part of Work i Order 9712943. Control fuse settings, trip test currents, and thermal overioad size selections were also revit,wed. No discrepancies were note Conclusi901 The safeguards ventilation systems inspected were in good material condition with no deficiencies noted. The inspectors identified one minor USAR discrepancy which will be addressed by the license .,

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08 Miscellaneous Operations issues (92700, 92901)

0 Inspector Briefino at Licensee's Regiongl Power Distribution Control Center On January 14,1998, the inspectors and the regional branch chief visited the licensee's povmr distribution control center in downtown Minneapolis, Minnesota. The licensee was part of the Mid-Continent Area Power Pool and the control center managed power trar.sfers within the pool as well as local distribution The inspectors gained an understanding of regional electrical grid stability issues and the reliability of offsite power sources for both the Prairie Island and Monticello Nuclear Generating Plants. The inspectors observed control center operations and questioned corporate staff on the potential effects of deregulation on grid operation .2 (Closed) Violation 50-282/96014-02(DRP)* Failure of Operators to Follow Surveillance Procedure During Diesel Generator Testing; (Closed) Violation 50-282/97005-01(DfiP): 50-306/97005-01(DRP): Failure of Operators to Follow Procedures: Filling the Safety injection Accumulators in a Mode not Allowed by the Procedure and Improper Valve Operation While Performing Reactor Coolant System Leakage Test; (Closed) Violation 50-306/97006-02(DRP): Two Examples of Operators Failing to Follow Procedures: Did not Establish Prescribed Reactor Coolant System Vent Path and Valve Tagging Error; (Closed) Violation 50-306/97009-01a(DRP): Failure of Operators to Follow Procedure for Placing a Mixed Bed lon Exchanger in Service Resulting in a Reactivity Addition; (Closed) Violation 50-282/97009-01d(DRP): Failure to Follow Procedure for a Change to ,

a Work Package During Post-Maintenance Testing; and l

(Closed) Violation 50-306/97015-02(DRP): Failure to Follow Procedure for Rod Position Verification Surveillance Tes All of the violations listed above involved operators failing to follow procedures during i maintenance, surveillance testing, or operational activities, and all happened within a ,

relatively short period of time. As documented in the associated inspection reports, the I NRC became increasingly concemed with an adverse trend in procedure adherence during the first half of 1997. Two management meetings were held to discuss the subject ;

on May 20,1997, and November 25,1997. In those meetings licensee management presented their actions to date and future plans for improving performanc The inspectors verified that the specific corrective actions for each violation, as discussed in the associated licensee violation response letters, were completed. In addition, the inspectors periodically monitored the conduct of operations and surveillance testing since

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the corrective actions were impbmente Conclusion The inspectors noticed a significant increase in awareness on the part of operators to procedure adherence requirements. There have been numerous examples of operators stopping implementation of procedures to revise steps that were unclear or

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l could not be accomplished as written. In the last seven months, only one minor case of

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an operator failing to follow procedures was identified. Licensee corrective actions to improve operator procedure adherence appeared to be effectiv .3 (Closed) Licensee Event Report (LER) 50-306/97002 (2-97-02): 81[ Safety injection]

Discharge Valves to the RCS Closed When Above Cold Shutdown Because of -

Administrative Error. This event was previously discussed in Inspection Report No. 50-282/97005(DRP); 50-306/97005(DRP), Section 01.4. This event involved operators bnefly closing both Si to RCS isolation valves, in order to operate an 81 pump to All the Si accumulators, while in a condition in which TSs did not allow closing the valve The inspectors verified that the corrective actions discussed in the LER had been completed. The inspectors have observed increased sensitivity on the part of the operators to filling the Si accumulators before leaving cold shutdown conditions. The licensee developed Operating Procedures 1(2)C18, " Engineered Safeguards System Unit 1(2)," Revision 0, to give directions for filling the Si accumulators in each mode that i

could be accomplished within the TS requirements. This included a new instruction for gravity filling the accumulators from the refueling water storage tank when in the cold shutdown mode. The licensee completed Safety Evaluation Screening 205, " Gravity Filling SI Accumulator At Cold Shutdown," Revision 1, to verify that the evolution was not a change to the facility described in the USAR.

I in addition, licensee maintenance personnel configured a portable positive displacement pump and developed Maintenance Standards implementing Procedure 5002, Revision 0, to allow the accumulators to be filled in any plant condition without the use of the SI pumps or the need to isolate the Si injection valves. This system would only be used with a specific work order tailored to the plant conditions. The inspectors also observed an increased awareness among the operators that the time allowance in shutdown TS 3.0 C was not intended to be used as an allowed outage tim This event also was considered one example of a violation for failure to follow procedures (50-282/97005-01(DRP); 50-306/97005-01(DRP)). The violation is closed in Sec; ion 0 of this repor ll.Jialntenance M1 Conduct of Maintenance M1.1 General Comments inspection Scope (61726. 62707)

The inspectors witnessed all or major portions of the following maintenance and l l surveillance testing activities. Included in the inspection was a review of the surveillance procedures (SPs) and work orders (WOs) listed below as well as the appropriate USAR ;

sections regarding the activities. The inspectors verified that the surveillance procedures !

reviewed met the requirements of the TS .

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• SP 1110 Quarterly Testing of Turtaine Coolmg Water Header isolation Valves, Revision 37;

• SP 1047 Control Rod Exercise, Revision 27;

• SP 1102 11 Turbine-Driven Auxiliary Feedwater Pump Monthly Test, Revision 60;

• SP 1252 Unit 1 Post Loss of Coolant Accident Hydrogen Control System Valve Operation Test, Revision 14; )

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• SP 1307 D2 Diesel Generator Fast Start Test, Revision 16; f

. SP 1332 Safe Shutdown Emergency Light Verification, Revision 3;

• SP 1544 Containment At Power inspection - Unit 1, Revision 27;

• WO 9708325 Control Room Damper Leakage Test;

• WO 9713240 D2 Diesel Generator Bearing insulation Check;

• WO 9713686 Quarterly Cooling Valve Timing During SP 1307;

• WO 9800507 Check Valve 281-9-4, Low Head Safety injection to Reactor Vessel Nozzle, Body to Bonnet Leak; and

. WO 9800602 Resolve Relevant Indications on Safety injection Pip b. Observations and Findinos For the work observed, procedures were property used and followed Maintenance personnel were experienced and knowledgeable of their tasks. The inspectors noted frequent monitoring of the activities by system engineers. Noteworthy comments on

' specific work activities are discussed belo * On January 13,1998, the inspectors identifieMi that the source range nuclear instrument power level on meters 1N51B and 1N51C at the train A and B hot shutdown panels read approximately 10d counts per second (cps). Since Unit 1 was operating at 100 percent power, the indications should have read greater than 10* cps. The redundant control room indications from the same detectors read as expected. The inspectors brought the discrepancy to the attention of the Unit 1 control room operators and the system engineer. The system engineer

. Issued WO 9800212 to direct the investigation and repair the faulty hot shutdown ,

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panel source ranga indications. The source range indications were repaired and retumed to service on January 20,199 Abnormal Operating Procedure 1C1.3 AOP1, " Shutdown from Outside the Control :

Room - Unit 1," Revision 2, listed the action r.scessary to place Unit 1 in a hot !

shutdown condition followino a e%iioom evacuation. Stop 2.4.28 of the procedure directed tne reactor operators to monitor the source range nuclear 14 '

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Instrument indications at the hot shutdown panels to verify shutdown conditions, in the condition identified,1N51 would still have provided a qualitatNe indication of shutdown conditions but not an accurate indi stion of the actual source range neutron powerleve The inspectors identified that there were no routine surveillance test procedures to periodically check the indicators. The indicators were not required by TS to be "

in the calibration program. The licensee subsequently revised monthly surveillance procedures, SP 1222 (2222), " Event Monitoring Instrument Channel Check," Revision 14, to include checks of the hot shutdown panel source range powerindication * For SP 1110, the inspectors attended the pre-job briefing and monitored the entire ,

evolution from the control room. The briefing, conducted by the shift supervisor, was thorough and stressed contingency actions should cooling water be lost to

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the turbine during the performance of the test. The surveillance test was efficiently coordinated by an operator in the control room. The operator ensured three-way communications were used and that all persons involved with the surveillance test were kept informed of procedure steps as complete * Surveillance Procedure 1047, the test which was normally conducted while the reactor was subcritical, was modified to allow it to be done with Unit 1 at 100 percent power. The purpose of the test was tc identify whether the source of noise heard on the Unit 1 digital metal impact monitoring system was associated with control rod movement. The noise, first identified in mid-December 1997, was previously discussed in Inspection Report No. 50-282/97023(DRP);

50-306/97023(DRP), Section M1.1. During the test, control room distractions were minimized, close attention was paid to reactor power level, concise three-way communications were used, and all annunciators were announced by the reactor operator to the lead reactor operator and shift supervisor. The test results indicated that the noise was most likely associated with control rods but additional testing was planne * For WO 9800507, the work included replacing the gasket, nuts, and studs on l Check Valve 2SI-9-4 due to leakage. The work required the formation of a freeze ;

seal on a six-inch nominal diameter stainless steel pipe to isolate the check valve i from the reactor vessel. However, prior to forming the freeze seal,16 relevant ,

dye penetrant surface indications had to be buffed from tho surface of the pipe ;

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where the freeze seal would be formed (WO 9800602).

The inspectors examined the nondestructive examination (NDE) records associated with the dye penetrant inspection and visually examined the surface of the stainless steel pipe where the freeze seal would be formed following the i buffing operation. The inspectors also reviewed Maintenance Procedure D28,

" Freeze Plug Procedurei' Revision 6, and monitored its implementation. No discrepancies were note .

l Conclusions l

Maintenance and surveillance test activities were performed well with no discrepancies noted. However, examples of surveillance procedures needing improvement continued to j be identified as highlighted by the inspectors' identification of inaccurately indicating source range meters at the hot shutdown panel M1.2 Unit 2 Partial Lenath (P/L) CRDM Removal. NDE. and Repair i

i Inspection Scope (61726. 62707. 57080)

)

I Unit 2 was shut down on January 24,1998, due to a 0.2 gallon per minute reactor coolant j system (RCS) leak from a P/L CRDM G9 pressure boundary weld between the motor tube base and control rod center sections. The inspectors observed all or major portions

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of the subsequent maintenance, NDE, and repair activities concoming l P/L CRDMs G9,17, E7, and GS. Included in the inspection was a review of the following documents:

l . USAR Section 3.5.4.1, "CRDM Housing Mechanical Failure Evaluation,"

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Revision 8;

• SP 1001 AA, " Reactor Coolant System Leak Test," Revision 27; l

. SP 1544, " Containment At Power inspection - Unit 1," Revision 27;

. WO 9800572, " Weld Adapter Plug Replacement for P/L CRDM st G9";

e WO 9800573, " Weld Adapter Plug Replacement for P/L CRDM at 17";

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. WO 9800949, " Weld Adapter Plug Replacement for P/L CRDM at E7"; and

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. WO 9800950, " Weld Adapter Plug Replacement for P/L CRDM at G5."

! Observations and Findinos

' . On February 5,1998, tu inspectors attended the pre-job briefing and monitored portions of the cutting of the lower canopy seal weld on P/L CRDM G9. The

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system engineer presented a thorough briefing of the procedure to be use Contractor personnel performing the cutting operation also participated in the briefing and described the specialty tooling and methods to be used. Radiation protection personnel described radiation level gradients in the vicinity of the reactor vessel head and P/L CRDM, engineered ventilation systems setup to minimize airbome radiation levels, temporary shielding, and other practices to minimin radiation exposur During the cutting operation, the inspectors noted good supervision and involvement by the system engineer over the contractor performing the work. The inspectors examined the remote cutting tooling and control systems and

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monitored portions of the actual cutting operation. The cutting was carried out in a deliberate, controlled manner with no discrepancies noted by the inspector i.

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. On February 8,1998, P/L CRDM G9 was removed from the Unit 2 reactor vessel head and placed in ar' itwn area for ultrasonic test (UT) examination. A manual UT inspection was performed on the evening of February 8, by a licensee contractor qualified in Electric Power Research Institute intergranular stress corrosion cracking detection and sizing techniques. The inspectors interviewed the UT examiner on the moming of February 9, and loamed that two l circumferentially oriented, inside diameter (ID) indications were noted at '

approximately the cent 6r of the tapered section between the P/L CRDM motor tube base and center section. One indication was determined to be about 5 inches long while the second indication was approximately 3 inches lon ]

Radiographic test (RT) examinations on P/L CRDM G9 on February 9,1998, indicated about a 4.5-inch long circumferential indication corresponding to the 5-inch circumferential indication noted during the manual UT examination. The 3-inch circumferential indication was not visible by RT A visual test (VT) !

examination was performed on P/L CRDM G9 on the evening of February 1 The VT examination was performed without magnification and used hand-held mirrors and flashlights to view the inside diameter surface of the weld area. The VT examination revealed a circumferentially oriented linear indication approximately 250 degrees around the inside circumference of G9. The VT indication corresponded to the 5-inch and 3-inch indications noted during the manual UT examination, j

• While removing interference fro,7 the Unit 2 reactor vessel head area on j February 10,1998, the licensee dropped an individual rod pon,ition indication (IRPI) coil stack housing approximately 8 to 10 inches. The IRPI coil stack was being lifted from the CRDM housing when the drop occurred. The IRPI coil stack housing dropped back onto its normal seating location. The licensee issued Nonconformance Report 19980230 and commenced an Error Reduction Task Force investigation for the everi . On February 11,1998, the inspectors accompanied operations and engineering personnel on a Unit 1 containment inspection while at power in accordance with SP 1544. Both the RCS system engineer and the inspectcrs examined the reactor vessel head area at a distance of 20 to 40 feet with a pair of binocular No indications of RCS boundary leakage were evident from any P/L or full length CRDM. Radiation protection personnel followed good dose reduction practices and frequently directed licensee personnel and the inspectors to areas with the lowest radiation dos . On the evening of February 11,1998, the inspectors witnessed the manual UT examination of the second P/L CRDM (17) removed from the Unit 2 reactor vessel head. The inspection was performed by the same licensee contractor who performed the manual UT examination on P/L CRDM G9. The inspectors witnessed the entire UT scanning evolution and determined that the methods, tools, and techniques used during the examination were adequate. No flaws were identified by the licensee contracto l

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The licensee performed VT and surface fluorescent examinations on the ID surface of P/L CRDM 17 on February 12,1998. No linear surface indications were identifie . The inspectors witnessed cutting operations during removal of P/L CRDMs G9,17, E7, and G5. In all cases, the licensee maintair.ed good control of the contractor personnel performing the cutting operations. Licensee system engineers provided continuous coverage of the work and maintained a questioning attitude towards the contractor's processes. The inspectors observed the remove! of P/L CRDM G5 from the reactor vessel head and subsequent lifting to an adjacent laydown area. Foreign material controls were property implemented by placing a cover over the open G5 penetration as soon as the ,

P/L CRDM was lifted clear of the reactor vessel hea . The inspectors witnessed the manual UT examinations of P/L CRDMs E7 and G5 on February 13 and 14,1998, respectively. The examinations were performed by a licensee-qualified Levei lll UT examiner. A calibration block matching the tapered geometry of the P/L CRDM was not available for these examination Instead a standard Rhompas block was used and the oscilloscope screen was set !

up for 2.5 inches of sound travel in the metal. The inspectors reviewed 'he I calibration used for the manual UT examinations and found the calibrawn suitable for qualitative UT results providing an interrogation of the ID surface of the part A calibration block matching the tapered geometry of the P/L CRDM became available on February 15,1998, and the manual UT examination of P/L CRDM G6 was repeated. No flaws were noted by the examiner for either P/L CRDM E7 or i G j i

A second weld existed on each P/L CRDM tube located on the motor tube center

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section, soproximately two feet above the defect area on P/L CRDM G9. Tnis weld was also examined by manual UT methods to help determine if the defect in l

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the motor tube base was of a generic nature. No UT indications were notsd in any of the second welds in P/L CRDMs G9,17, E7, or G I

. The licensee had an offsite vendor fabncate four threaded head adapter plugs to cap the head tubes where the P/L CRDMs were removed. Since the vendor did not have a qualified quality assurance program licensee quality services personnel provided the oversight of the fabrication proces I

. The inspectors witnessed portions of the seal welding of the adapter plugs to the head tubes in locations 17 and G5 on February 17 and 19,1998. An automated tungsten inett gas process was used to place a fillet weld between the lower surface of the plug and the tube. The inspectors noted good control of the welding process by the licensee contractor. Weld interpass temperatures, the number and cucumferential orientation of specifir weld passes, and machine travel speeds were recorded by the contractor. Wold records, including current, voltage, and weld wire feed rates, were property maintained. The molten weid pool was well controlled even though one leg of 'he weld was vertical and the other leg inverted. System engineering and quality services (quality assurance)

personnel closely monitored the processe i

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. The affected section of P/L CRDM G9 was sent, as soon as it was available, to a l vendor laboratory for detailed metallurgical examinations and root cause l determination of the leak. Licensee engineering personnel were actively involved l in reviewing and approving the vendor's plans for those examinations. Other P/L '

CRDM sections were also sent to the vendor after they were removed. At the l conclusion of the inspection period, final laboratory results were not yet available. l

. On February 20,1998, the NRC Office of Nuclear Reactor Regulation requested that the Westinghouse Owners Group Regulatory Response Team be activated to re;iew the generic implications of the significant weld defect in the RCS pressure j boundar i Conclusions Following the identification of a leak on Unit 2 P/L CRDM G9, removal, NDE, and repair activitics associated with all of the Unit 2 P/L CRDMs were conducted well. The methods, tools, and techniques used during the NDE examinations were adequate for the inspections performed. The licensee established an effective task force to manage Unit 2 P/L CRDM repairs. The task force developed removal procedures, examination plans, j design changes for replacing the CRDMs with threaded plugs, and root cause determination plans. The task force also produced operability evaluations, interacted frequently'with the NRC, and helped plan the maintenance of reactor conditions such as i water level, boron concentration, and boundary control throughout the effort. Contractors were careful ly supervised by system engineers and performed P/L CRDM removal and repairs in a deliberate, controlled manner. Quality services oversight of the project was !

goo i M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Maintenance Backloas l Inspection Scope (92902)

The inspectors periodically monitored the backlog of ma!ntenance work orders with emphasis on control room problems. The inspectors evaluated whether the backlog appeared to be under control and whether sufficient attention was given to resolving operationalissue Observations and Findinas i The most recent data available to the inspectors indicated the following;

. The total non-outage work order backlog remained fairiy steady at about 1100 items. Corrective maintenance represented only a small frac * ion of that total because work orders were written for all corrective, prcdictive, preventive, and ;

minor maintenance, as well as for surveillance tests and modifications. The number of non-outage work orders had not varied more than about plus or minus 10 percent in the previous 12 months, indicating that work was not accumulatin .,  !

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. The total non-outage power block equipment corrective maintenance work orJer backlog was about 70 items. That number included 4 Priority 1 (repair within 3 days) and 33 Priority 2 (repair within 3 weeks) items. The correc0ve - I maintenance backlog represented only about 2 to 3 weeks of work at the typical j completion rat !

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. There were a total of 39 control room deficiencies, as indicated by a count of l

" work requested" tags found in the control room. These deficiencies included l annunciator, instrumentation, control, and computer problems sad were a mix of outage and non-outage work, as well as problems needing modifications to resolve. The inspectors determined that most of the problems were mino Operators typically made significant control room deficiencies into Priority 1 work orders, which were typically resolved within three day . There were 12 operator workaround problems that required compensatory operator schons or complicated the response to events. Many of them 'were long-terin issues that would require design changes to resolve. The inspectors determined that one problem had already been remedied and was in an evaluation penod, three were expcoted to be resolved in the first half of 1998, one was expected to be resolved in the next refueling outage for each unit, and the other seven were scheduled to have resolution plans developed for them in the j first quarter of 1998. Operator input was frequently solicited to identify new j operator workarounos and the problems received significant management i attentio )

. There were only five installed temporary modifications. Two of those modifications were for temporary instrumentation to measure the efficiency of the new Unit 1 turbine !

- General material condition of the plant was excellent and unexpected entries into ;

TS Limiting Conditions for Operation (LCOs) due to equipment problems were

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infrequent. During the 6-week inspection period there were 10 LCO entries due to )

equipment issues on Unit 1 and Unit 2. Three were as a result of the loss of the 10-bank transformer, discussed in Sections 01.1 and M3.1 of this report, rad three were the result of special testing of the control room ven'ilation dampers discussed in Section E8.5 of this report. All equipment issues resulting in LCO entrics were rapidly addressed and the LCOs exited well before the expiration of )

the associated time limit !

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. In 1997, preventative maintenance and surveillance test activities were performed within the TS-cIlowed time periods. Uncompleted surveillance test activities neasing the overdue dates were closely tracked by the scheduling office and reviewed by supervisors dail * Repeat work orders to re-perform the same work due to inadequate maintenance were ras On average, only about one repeat work order was generated per mont '

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! Q20.glugl i9na The backlog of corrective maintenance work orders was relatively small and stabl j Priority work and control rc :n deficiencies received adequato attention. Equipmen, i failures which lead to TS Luos were infrequent and rapidly resolved. There were very j few temporary modifications in place. Work was completM in a timely manner and was generally done correctly the first time. Operability decisions because of degraded equipment were conservatively made. Overall, a revie)v of the maintenance backlog indicated a strong maintenance program that was receiving suitable management attentio M3 Maintenance Procedures and Documentation M3.1 Lockout of 10 Transformer due to inadeauste Mai'denance Procedure l Inspection Scope (92902)

I As discussed in Section 01.1 of this report, the licensee experienced a lockout of the I 10 transformer during maintenance activities in the substation. The inspectors reviewed l the circumstances of the event and reviewed the following documents as part of this ;

Npection: l

. WO 9800310, " Isolate Breaker 1H3";  ;

. USAR Section 8, " Plant Electrical Systems," Revision 14; and

. Licensee Event Report (LER) 2-98-01, " Lockout of No.10 Transformer Resulting in Auto Load Rejection / Restoration on Safety-related Bus." Observations and Findinos On January 17,1998,13.8-kilovolt (KV) substation breaker 1H3, one of the supplies to the Prairie Island Training Center, locked out due to a ground fault during construction work in the Training Center. The system engineer decide (' to leave the breaker open and not reset the ground fault trip until an investigation of the Ouse could take place. On January 21,1998, the system engineer issued WO 9800310 to isolate the 1H3 breaker as part of the investigation. In order to prevent accidental closure of the breaker while opening the manual disconnect switches on both sides of the breaker, one of the first steps in the work order was 16 open the direct current (DC) supply knife switch in the breaker. Securing DC control power was a common prw;tice when isolating substation breaker For all of the other 13.8-KV substation breakers, the steps in the work order procedure would have worked. However, unknown to the system engineer, the 1H3 breaker protection scheme was different than the rest of the substadion breakers. In all of the breakers, a ground fault should immediately trip open the affected breaker. If the breaker still had a closed indication after the ground fault, the supply source would lockout

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because it would be an indication that the normal protection scheme had failed to

! operate. For all the othx substation breakers, the " breaker closed" indication came from l mechanical auxiliary switches operated by actuct breaker position. However, for the

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1H3 breaker, the closed indication came from a DC-powered relay which failed ta the

" breaker closed" position on loss of power. Thus, when DC power was removed from the 1H3 breaker, the protection scheme saw the condition as a closed breaker with a ground

, fault and locked out the supply, which was the 10 transformer. That caused a temporary l

loss of one of the 4-KV safeguards buses on Unit 2 as discussed in Section 01.1 of this report.

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l The inspectors interviewed the system engineer who wrote the work order. He stated that he had not known about the difference between the 1H3 breaker and the rest of the substation breakers. Furthermore, he stated that he wrote the steps in the wd order based on his experience with the other breakers and had not adequately reviewed the 1H3 logic. The 1H3 breaker was not a safety-related component so the work order was i not required to have an independent technical revie Criterion V of Appendix B of 10 CFR Part 50 requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances. Work Order 9800310, " Isolate Brea*Ur 1H3," was not appropriate for the circumstances because Step 7.2 directed that the DC supply knife switch in the breaker be opened while a ground fault trip signal was still presen Performing the work order step resulted in a temporary loss of safeguards Bus 26 and an unnecessary challenge to an engineered safety feature system. This was a violation l (50-306/98003-02(DRP)).

The licensee assigned its Error Reduction Task Force to conduct an investigation of the event and recommend corrective actions. That investigation was not complete at the conclusion of the inspection period but some corrective actions had already been take Work control procedures were revised to require a detailed second-level engineering review for all plant work oMers for substation equipment under the jurisdiction of the plan Although this event was self-revealing and the cause was licensee-identified with corrective actions being taken, enforcement discretion was not granted because the challenge to the engineered safety feature systems was considered if more than minor safety significance. In addition, there were three other recent events in which an inadequate review of the logic circuits resulted in problema during the conduct of infrequent or first-time maintenance activities. Those events were previously discussed l in inspection Reports Nos. 50-282/96010(DRP); 50-306/96010(DRP), Section M3.3; ,

l 50-282/97011(DRP); 50-306/97011(DRP), Section M3.1; and 50-282/97023(DRP); i

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50-306/97023(DRP), Section M1.1. The events resulted in two non-cited violations and one cited violation of NRC requirement The licensee issued LER 2-98-01 for this event. The LER is closed in Section M8.2 of this repor c. Conclusions An inadequate review of the 1H3 breaker protection logic led to an angineered safety l-feature system actuation during a non-routine maintenance activity. The event was the fourth documented case in a little over a year in which an inadequate review of logic circuits led to problems during maintenance or testing activities. All of the events were

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either first time evolutions or infrequent and emergent work activities. A violation was kentified for failure to provide an appropriate work orde M8 Miscellaneous Maintenance Activities (92700,92902)

M8.1 (Closed) Violation 50-282/97009-01b(DRP): Inadequate Procedure for Restoring System to Service Resulting in Reactivity Addition; and (Closed) Violation 50-282/97009-01c(DRP): Inadequate Procedure for Diesel Generator Post-Maintenance Testin These issues were two examples of a four-part violation for failure to follow procedures and inadequate procedures. Examples "a" and "d" of the violation were closed in Section 08.2 of this report. The inspectors verified that the corrective actions discussed in the licensee's violation response letter were also completed for examples "b" and "c" of l the violatio M8.2 (Closed) LER 50-306/98001 (2-98-01): Lockout of No.10 Transformer Resulting in Auto Load Rejection / Restoration of Safety-Related Bus. This event was discussed in Section 01.1 and M3.1 of this report. A violation (50-306/98003-02) was issued for the inappropriate procedure that led to the event. The corrective actions discussed in the LER will be reviewed when the violation is closed so the LER is closed to avoid duplicate tracking of the issu Ill. Enaineerina E2 Engineering Support of Facilities and Equipment E Review of Updated Safety Analysis Report (USAR) Commitments (37551. 92903) ,

l While performing the inspections discussed in this report, the inspectors reviewed the '

applicable portions of the USAR that related to the areas inspected and used the USAR as an engineering / technical support basis document. The inspectors compared plant practices, procedures, and/or parameters to the USAR descriptions as discussed in each section. The inspectors verified that the USAR wording was consistent with the observed plant practices, procedures, and parameters. The inspectors identified one discrepancy which is discussed in Section O2.1 of this repor E8 Miscellaneous Engineering issues (92700,92903)

E (Closed) Inspection Followuo item (IFI) 50-282/96008-03(DRP): Error in USAR Description of Fire Protection Actuation Switches. This issue was previously discussed in Inspection Report No. 50-282/96008(DRP); 50-306/96008(DRP), Sections M1.1 and E It involved a minor error in a system description in the USAR. The inspectors reviewed licensee records and verified that the error had been entered in the licensee's tracking

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system, as part of its ongoing USAR review project, for correction in the next USAR l

updat . . . .. .. .

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.o E8.2 (Closed) Unresolved item (URI) 50-282/97002-02(DRP): 50-306/97002-02(DRP)- i Question Regarding Whether Surveillance Testing of the Cooling Water Pumps Fulfills a )

TS Requirement. This issue was previously discussed in Inspection Report l No. 50-282/97002(DRP); 50-306/97002(DRP) Section M1.1. The inspectors questioned I whether the licensee's practice of conducting the required monthly tests of the diesel-driven cooling water pumps by simulating a low header pressure met the TS 4.5.0.1.b requirement for a " manually-initiated start of each diesel engine."

By NRC letter dated January 28,1998, from Cynthia A. Carpenter, Acting Director, Project Directorate lil-1 to Geoffrey Grant, Director, Division of Reactor Projects, Region 111, the NRC determined that the requirement was ambiguous in that the TS did not define the term " manually-initiated." The NRC also agreed with the licensee that starting the pumps using the low pressure method once a year would be beneficif ia ,

demonstrating that the design basis of the system was met. The NRC recommended that

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the licensee' revise the TS to clarify or change the testing requirement but determined that enforcement was not appropriate due to the lack of safety significance and the ambiguity !

of the TS requiremen i E8.3 (Closed 4tf 50-282/97011: 50-306/97011 (1-97-11): Failure to Test the Low Pressure Auto-sted Function of 121 Motor Driven Cooling Water Pump and inadequate Separation Between Trains A and B Low Pressure Auto-start Switches. This licensee-;dentified finding was previously discussed in Inspection Report 50-282/97018(DRP);

50-306/97018(DRP), Section E1.1. The inspectors verified that the corrective actions ;

discussed in the LER, to revise the pump's surveillance test procedure to include the low l pressure auto-start feature and to complete a design change to separate the pressure

- switches, were complete ;

E8.4 (Closed) LER 50-282/97016: 50-306/97016 (1-97-16): Reactor Coolant Pump Lube Oil Lift Pump Oil Leak Collection System Design Not in Compliance with 10 CFR Part 50, Appendix R, Section Ill.O. This licensee-1dentified finding was previously discussed in inspection Report No. 50-282/97021(DRP); 50-306/97021(DRP), Section E2.1. The inspectors verified that the corrective actions discussed in the LER, to install seismically qualified splash shields over each of the reactor coolant pump oil lift pumps in Unit 1 and Unit 2, wens complete E (Open) URI 50-282/97015-04(DRP): 50-306/97015-04(DRP): Control Room HabMability Evaluation. This issue was previously discussed in Inspection Report No. 50-282/97015(DRP); 50-306/97015(DRP), Section E2.2. It involved several con : ems with control room habitability including the amount of in-leakage into the control room ventilation envelope during accident conditions. During this inspection period, the licensee conducted a series of leakage tests on individual control room ventilation dampers to assess overall envelope tightness. The results of the testing indicated that the pon ntial in-leakage into the control room envelope was greater than design assumptlens from both steam exclusion and dose control standpoints. The results were reported by the licensee in LERs 50-282/98001; 50-306/98001 (1-98-01) and 50-282/98002; 50-306/98002 (1-98-02). The LERs reported that, although design assumptions cou!d have been exceeded, the coritrol room would probably have remained habitable. Confirma;ory calculations were in progress. The unresolved item will remain open pending the inspectors' review of the final habitability analysis. The LERs will also remain open pending completion of the individual corrective action i

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! E8.6 (Open) LER 50-282/98001: 50-306/96001 (1-98-01): Leakage Through Redundant Control Room Steam Exclusion Dampers Found to Exceed Value Assumed in the High j Energy Line Brr k Analysis. This LER was discussed in Section E8.5 of this repor E8.7 (Open) LER 50- U/98002: 50-306/98002 (1-98-02): Control Room Unfiltered Air in-leakage Found to be Excessive. This LER was discussed in Section E8.5 of this repor E (Ocen) LER 50-282/98003: 50-306/98003 (1-98-03): Routing of Containment Dome Fan Coil Unit Exhaust Dam #rs' Control Circuit Wiring Contrary to Configuration Described in I USAR. This LER was discussed in Section E7.1 of this repor I IV. Plant Support R1 Radiological Protection and Chemistry Controls (71750)

The inspector; observed sev3ral instances of good radiation control practices to maintain dose as low as reasonably achievable during the Unit 2 partial length control rod drive mechanism l repairs. Control rod drive mechanism stub tubes were wrapped with 5tted lead sheets, !

temporary shielding was hung in four locations around the reactor vessel head minimizing l exposure to contractor personnel witnessing cutting operations, and health physics personnel l made good use of remote dosimetry monitoring devices. The inspectors observed four instances ;

where health physics personnel effectively utilized remote dosimetry monitoring devices, telling l contractor personnel to move to lower dose aress, while still allowing them to accomplish the ,

assigned work tas l V. Manaoement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on February 24,1998. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie l

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PARTIAL UST OF PERSONS CONTACTED l

License.1 i

l J. Sorensen, Plant Manager

. K. Albrecht, Geneml Superintendent Engineering, Electrical / Instrumentation & Controls T. Amundson, General Superintendent Engineering, Mechanical J. Goldsmith, General Superintendent Engineering, Generation Services J. Hill, Manager Quality Services G. Lenertz, General Superintendent Plant Maintenance J. Maki, Outage Manager D. Schuelke, General Superintendent Radiation Protection and Chemistry l T. Silverberg, General Superintendent Plant Operations M. Sleigh, Superintendent Security l

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INSPECTION PROCEDURES USED

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' IP 37551: Engineering L IP 57080: Nondestructive Examination Procedure Ultrasonic l lP 61726: - Surveillance Observations

! IP 62707: . Maintenance Observations

? IP 71707: - Plant Operations -

IP 71714:- Cold Weather Preparations

~ IP 71750: Plant Support Activities IP 92700: Onsite Follow-up of Written Reports of Non-routine Events at Power Reacto Facilities i

- IP 92901: Follow up - Operations -

- lP.92902: Follow up - Maintenance IP 92903: Follow up - Engineering ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-282/98003-01(DRP) NCV Failure to Install Remote Radiation Monitor Readout as 50-306/98003-01(DRP) Described in the Updated Safety Analysis Report 50-306/98003-02(DRP) VIO Inappropriate Work Order Procedure for Substation Work Resulted in an Engineered Safety Feature System Actuation 50 282/98001 (1-98-01) LER Leakage Through Redundant Control Room Steam 50-306/98001 Exclusion Dampers Found to Exceed Value Assumed in the High Energy Line Break Analysis 50-282/98002 (1-98-02) LER Control Room Unfiltered Air In-leakage Found to be 50-306/98002 Excessive 50-282/98003 (1-98-03) LER Routing of Containment Dome Fan Coil Unit Exhaust 50-306/96005 Dampers' Control Circuit Wiring Contrary to Configuration Described in Updated Safety Analysis Report Closed 50-282/96006-03(DRP) IFl Error in Updated Safety Analysis Report Description of Fire Protection Actuation Switches

- 50-282/96014-02(DRP) VIO Failure of Operators to Follow Surveillance Procedure During Diesel Generator Testing 50-282/97002-02(DRP)- URI Question Regarding Whether Surveillance Testing of the

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50-306/97002-02(DRP) Cooling Water Pumps Fulfills a TS Requirement l

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l 50-282/97005-01(DRP) VIO Failure of Operators to Follow Procedures: Filling the I l 50-306/97005-01(DRP) Safety injection Accumulators in a Mode Not Allowed by the i

! Procedure and improper Valve Operation While Performing !

Reactor Coolant System Leakage Test l 50-306/97006-02(DRP) VIO Two Examples of Operators Failing to Follow Procedures:

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Did Not Establish Prescribed Reactor Coolant System Vent i'

Path and Valve Tagging Error 50-306/97009-01a(DRP) VIO Failure of Operators to Follow Procedure for Placing a ,

l Mixed Bed lon Exchanger in Service Resulting in a l Reactivity Addition 1 50-282/97009-01b(DRP) VIO Inadequate Procedure for Restoring System to Service Resulting in Reactivity Addition j

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50-282/97009-01c(DRP) VIO Inadequate Procedure for Diesel Generator Post-Maintenance Testing 50-306/97009-01d(DRP) VIO Failure to Follow Procedure for a Change to a Work Package During Post-Maintenance Testing 50-306/97015-02(DRP) VIO Failure to Follow Procedure for Rod Position Verification !

Surveillance Test i 50-306/97002 (2-97-02) LER Safety injection Discharge Valves to the Reactor Coolant ,

System Closed When Above Cold Shutdown Because of l Administrative Error i 50-306/97005 LER Sudden Pressure Lockout of No.10 Transformer Resulting in Auto Load Rejection / Restoration on Safety-Related Bus .

50-282/97011 (1-97-11) LER Failure to Test the Low Pressure Auto-start Function of 121 j 50-306/97011 Motor Driven Cooling Water Pump and Inadequate *

Separation Between Trains A and B Low Pressure Auto-start Switches l

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50-282/97016 (1-97-16) LER Reactor Coolant Lube Oil Lift Pump Oil Leak Collection 50-306/97016 System Design Not in Compliance with 10 CFR Part 50, Appendix R, Section 11 /98001 (2-98-01) LER Lockout of No.10 Transformer Resulting in Auto Load Rejection / Restoration of Safety-Related Bus l

Discussed j URI Control Room Habitability Evaluation  !

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50-282/97015-04(DRP)

50-306/97015-04(DRP) )

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( UST OF ACRONYMS USED CFR Code of Federal Regulations cps Counts Per Second j CRDM Control Rod Drive Mechanism 4 DC Direct Current -

DRP Division of Reactor Projects ,

DRS Division of Reactor Safety . )

EA Enforcement Action l ESF Engineered Safety Feature I

'F Degrees Fahrenheit FSAR Final Safety Analysis Report i

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10 Inside Diameter IFl Inspection Followup item IP Inspection Procedure IRPl individual Rod Position Indication KV Kilovolts LCO Limiting Condition for Operation LER Licensee Event Report NCV Non-cited Violation NDE Nondestructive Examination NRC Nuclear Regulatory Commission PDR Public Document Room P/L Partial Length RCS Reactor Coolant System l RT Radiographic Test SE Safety Evaluation SI Safety injection SP Surveillance Procedure l SWI Section Work Instruction

! TP ' Test Procedure  !

l TS Technical Specification URI Unresolved item l

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USAR Updated Safety Analysis Report UT Ultrasonic Test VIO Vmlation VT Visual Test WO Work Order

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