IR 05000220/1999006

Insp Repts 50-220/99-06 & 50-410/99-06 on 990620-0731.NCVs Noted.Major Areas Inspected:Licensee Operations,Engineering, Maint & Plant Support

ML20212C604
Person / Time
Site:	Nine Mile Point
Issue date:	09/14/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17059C775	List: IR 05000220/1999006
References
50-220-99-06, 50-410-99-06, NUDOCS 9909220044
Download: ML20212C604 (85)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket / Report Nos.: 50-220/99-06 I 50-410/99-06

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i License Nos.: DPR-63 NPF-69 Licensee: Niagara Mohawk Power Corporation

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P. O. Box 63 )

Lycoming, NY 13093 )

i Facility: Nine Mile Point, Units 1 and 2 Location: Scriba, New York Dates: June 20,1999 - July 31,1999 Inspectors: G. K. Hunegs, Senior Resident inspector W. L. Schmidt, Senior Resident inspector, Three Mile Island J. M. Trapp, Senior Reactor Analyst R. L. Fuhrmeister, Engineer, Division of Reactor Safety (DRS)

S. K. Chaudhary, Engineer, DRS R. A. Fernandes, Resident inspector ,

Approved by: Michele G. Evans, Chief Projects Branch 1 Division of Reactor Projects 9909220044 990914 PDR ADOCK 05000220 g PM

O EXECUTIVE SUMMARY Nine Mile Point Units 1 and 2 50-220/99-06 & 50-410/99-06 June 20,1999 - July 31,1999 This special inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covered a six-week perioi ef inspection by the residents and region based inspectors. The inspections focused on activities associated with and following the Unit 2 automatic reactor shutdown which occurred on June 2 Operations On June 24, an automatic reactor shutdown from 100 percent power occurred at Unit 2 during maintenance on the feedwater control system. Operators placed the plant in a stable condition; overall, operator performance was adequate. Several equipment performance problems, combined with an off-normal plant electrical lineup, resulted in increased challenges to plant operators. (Section 01.2)

The reactor restart on June 30 was conducted in a conservative, well controlled manner and

. effective supervision and oversight was noted in addressing equipment performance problem In contrast, during the July 23 startup, operators energized the normal station service transformer without cooling water. This error was caused, in part, by an inadequate operating procedure and by the operators' poor response to the associated transformer alar (Section 01.3)

Several aquipment problems associated with the reactor core isolation cooling (RCIC) system were evident during system operation subsequent to the June 24 automatic reactor shutdown at

- Unit 2. These degraded equipment conditions resulted in the control room staff declaring the RCIC system inoperable per Technical Specifications, but operators were able to compensate for these conditions and successfully operated the system to maintain reactor vessel leve These compensatory actions, collectively, were a distraction to the control room staff during the recovery from the automatic shutdown. (Section O2.1)

During the recovery from the June 24 automatic reactor shutdown, the control room staff operated the reactor core isolation cooling (RCIC) system with the flow controller in manua The RCIC system operating and alarm response procedures contained some inconsistencies regarding operating the system in this mode, but operators were able to use their system i knowledge to adequately maintain reactor vessel level. The licensee's July 13,199g, evaluation l of operator performance adequately identified and resolved the RCIC system operating .

I procedure issues and was reasonably thorough and critical in assessing operator performanc The licensee acknowledged that their process to evaluate operator performance following a major plant event warranted improvements to ensure timely and effective corrective actio (Section 03.1)

The documentation and communication between the crews of the reactor core isolation cooling (RCIC) system controller issues were poor following the June 24 automatic reactor shutdow il .

Executive Summary (cont'd)

Specifically, operator logs did not contain any information regarding the RCIC controller problems and the observed problems were not verbally, or in the operator turnover sheets, communicated to the oncoming shift. Additionally, operators exercised poorjudgement by placing the RCIC controller in automatic to validate previously confirmed improper system performance. (Section 04.1) -

Maintenance During the conduct of maintenance at Unit 2, a faulty manual control circuit in the feedwater controller failed which resulted in a reactor vessel level transient and caused an automatic reactor shutdown. Plant conditions were acceptable to perform the maintenance. However, the pre-job brief was limited, in that, it did not discuss the potential consequences of a controller failure. (Section M1.1)

A relay failure in the main generator backup protection circuit resulted in a partial loss of off-site power following the automatic reactor shutdown at Unit 2 and additional challenges to plant operators.' 'NMPC's investigation into and identification of the cause was thorough. Although not a direct contributor to the relay failure, the investigation showed that certain recommended substation breaker preventive maintenance was not being performed by the off-site

- maintenance group. (Section M2.1)

During the June 24 automatic reactor shutdown and again on July 2, the reactor core isolation

. cooling system injection containment isolation check valves exhibited a number of performance problems. ' The valves remained operable, but were degraded. Ineffective corrective actions contributed to the valves' poor operating history. Additionally, the installation of a modification to the indicator shaft was not implemented in a timely fashion. (Section M2.2)

During the Unit 2 forced outage, position indication problems with the residual heat removal-system containment isolation check valve (AOV398) were repaired and the valve was tested satisfactorily. Subsequently, AOV39B failed to close when shutdown cooling was secure Previous poor maintenance practices, including weak valve maintenance procedures contributed to the valve failure. (Section M2.3)

During the June 24 automatic shutdown transient at Unit 2, the reactor core isolation cooling I (RCIC) system exhibited 200-300 gallon per minute flow oscillations with the controller in I automatic. NMPC investigation showed that the flow controller had not been properly adjusted j when it was replaced in 1996, in spite of available industry information on proper controller set- !

up.; The controller out-of-adjustment condition, in conjunction with some air in the flow ,

transmitter sensing lines, caused the flow oscillations. The failure to have appropriate l procedures for tuning and calibration of the RCIC system was a non-cited violation and the result of past poor quality maintenance. (Gection M3.1)

Following the June 24 automatic reactor shutdown and manual initiation of the reactor core isolation cooling (RCIC) system, operators identified that the lube oil level was not visible in the sight glass. The low oil level was the result of oil not being added following an oil sample being lii '

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Executive Summary (cont'd)

taken. Subsequent lube oil analysis showed that there was no RCIC system degradatio NMPC revised the RCIC oil sample procedure to assure that proper oil level is maintaine (Section M3.2)

Prior to July 2, troubleshooting efforts associated with the reactor core isolation cooling valve repair were poor, in that, logs did not fully reflect work done and the valve status was not adequately communicated to the oncoming shift. This resulted in the determination that the root cause of the problem had been found and that the valve had been repaired, when in fact, it was not. Unit 2 management and staff demonstrated poorjudgement by rationalizing the anomalies associated with the valve maintenance as acceptable, rather than thoroughly investigating and resolving them. (Section M4.1)

' Prior to the reactor core isolation cooling injection valve failures on July 2, the corrective actions to address valve performance deficiencies were narrowly focused. NMPC subsequently assembled a team which developed the root causes of the poor valve operating history and implemented appropriate corrective actions to resolve the technical problems. (Section M7.1)

Maintenance and engineering staff performance associated with the Anchor / Darling testable check valves was weak.. A significant number of position indication problems due to mechanical interferences or mis-adjustments were documented and this negative equipment performance trend was not earlier recognized or evaluated. A timely installation of an approved 1992 modification would have prevented the improper reassembly of the RCIC system in;ection check valve in 1998. (Section M7.1)

The Unit 2 reactor core isolation cooling system reliability and performance was degraded as a result of weaknesses in maintenance and engineering support. (Section M7.2)

Enoineerina NMPC assumptions used to develop the iridividual plant examination for the frequency of loss of offsite power were not consistent with operating experience. NMPC updated its probabilistic risk analysis model and has submitted a revised individual plant examination to the NR (Section E1.1)

The failure rate data evaluation methodology used in the Nine Mile Point Unit 2 probabilistic risk analysis (PRA) for the reactor core isolation cooling (RCIC) system was appropriate. The PRA assumptions regarding the loss of offsite power were consistent with plant operating practice There was an increase in core damage frequency caused by the RCIC system malfunctions following the April 24,1999, scram. The availability of multiple redundant systems to provide makeup to the reactor vessel mitigated the risk significance of this event. The RCIC system operation in the manual mode following the June 24 scram had an almost negligible effect on the core damage frequency. However, the aggregate of equipment malfunctions associated with the June 24 scram and the April 24 scram have risk significance and both scrams are being

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considered for inclusion in the NRC accdent sequence precursor program. (Section E2.1)

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Executive Summary (cont'd)

Misapplication ofindustry guidance during the development of the second ten-year intervai inservice testing (IST) program at Unit 2 resulted in improperly deleting the requirement to conduct IST testing for 26 safety related valves. The valves were subsequently tested satisfactorily. Failure to conduct the required testing was a non-cited violation. (Section E2.2)

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TABLE OF CONTENTS

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page EXECUTIVE SUM MARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii

- TABLE OF CONTENTS . . . . . . , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. .vi Summary of Plant Status . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1. Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..................... 1 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 O1.1 General Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 l 01.2 Automatic Reactor Shutdown Overview (Unit 2) . . . . . . . . . . . . . . . . . 1 l 01.3 Reactor Startup Observations (Unit 2) . . .. . . ..................3 l O2 Operations Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . . . . 4 O2.1 RCIC System Performance During the Automatic Reactor Shutdown ( U n it 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 1 03 . Operations Procedures and Documentation . . . . . . . . . . . . , . . . . . . . . . . . . . 5 L 03.1 Operator Scram Response and Use of RCIC Operating Procedures ( U nit 2 ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . 5 04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 04.1 Event Log-keeping and Shift Turnover (Unit 2) . . . . . . . . . . . . . . . . . . 7 08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 l 08.1 (Closed) Licensee Event Report (LER) 50-410/99-10: Unit 2 Reactor Trip l due to a Feedwater Master Controller Failure. . . . . . . . . . . . . . . . . . . 7 I I . Maintena n ce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -. . . . . . . . . . . . . . . . . . . . . 8 M Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 l M1.1. Feedwater Flow Controller Failure (Unit 2) . . . . . . . . . . . . . . . . . . . . . . 8 l M2 Maintenance and Material Condition of Facilities and Equipment . . . . . . . . . . 9 L

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M2.1 Loss of One Source of Off-site Power (Line 5) (Unit 2). . . . . . . . . . . . . 9 M2.2 Reactor Core Isolation Cooling injection Containment Isolation Check Valye Failures (Unit 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 M2.3 Residual Heat Removal System Containment isolation Check Valve j' Failure (U nit 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 M3 Maintenance Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . 12 M3.1 RCIC Flow Oscillations (Unit 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 M3.2 RCIC Turbine Low Oil Level (Unit 2) . . . . . . . . . . . . . . . . . . . . . . . . . . 13 M4 Maintenance Staff Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . 14 l- M4.1 Poor Maintenance Staff Performance Associated with RCIC Check Valve Troubleshooting (Unit 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 M7 Quality Assurance in Maintenance Activities . . . . . . . . . . . . . . . . . . . . . . . . . . 15 M7.1 Review of Check Valve Corrective Action Team Activities (Unit 2) . . 15

, M7,2 4 RCIC Maintenance / Performance Summary (Unit 2) . . . . . . . . . . . . . . 16 i

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Table of Contents (cont'd)

lli. Engineering . . . . . . . . . ..... . ..... .. ... .. ....... . . ... ...... 17 E1 Conduct of Engineering . . . . . ... ... . .. . . .. . .. ..... 17 ;

E Individual Plant Examination Assumptions Associated with Loss of Offsite l Power (Unit 2) . . . . . .......... ..... .. .... ... ... 17

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E2 Engineering Support of Facilities and Equipment ..... .. .. . . 17 J E Reactor Core Isolation Cooling System Failure Safety Significance I Review (Unit 2) . . . . ...... .. ....... ... ... .. .. 17 E2.2 Active Valves Not included in the inservice Testing Program (Unit 2) . 19 V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . .. .... 20 ,

X1 Exit Meeting Summary . . . ................. ... ... . ..... 20 X2 June 25,1999, Management Meeting . . . . . . . . . ..... . .. ... . . 20 ATTACHMENTS Attachment 1- Partial List of NMPC Persons Contacted-Inspection Procedures Used-Items Opened, Closed, and Updated

- List of Acronyms Used

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Report Details 1 Summarv of Plant Status i

Nine Mile Point Unit 1 (Unit 1) retumed to power operation on June 17 following the completion of the refuel outage, which was 66 days in duration. During power operation, erratic operation of the turbine control mechanical pressure regulator and electronic pressure regulator was observed. On July 23, Unit 1 automatically shutdown from 100 percent power during testing of the mechanical pressure regulator. Details of the Unit 1 automatic shutdown and associated inspector observations were documented in NRC inspection report 99-07. Unit i remained shutdown through the end of this inspection perio Nine Mile Point Unit 2 (Unit 2) began the period at 100 percent power. On June 24, Unit 2 automatically shutdown due to a faulty feedwater flow controller. On June 30, Unit 2 commenced a reactor startup. The reactor core isolation cooling system valve testing following the startup was unsatisfactory and on July 2, Unit 2 was shutdown to conduct repairs. A 10CFR50.72 notification (Event No. 35889) was made on July 2,1999, for this event and later retracted on July 29,1999. The retraction was made because the preliminary determination that the testable check valve indication problems adversely impacted RCIC system operability and containment integrity was subsequently determined to be unfounded. Unit 2 was returned to service on July 23 and reached 100 percent power on July 26,199 . Operations 01 Conduct of Operation O1.1 General Comments (71707)

Using NRC Inspection Procedure 71707, the resident inspectors conducted frequent reviews of ongoing plant operations. The reviews included tours of accessible areas of both units, verification of engineered safeguards features (ESF) system operability, l verification of adequate control room and shift staffing, verification that the units were operated in conformance with Technical Specifications (TSs), and verification that logs and records accurately identified equipment status or deficiencies. In general, the conduct of operations was professional and safety-consciou .2 Automatic Reactor Shutdown Overview (Unit 2) Inspection Scope (71707)

On June 24, at 3:41 p.m., Unit 2 experienced an automatic reactor shutdown (scram) l from 100 percent power due to a malfunction in the feedwater master controlle Subsequent to the scram, the reactor core isolation cooling (RCIC) system was declared inoperable due to unexpected RCIC flow oscillations occurring with the flow controller in automatic. The inspectors responded to the control room and observed portions of the

' Topical headings such as o1, MB, etc., are used in accordance with the NRC standardized reactor inspection report outlin Individual reports are not expected to address all outline topics. The NRC inspection manuai procedure or temporary instruction that was used as inspection guidance is listed for each applicable report sectio .

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l scram recovery process. The inspectors also reviewed the operator logs, post-scram review documentation, and the sequence of events. Additionally, the event was discussed with Unit 2 operations and management personne b. Observations and Findinas l The cause of the transient was low reactor water level due to a failure of the feedwater l master controller. Scram recovery was complicated by a partial loss of offsite power l (Line 5) and the RCIC system failed to perform correctly in the automatic mode of operation. The cause of the loss of line 5 was the failure of one of the main generator output breaker fault relays. The cause of the RCIC system flow oscillations was a miscalibrated flow controller and air in the flow transmitter sensing lines.

l The reactor trip resulted in a main turbine trip on reverse power, as designed. Ali control l rods inserted properly. The turbine trip caused a fast transfer of both 13.8 kilo-volt (kV)

buses to offsite power sources. The fast transfer was completed with one 13.8 kV bus f

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transferring to line 5 and the other to line 6. Shortly after the fast transfer of the 13.8 kV l buses was complete, the line 5 offsite power source de-energized and the division 1 and

{- 3 emergency diesel generators started on the undervoltage condition and energized their i

respective buses. The loss of line 5 resulted in tripping the feedwater and condensate booster pumps supplied from that source. The subsequent condensate transient caused the remaining condensate booster and feedwater pumps to trip on low suction pressur Prior to the scram; past of the balance of plant electrical system was in an off-normal condition to support planned circuit breaker maintenance. The off-normal electrical line-up resulted in the loss of power to all of the turbine electro hydraulic control (EHC)

system pumps and the offgas system. With the loss of EHC system pumps and the off-gas system, the condenser became unavailable as a heat sink (no pressure control using the turbine bypass valves). Accordingly, the safety relief valves were cycled intermittently to control reactor pressur Operators manually initiated the RCIC system for reactor vessel level control. The RCIC system exhibited oscillations in automatic and the controller was placed in manua Operators closed the outboard main steam isolation valves to minimize the cooldown rate and to isolate the condenser which was losing vacuum as a result of the loss of the off-gas system. Excluding the above stated exceptions, operators executed a routine scram recovery and placed the plant in a stable conditio In accordance with 10 CFR 50.72, the control room staff made appropriate notifications for the June 24,1999, automatic reactor protection system actuation with a partial loss of off site power (Event No. 35857) and the subsequent RCIC system operability problem (Event No. 35859). The control room staff made an update to Event No. 35857 at 10:44 l

p.m. on June 24,1999, notifying the NRC staff that the off site power line 5 had been L restore .

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3 Conclusions On June 24, an automatic reactor shutdown from 100 percent power occurred at Unit 2 during maintenance on the feedwater control system. Operators placed the plant in a stable condition; overall, operator performance was adequate. Several equipment performance problems, combined with an off-normal plant electrical lineup, resulted in increased challenges to plant operator .3 Reactor Startuo Observations (Unit 2) Insoection Scope (71707)

The inspectors observed reactor startup activities conducted on June 30 and July 2 This review included the conduct of operations, resolution of plant problems, and observations of management oversigh Observations and Findinas A reactor startup was conducted on June 30. On July 1,1999 operators raised reacto pressure in preparation to perform the RCIC system injection test at rated pressure. At about 900 psig, operators observed significant control room instrumentation oscillation Plant evolutions were put on hold pending investigation and resolution of the proble Troubleshooting efforts were effective in determining that the instrumentation oscillations were caused by steam line resonance. Based upon discussions with the troubleshooting team, the inspectors determined that traveling pressure waves are produced in the main steam and bypass piping whenever the steam flow is disturbed by a valve position change. The pressure waves are reflected back and forth between the reactor vessel and turbine valves. The pressure waves are detected by the EHC pressure transducer and reinforced by the EHC regulator which can result in system oscillations. Operator response to the control room instrumentation oscillations and subsequent troubleshooting efforts was appropriate. The unit was shutdown on July 2, for unrelated RCIC system testable check valve problems. (See section M2.2)

During the July 23 plant startup, the normal station service transformer was energized with the cooling systems secured. The control room annunciator associated with the transformer was in alarm when the transformer was energized. However, control room operators thought that the alarm would clear after the transformer was placed in servic House loads wen transferred back to the reserve transformer when the alarm did not clear. NMPC determined that the shutdown procedure had been changed to add a step to secure cooling for the normal station service transformer. However, a similar change )

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was not made to the startup procedure to un-isolate cooling flo Conclusions i The reactor restart on June 30 was conducted in a conservative, well controlled manner and effective supervision and oversight was noted in addressing equipment performance problems. In contrast, during the July 23 startup, operators energized the normal station

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service transformer without cooling water. This error was caused, in part, by an inadequate operating procedure and by the operators' poor response to the associated transformer alar Operations Status of Facilities and Equipment O2.1 RCIC System Performance Durina the Automatic Reactor Shutdown (Unit 2) Insoection Scope (71707)

During the June 24 scram recovery, the RCIC system was started for vessel level control and exhibited 200-300 gpm flow oscillations while in the automatic flow control mod Operators declared the system inoperable, but continued to operate RCIC in the manual flow control mode. Additional RCIC system performance problems were observed and compensated for by the control room staff. The inspector reviewed RCIC system performance during the automatic reactor shutdown on June 24 and assessed the

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- impact on plant operator Observations and Findinas RCIC flow oscillations were observed with the flow controller in automatic. Operators I

suspected a possible flow controller problem and shifted the controller to manual, where the oscillations stopped. When in manual, the controller maintains a constant RCIC turbine speed. An operator must periodically adjust turbine speed to maintain the desired flow rate and vessel level as reactor pressure changes. In automatic, the flow rate is maintained automatically, regardless of reactor pressure, by adjusting the desired flow via a thumb wheel setting. Thus, the failure of the RCIC system to operate in automatic was not a significant safety problem, but rather an inconvenience to the control room operators because more attention had to be given to the system in manua )

(See Section M3.1)

During operation of the RCIC system to maintain reactor vessellevel, turbine oillevel was observed to be below the lowest level in the sightglass. This did not impact system operability, but was another distraction and operating concem to the control room staf (See Section M3.2)

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The RCIC governor valve indicated full closed during system operation. Nonetheless, operators verified the operation of the RCIC system using other instrumentation (i.e.,

turbine speed and discharge pressure). The licensee subsequently determined that the valve position limit switch was out of adjustment. It was later adjusted and tested satisfactorily. NMPC discovered that information regarding proper switch adjustment was not provkied in the work instructions, as the adjustment was considered to be a " skill of the craft" item. DER 2-1999-2164 was initiated for this issue and the work procedures were enhance l l

The RCIC turbine gland seal compressor tripped after running for several hours. The loss of compressor resulted in some gland seal leakage from the turbine shaft, but did i

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not significantly impact RCIC system operation. Subsequent maintenance staff troubleshooting identified that the starter coil was defective and it was replace {

During operation and shutdown of the RCIC system, valve position indication problems were noted with the two testable check valves located in the injection line to the reactor vessel. (See Section M2.2) Conclusions Several equipment problems associated with the reactor core isolation cooling (RCIC)

system were evident during system operation subsequent to the June 24 automatic reactor shutdown at Unit 2. These degraded equipment conditions resulted in the control room staff declaring the RCIC system inoperable per Technical Specifications, but operators were able to compensate for these conditions and successfully operated the system to maintain reactor vessel level. These compensatory actions, collectively, were a distraction to the control room staff during the recovery from the automatic shutdow Operations Procedures and Documentation O3.1 Operator Scram Resoonse and Use of RCIC Ooeratina Procedures (Unit 2)

$ Insoection Scooe (71707)

The inspector reviewed the actions taken by operators to control vessel level and to -

compensate for RCIC flow oscillations with the flow controller in automatic. The ;

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inspector reviewed instrument and control procedures for maintaining the RCIC speed / flow control system, operating procedures used to control the system, and the emergency operating procedures. The inspector also reviewed the licensee's assessment of operator performance, dated July 13,199 Observations and Findinas The inspectors observed that operators responded properly to lowering reactor vessel water level by initiating the RCIC system. However, independent inspector review of the !

RCIC system operating procedure (OP) and associated alarm response procedures identified some apparent inconsistencies, including:

1) The OP did not discuss the manual mode of RCIC system flow control. The OP 1 did describe RCIC system control of reactor vessel level via opening or closing l the recirculation line back to the condensate storage tank, and by adjusting flow via the controller in automati ) The OP did not address bypassing the reactor vessel high water level isolation l

(level 8).' Additionally, the alarm response procedure (for operator actions when a level 8 isolation of the RCIC system occurs) did not address restart of the RCIC ,

system until a reactor vessel level 2 condition was satisfie '

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3) The OP method of starting the RCIC system in the manual mode calls for opening the steam admission valve, allowing the machine to start and pump water through the minimum flow valve, and then opening up the injection valv The OP does not address starting / restarting the system using the manual start pushbutto In additior:, based upon inspector review of the post-trip alarm printer and discussions with the plant staff, it appeared that control room operators experienced some difficulty in following the OP and had to rely upon systems knowledge to adequately control vessel level. For example, the system was secured by closing the steam admission valve and -

then the injection valve. When operators restarted the system, they were not alerted to

- the 10 second time delay (TD) interlock between opening of the steam admission valve and then the injection valve. From review of the printout, there were severalinstances where the injection valve got an open signal while the TD was still in effec NMPC's initial post-transient evaluation was conducted prior to the Unit 2 restart on June 30. The evaluation was sufficient to identify the cause of the scram and to identify and address major equipment problems prior to unit restart. Based upon a number of discussions between the NRC staff and NMPC prior to and following the July 2 shutdown, the licensee initiated a detailed evaluation focused on operator performance -

during the recovery from the June 24 scram. At the August 23,1999, exit meeting, the licensee acknowledged that their process to evaluate operator performance following a major plant event warranted improvements to ensure timely and effective corrective actio The inspectors reviewed the detailed operator performance evaluation, dated July 13, 1999, and concluded that the procedural issues discussed above were adequately addressed and that the licensee's detailed assessment of operators' performance was acceptable. Some of the particular RCIC system operating information was lost due to the strip chart recorder failure part-way through the scram recovery perio Conclusions During the recovery from the June 24 automatic reactor shutdown, the control room staff operated the reactor core isolation cooling (RCIC) system with the flow controller in manual. The RCIC system operating and alarm response procedures contained some inconsistencies regarding operating the system in this mode, but operators were able to use their system knowledge to adequately maintain reactor vessel level. The licensee's July 13,1999, evaluation of operator performance adequately identified and resolved the RCIC system operating procedure issues and was reasonably thorough and critical in i assessing operator performance. The licensee acknowledged that their process to evaluate operator performance following a major plant event warranted improvements to ensure timely and effective corrective actio i l

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04 Operator Knowledge and Performance 04.1 Event Loa-keepina and Shift Tumover (Unit 2) Inspection Scope (71707)

The inspector reviewed the operators' response to the June 24 automatic reactor shutdown, including examination of operator logs and shift tumover informatio l Observations and Findinos in review of the operator / system response to the transient the inspectors found that:

- Control room logs were very poor, as there was no discussion of any RCIC problems that were evident in the initial response to the event. Specifically there was no discussion of taking the flow controller to manual, although subsequently a deficiency event report (DER) was writte The turnover of information from the first crew to the second crew was poor. The l- -

station shift supervisor (SSS) for the second crew involved did not know the extent of the RCIC system oscillations. As a result, the RCIC controller was again placed in automatic to observe system operation to validate the DER informatio l Conclusions

- The documentation and communication between the crews of the reactor core isolation i cooling (RCIC) system controller issues were poor following the June 24 automatic j reactor shutdown. Specifically, operator logs did not contain any information regarding j l the RCIC controller problems and the observed problems were not verbally, or in the !

! operator tumover sheets, communicated to the oncoming shift. Additionally, operators exercised poorjudgement by placing the RCIC controller in automatic to validate previously confirmed improper system performanc l 08 Miscellaneous Operations issues (92700)

l- 08.1 (Closed) Licensee Event Reoort (LER) 50-410/99-10: Unit 2 Reactor Trio due to a l Feedwater Master Controller Failure.

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l I report. The inspector completed an on-site review of the LER and verified that it was '

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completed in accordance with the requirements of 10CFR50.73. Specifically, the

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description and analysis of the ermt, as contained in the LER were consistent with the inspectors' understanding of the event. The root cause and corrective and preventive l- actions as described in the LER were reasonable. This LER is closed.

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M1 Conduct of Maintenance

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l M1.1 Feedwater Flow Controller Failure (Unit 2) Insoection Scooe (62707)

Due to some problems being experienced with the leading edge flow meter, NMPC

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elected to perform maintenance on the feedwater control system. In preparation,

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operators placed the feedwater master flow controller in manual. When the master flow controller was switched from automatic to manual, a feedwater transient occurred and resulted in an automatic reactor shutdown. The inspector reviewed the work planning and discussed the conduct of the maintenance with NMPC personne Observations and Findinos l '

I I Maintenance technicians were prepanng to flush the feedwater flow instrument lines in , . accordance with a work order package. .To support the work, operators prepared to shift l the feedwater level control system from three-element to single-element control by shifting the master controller to manual. Immediately after this step was performed, the controller output dropped to zero and the feedwater level control valves started to clos The operator was not able to stabilize level and an automatic reactor shutdown occurre A faulty manual control card was found in the feedwater master flow controller logic circuit and was replaced.

l

!

The work to be conducted was not previously scheduled and therefore was not part of the normal work control process. However, the work was planned and implemented through the fix-it-now (FIN) tearn in conjunction with the control room operators. A work impact assessment was performed and it was determined that there were no procedural restrictions in performing the work and a pre-job brief was conducted. It was noted that the pre-job brief did not specifically discuss the potential adverse consequences of a controller failure. NMPC has taken corrective actions to heighten the sensitivity of l workers and management conducting evolutions that have the potential to cause transient Conclusions During the conduct of maintenance at Unit 2, a faulty manual control circuit in the feedwater controller failed which resulted in a reactor vessel level transient and caused an automatic reactor shutdown. Plant conditions were acceptable to perform the maintenance. However, the pre-job brief was limited, in that, it did not discuss the potential consequences of a controller failur E,

M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Loss of One Source of Off-site Power (Line 5) (Unit 2) Insoection Scope (62707)

The June 24 automatic reactor shutdown caused a turbine trip which initiated relays to transfer station buses to 115 kV offsite power sources (lines 5 and 6). NMPC ,

' determined that a failure in the main generator breaker backup protection circuit, located '

in an off-site substation, resulted in the loss of line 5. The inspectors reviewed NMPC's troubleshooting and evaluation methods used to determine the cause of the loss of line 5, as documented in DER 2-1999-2158, and discussed the event with NMPC personne Observations and Findinas NMPC is provided with two offsite power sources from the transmission network to the i onsite distribution system and three divisions of on-site power. When line 5 was lost, l

'

both division I and division 111 were aligned to line 5. On the loss of line 5, the

. undervoltage relays on both division I and lll initiated and started both emergency diesel

. generators which successfully re-energized both buses. Due to an off-normal electrical lineup for the balance of plant equipment, the loss of line 5 also caused the loss of I additional loads which normally would not have been lost. (See section 01.2)

The circuit failure was isolated to a malfunction with the backup protection circuits for the main generator output breaker. NMPC determined that the apparent cause was that either the breaker auxiliary contacts did not operate properly or a relay failed to operate, resulting in the trip of the feeder breaker to line 5. Initial corrective action included the replacement of the suspected relays and the breaker contacts were moved to the spare contacts. The electrical system was subsequently tested satisfactorily. Subsequent bench testing demonstrated that the root cause was the failure of the suspected rela NMPC's investigation into the loss of line 5 determined that there was some Scriba Substation breaker preventive maintenance that had not been performed. Additionally, the quality of maintenance activities in the substation was poor and the interface between the off-site and on-site maintenance organizations was lacking. DER 2-1999-2206 was initiated to address these concems. The breaker vendor manual showed that the auxiliary switch mechanism and contacts should undergo periodic maintenance and checks. Previous maintenance report checklists identified that these checks were not made.' The required maintenance was completed during the troubleshooting and inspection process and additional corrective actions to improve reliability were being evaluated by NMPC. NMPC concluded that the lack of preventive maintenance did not contribute to the relay failur Conclusions A relay failure in the main generator backup protection circuit resulted in a partial loss of off-site power following the automatic reactor shutdown at Unit 2 and additional i

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challenges to plant operators. NMPC's investigation into and identification of the cause was thorough. Although not a direct contributor to the relay failure, the investigation showed that certain recommended substation breaker preventive maintenance was not being performed by the off-site maintenance grou M2.2 Reactor Core Isolation Coolina iniection Containment isolation Check Valve Failures (Unit 2) i

! Insoection Scope (62707. 37551)

The inspectors observed RCIC valve maintenance activities including disassembly,

. reassembly, and post maintenance testing and reviewed the NMPC root cause analysis repor Observations and Findinas

- During the June 24 automatic reactor shutdown, the RCIC system was used to control reactor vessel level. During the RCIC system operation, the injection outboard containment isolation check valve, 2iCS*AOV156 (AOV156) indicated open with no flow

- (valve should indicate closed) and the injection inboard containment isolation check valve, 2iCS*AOV157 (AOV157) indicated closed with full flow. Maintenance was conducted on AOV156 and AOV157 and initial post-maintenance testing showed that the valves operated satisfactorily. (See Section M4.1)

On July 2, the RCIC system was tested by injecting into the reactor vessel. Once again, AOV157 indicated closed under full system flow conditions. When the RCIC system was secured following testing, AOV156 again failed to indicate closed. Because these observed conditions were similar to those observed on June 24, and it was apparent that previous corrective action were not effective, the reactor was shutdown to determine the -

root cause and implement appropriate corrective action. NMPC assembled a team to analyze and address the check valve failures and a root cause/ investigation plan was developed. (See Section M7.1)

AOV156 Failure to indicate Closed NMPC initiated DER 2-1999-2264 to document the AOV156 failure to close even AOV156 was disassembled and several valve intemal discrepancies were identified. For example: mechanics noted that total tolerances for axial shaft component stack-up were outside the acceptance criteria; the indicator side stuffing box was not making metal to metal contact; and the hinge arm length was incorrect. The NMPC team determined that the shutting force was not sufficient to overcome the combination of check valve component out-of-tolerances, packing friction, and limit switch resistance force However, the valve was able to function in the open direction and NMPC engineering calculations demonstrated that shutting forces in the event of a steam line break would be sufficient to cause the valve to go close t

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AOV157 Failure to indicate Open NMPC initiated DER 2-1999-2161 to document the AOV157 discrepancy. AOV157 was disassembled and several valve internal discrepancies similar to the problems with AOV156 were identified. In addition, the indicator shaft was installed 180 degrees out of position,'in the wrong recessed slot on the hinge arm. During the Ju:n 1998 outage, the position indicating shaft was removed and incorrectly re-installed. Contributing to the

. reassembly error was insufficient guidance in the work order, in addition, a 1992 modification to upgrade the indicator shaft to a design that would prevent improper re-assembly was issued, but not installed. The NMPC staff concluded that timely installation of the modification would have prevented the improper re-assembly of the valve. (See Section M7.1) j Conclusions During the June 24 automatic reactor shutdown and again on July 2, the reactor core isolation cooling system injection containment isolation check valves exhibited a number of performance problems. The valves remained operable, but were degrade '

Ineffective corrective actions contributed to the valves' porgerating histor )

Mditionally, the installation of a modification to the indie .Wr shaft was not implemented

.

in a timely fashio M2.3 Residual Heat Removal System Containment Isolation Check Valve Failure (Unit 2) Inspection Scope (62707) l The residual heat removal system containment isolation check valve, RHS*AOV398, (AOV398) did not initially close when shutdown cooling was secured on July 10. The inspector observed portions of the maintenance activities, including post-work tecting, and reviewed the corrective action Observations and Findinos  !

During the forced outage, position indication cam physical interferences for AOV39B were repaired and the valve was tested satisfactorily on July 8. On July 10, the valve failed to close when shutdown cooling (SDC) flow was throttled and then secure AOV398 was disassembled and the overall material condition was determined to be poor; with significant galling, nicks, and scratches observed. The valve had been rebuilt during the 1998 refueling outage. Since then, AOV39B h&s experienced position indication problems and one event, in May 1999, where it did not fully close when SDC was secured. At that time, the limit switches were adjusted and the valve operation was tested satisfactoril AOV39B was completely overhauled during this outage, including many new components (i.e., new position indication and actuator shafts). Significant difficulty was experienced during the valve maintenance which required two subsequent rework evolutions. The reworks were caused, in part, by improper re-assembly of the valve

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(resulting in the valve binding). In addition, NMPC determined that the generic maintenance procedure was not sufficient to address the special considerations required to properly maintain the valve. The failure was considered a maintenance preventable functional failur Conclusions l During the Unit 2 forced outage, position indication problems with the residual heat removal system containment isolation check valve (AOV39B) were repaired and the valve was tested satisfactorily. Subsequently, AOV39B failed to close when shutdown cooling was secured. Previous poor maintenance practices, including weak valve maintenance procedures contributed to the valve failure.

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M3 Maintenance Procedures and Documentation M3.1 RCIC Flow Oscillations (Unit 2)

l Inspection Scope (627QI)

l As previous!y discussed in Section O2.1, the RCIC system was started for level control -

and exhibited 200-300 gpm flow oscillations while in automatic. Operators declared the system inoperable and continued to use it in manual. The cause of the oscillations was

, determined to be improper adjustment for the flow controller. Additiona!!y, air in the flow l transmitter sensing lines contributed to the oscillations. The inspector reviewed vendor l manualinformation and maintenance procedure Observations and Findinos NMPC implemented a work order to troubleshoot, repair, and bench calibrate the contmiler. The flow transmitter was found to have entrained air and the controller did not have the derivative properly nulled. The RCIC flow controller settings include gain, l integral, and derivative. Derivative is used for anticipatory control and, for the RCIC

,

system, should be nulled.

l l The controller had been replaced in 1996 and was set up to match the replaced l controller. Due to the poor quality of the maintenance planned and performed in 1996, I

controller settings were not documented and the system response was not checke Industry information was available which provided current procedures for calibration of the turbine control systems and stated that when a controller is replaced, the use of ;

previous controller settings and dynamic testing in the surveillance test mode can be an inaccurate means of controller tuning. Additionally, actual testing (vessel injection) may

'

be needed to assure proper response. This industry information was not used. On July 2. Unit 2 completed the injection test to the reactor vessel satisfactorily. The inspector

! noted that command and control for the test was excellent. There did not appear to be any flow oscillations on the initial startup or following the step change demand signals initiated using the controller. However, deficiencies were identified with the injection check valve position indication. (See Section M2.2)

i L

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The failure to have appropriate procedures to ensure proper performance and documentation of all required RCIC system tuning and calibration is a violation of 10CFR 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings". This severity level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 50-410/99-06-01). This violation is in the licensee's corrective action program as DER 2-1999-215 Conclusions l

During the June 24 automatic shutdown transient at Unit 2, the reactor core isolation cooling (RCIC) system exhibited 200-300 gallon per minute flow oscillations with the controller in automatic. NMPC investigation showed that the flow controller had not been properly adjusted when it was replaced in 1996, in spite of available industry information on proper controller set-up. The controller out-of-adjustment condition, in conjunction with some air in the flow transmitter sensing lines, caused the flow oscillations. The failure to have appropriate procedures for tuning and calibration of the RCIC system was a non-cited violation and the result of past poor quality maintenanc M3.2 RCIC Turbine Low Oil Level (Unit 2) Inspection Scope (62707)

During the June 24 automatic reactor shutdown, when the RCIC turbine was started, oil levels on the sight glass were not visible. The inspector reviewed NMPC's corrective actions to address this issue, j Observations and Findinos RClO turbine operation was not affected by the low oil level and bearing temperature remained satisfactory. No low lube oil pressure or bearing high temperature alarms were i observed during RClO system operation with this condition. As a precaution, the RCIC l lube oil was sampled and the analysis showed that no degradation occurre The licensee determined that the low oil level was caused by improper oil sampling processes. The chemistry department obtained a two liter oil sample at the drain valve on the oil cooler following the last RCIC system quarterly surveillance test and the procedure did not require the replenishment of oil following the sample. The licensee also identified that the vendor manual recommended that tube oil level be checked after each turbine run. The quartedy surveillance procedure and operating procedure did not

. have this step. The procedures were changed to assure that proper lubrication oil level is maintained. This minor violation is not subject to enforcement actio Conclusions  ;

Following the June 24 automatic reactor shutdown and manualinitiation of the reactor core isolation cooling (RCIC) system, operators identified that the lube oil level was not visible in the sight glass. The low oil level was the result of oil not being added following l

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an oil sample being taken. Subsequent lube oil analysis showed that there was no RCIC system degradation. NMPC revised the RCIC oil sample procedure to assure that proper oillevelis maintaine M4 Maintenance Staff Knowledge and Performance M4.1 Poor Maintenance Staff Performance Associated with RCIC Check Valve Troubleshootina (Unit 2) Insoection Scope (62707)

During the RCIC system operation on June 24, AOV156 indicated open with no flow (valve should indicate closed) and AOV157 indicated closed with full flow. Maintenance was conducted on AOV156 and 157 and post-maintenance testing showed that the valves operated satisfactorily. The work that was conducted focused on the external

.

position indication mechanisms. Subsequently, on July 2, during the RCIC injection test, the valves exhibited indication problems and the reactor was shutdown to conduct troubleshooting. The inspector observed the initial AOV156 troubleshooting efforts and discussed activities with NMPC personne Observations and Findinas On June 28, the maintenance day shift crew that was working on AOV156 was relieved by the night shift crew. The day shift crew had left the bearing bracket cap screws reinstalled finger tight, which was not relayed to the night shift crew. The day shift crew had not been able to get the valve to stroke without assistance. The night shift crew found that the bearing bracket cap screws were rubbing against the bearing bracket (as they were only finger tight) and concluded that was the cause for the inability for the valve to operate properly. After tightening the cap screws, the valve operated acceptably. The next day, the day shift crew supervisor expressed reservations that the cap screws being finger tight was the root cause. After several discussions were held with engineering and management personnel, the root cause was not challenged furthe Subsequently on July 2, the valve failed to close when the RCIC system was secure (See Section M2.2)

The inspectors observed that there wera several causes for deciding that the valve had been repaired when, in fact, it had not. Troubleshooting efforts were focused on external not internal valve problems and the troubleshooting work order was not specific. A written turnover log was not adequately maintained to capture the troubleshooting efforts. Although the day shift supervisor had reservations and challenged the situation, NMPC management failed to properly recogniza and resolve the concern Conclusions Prior to July 2, troubleshooting efforts associated with the reactor core isolation cooling valve repair were poor, in that, logs did not fully reflect work done and the valve status was not adequately communicated to the oncoming shift. This resulted in the

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determination that the root cause of the problem had been found and that the valve had been repaired, when in fact, it was not. Unit 2 management and staff demonstrated poor judgement by rationalizing the anomalies associated with the valve maintenance as acceptable, rather than thoroughly investigating and resolving the M7 Quality Assurance in Maintenance Activities M7.1 Review of Check Valve Corrective Action Team Activities (Unit 2) Inspection Scope (62707)

As briefly discussed in Section M2.2, the corrective actions taken by NMPC to resolve RCIC system check valve problems following the June 24 scram were not effectiv ;

After the RCIC system full flow testing injection valve failures on July 2, Unit 2 was shutdown and a multi-discipline team was assembled to investigate the causes of the RCIC containment isolation check valve failures, to determine the extent of condition, and to implement corrective actions. The inspector observed team activities and reviewed the team's root cause analysis repor Observations and Findinos

!

The inspector noted that the team developed a plan and maintained an activity log. The 4 RCIC check valves were quarantined to identify the "as found" condition for the failure l

'

analysis. - A vendor representative was available to assist with on-site investigation and corrective maintenance. The scope was appropriately expanded to include other Anchor Darling (A/D) testable check valves with remote position indication. These valves were !

located in the high pressure core spray, low pressure core spray, residual heat removal, j and feedwater systems. Nine containment isolation valves were included in the scop j l

A historical review showed that there had been no occurrences of valves failing to open, but severalinstances of the valves failing to fully close. Additionally, a significant number of position indication problems due to mechanical interferences or mis-adjustments were documented and a long history of packing leakage problems was noted. it was evident that this negative performance trend of valve problems was not earlier recognized or l evaluated by the maintenance or engineering staffs. A modification to the valve position indication stem was issued in 1992, but was not installed. This modification was designed to prevent the error made during the 1998 outage work on the RCIC injection check valve, which resulted in the position indication shaft being incorrectly installe The licensee's investigation team also identified that a modification to eliminate the position indication limit switches was proposed in 1991, but was closed and not implemente The inspector observed that the corrective actions developed by the team were extensive and included addressing negative personnel performance aspects of maintenance and engineering staffs. The inspector noted that NMPC intends to install a modification to eliminate the limit switches for Anchor / Darling testable check valve t

.

16 Conclusions Prior to the reactor core isolation cooling injection valve failures on July 2, the corrective actions to address valve performance deficiencies were narrowly focused. NMPC subsequently assembled a team which developed the root causes of the poor valve operating history and implemented appropriate corrective actions to resolve the technical problem Maintenance and engineering staff performance associated with the Anchor / Darling testable check valves was weak. A significant number of position indication problems due to mechanical interferences or mis-adjustments were documented and this negative equipment performance trend was not earlier recognized or evaluated. A timely I installation of an approved 1992 modification would have prevented the improper l

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reassembly of the RCIC system injection check valve in 199 M7.2 RCIC Maintenance / Performance Summarv (Unit 2) Insoection Scope. Observations and Findinos (71707) ,

i Due to the problems identified during the June 24 automatic reactor shutdown, the l inspectors summarized a brief history of the recent RCIC system performance issues: l

- The RCIC system failed on demand during the April 24,1999 automatic reactor !

'

shutdown. The failure occurred because the turbine trip valve was not properly adjusted. (See NRC inspection report 99-04)

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Numerous minor RCIC support system discrepancies. (See Section O2.1)

- The RCIC system injection check valves have had a history of position indication )

'

problems (See Section M7.1).

- Several maintenance related deficiencies were found during the RCIC system ,

planned work w'ndow from May 11-22 (See NRC inspection report 99-05). l

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In June 1999, f.no RCIC system was placed in the maintenance rule category l t

(a)(1). Conclusions The Unit 2 reactor core isolation cooling system reliability and performance was degraded as a result of weaknesses in maintenance and engineering suppor i

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111. Enaineerina E1 Conduct of Engineering E Individual Plant Examination Assumotions Associated with Loss of Offsite Power (Unit 2) Insoection Scope (37551)

The inspector reviewed the Unit 2 individual plant examination (IPE) and probabilistic risk analysis model associated with the loss of offsite power, and held discussions with NMPC personne Observations and Findinas The inspector notcd that, prior to the June 24 event, theio have been nine losses of offsite power (LOSP) at Unit 2, seven of which occurred between December 1988 and November 1993. The majority of these events were caused by component failure, with others associated with work control practice The inspector reviewed the NMPC safety and availability assessment of Line 5 and 6 probabilistic risk analysis (PRA) treatment report, dated August 6,1999. The assumptions used in the initial PRA regarding loss of offsite power were not consistent with NMPC operating experience. The initiating event frequency used in the initial PRA for loss of lines 5 and 6 is 0.04 events per year per line. The actual frequency of these ,

events is a much higher 0.33. The impact of this increased number of initiators since the l initial IPE contributed to an increase in the core damage frequency (CDF) from 3.1E-05/yr to 5.4E-05/yr. NMPC updated their PRA and has submitted a revised IPE to the NR , Conclusions ,

NMPC assumptions used to develop the individual plant examination for the frequency of loss of offsite power were not consistent with operating experience. NMPC updated its probabilistic risk analysis model and has submitted a revised individual plant examination

' to the NR E2 Engineering Support of Facilities and Equipment E Reactor Core Isolation Coolina System Failure Safety Sianificance Review (Unit 2) Inspection Scoos (37551)

The Region i Senior Reactor Analysts (SRAs) reviewed portions of the Unit 2 individual plant examination (IPE), probabilistic risk analysis (PRA) model, and the licensee's event evaluations to assess the significance of RCIC system malfunctions noted during the April 24 and June 24,1999, automatic reactor shutdowns (scrams). The items specifically reviewed were the method used to determine the RCIC pump failure .

probability data, PRA assumptions regarding the mitigation of loss of offsite power i events and the risk associated with the RCIC system malfunctions following the two l reactor scrams.

l l b. Observations and Findinas l

The SRAs found that the licensee's component failure rate practice was appropriate and consistent with current industry practice. The Unit 2 IPE does not specifically model the failure probabilities of the RCIC turbine protective devices. The failure of the protective i devices, if they result in the failure of RCIC, would be appropriately included in the RCIC l

failure rate data. The practice of collapsing the failure of "sub-components" into

" super-components"is routinely performed to simplify the PRA data collection and evaluation process. This practice does not adversely affect the quality or accuracy of the PRA. On a periodic basis, the PRA failure rate data is updated based on actual plant l equipment performance. The SRAs confirmed with the licensee's PRA staff that the i recent RCIC system failures would be evaluated during the next Unit 2 PRA failure rate data updat The SRAs reviewed the Unit 2 methodology for coping with a loss of offsite power (LOSP) events. Nine Mile Point Unit 2 has two emergency diesel generators (EE M that power necessary mitigation equipment if offsite power is lost. The failure of m$dys trains of redundant safety-related equipment must occur to result in a loss of all and emergency alternating current (AC) power sources. Therefore, the frequency of a loss of offsite AC power, concurrent with the failure of both trains of the emergency diesel generators, is low. However, if offsite power and both EDGs were unavailable, the

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current PRA model allows operation of the RCIC system to provide reactor vessel i makeup, during the first two hours following event initiation. If the RCIC system were to l fail following this initial two-hour interval, reactor vessel level could be maintained by depressurizing the reactor and using the diesel-driven fire water pump to provide reactor vessel inventory makeup. The SRAs noted that while the IPE did not take credit for the availability of the high pressure core spray (HPCS) system for coping with a loss of power, the current PRA does credit the HPCS dedicated diesel generator. Procedural guidance has been provided to the operators to cross-tie one of the Division I or ll electrical buses to the HPCS diesel generator bus (Division 111) to ensure adequate HPCS emergency diesel generator cooling (via a Division I or ll service water pump), to power a battery charger, and to provide low pressure injection. Ultimately an AC power source (one off site or either of the Division I or ll emergency diesel generators, or Division lli crosstie) must be recovered, before station battery depletion, for any of the LOSP sequences to be successfu Following the April 24,1999, automatic reactor shutdown, both offsite power sources and l the emergency diesel generators remained available. While RCIC failed to operate following this event, HPCS was available and provided high pressure reactor vessel makeup. The power conversion system (feedwater and condensate systems) '

automatically secured, as design, following the slow non-safety related bus transfe However, the system remained available and was subsequently recovered following the event. In addition, the automatic depressurization system and the multiple low pressure

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injection pumps also remained available in the event that the high pressure injection sources faile Following the June 24 automatic shutdown, one of the offsite power supplies (line 5) was unavailable which caused the partial loss of non-safety relsted loads and the temporary loss of power to the Division i and ill emergency electrical busses. Power was restored to the safety related busses. The availability of the feedwater and condensate systems was partially degraded by the loss of line 5, but remained recoverable. The HPCS remained available following this event. The manualinitiation of the RCIC system was in accordance with station procedures. Although the RCIC system was not operated with the pump controller in automatic, the system maintained reactor vessel level in the manual mod Conclusions The failure rate data evaluation methodology used in the Nine Mile Point Unit 2 probabilistic risk analysis (PRA) for the reactor core isolation cooling (RCIC) system was appropriate. The PRA assumptions regarding the loss of offsite power were consistert with plant operating practices. There was an increase in core damage frequency caused by the RCIC system malfunctions following the April 24,1999, scram. The availability of multiple redundant systems to provide makeup to the reactor vessel mitigated the risk significance of this event. The RCIC system operation in the manual mode following the June 24 scram had an almost negligible effect on the core damage frequency. However, the aggregate of equipment malfunctions associated with the June 24 scram and the April 24 scram have risk significance and both scrams are being considered for inclusion in the NRC accident sequence precursor progra E2.2 Active Valves Not included in the inservice Testino Prooram (Unit 2) Inspection Scope (37551)

On July 19, Unit 2 identified that 26 valves had been improperly excluded from the inservice testing (IST) program. The inspector reviewed the DER, American Society of Mechanical Engineers (ASME) requirements and discussed the issue with NMPC personne b.- Observations and Findinos The 26 valves were associated with residual heat removal, reactor core isolation cooling and high pressure core spray system. The valves are normally closed, but do have an active safety function and are therefore required to be in the IST progra The valves were deleted from the IST program when the second ten-year interval of the program superseded the first ten-year interval, in 1998. NMPC performed an extent of condition review and reviewed other changes made to the second ten-year interval. No other problems were identified. The 26 valves were subsequently tested satisfactoril The Unit 1 IST program plan was reviewed for similar discrepancies and none were i

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found. NMPC determined the cause to be the misapplication of industry guidance concerning IST requirements for active and passive valve The failure to conduct the required ASME code inspections is a severity level IV violation and is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 50-410/99-06-02). This violation is in the licensee's corrective action program as DER 2-1999-2423. The inspector noted that NMPC has recently identified similar ASME Code,Section XI, discrepancies. These discrepancies were documented in LER 99-09, Nonconformance with Technical Specification Regarding ASME Section XI Class 2 Check Valve Reverse Flow Testing. Additional IST and inservice inspection (ISI) program discrepancies were identified and documented by NMPC in LERs 99-07 and 99-08. NMPC has identified these 26 valve testing discrepancies through their ongoing efforts to identify and correct ISI/IST program oversight Conclusions Misapplication of industry guidance during the development of the second ten-year

. interval inservice testing (IST) program at Unit 2 resulted in improperly deleting the requirement to conduct IST testing for 26 safety related valves. The valves were subsequently tested satisfactorily. Failure to conduct the required testing was a non-cited violatio V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of the licensee management i at the conclusion of the inspection on August 23,1999. Richard Crienjak, Deputy Director, DRP, and Michele Evans, Branch Chief, Projects Branch 1, DRP, attended the exit meeting and held discussions with NMPC managers on site. The licensee  !

acknowledged the inspectors' findings and noted that no proprietary information was l identifie X2 June 25,1999, Management Meeting '

On June 25,1999, NMPC management met with the NRC staff in the NRC Region l l Office in King of Prussia, Pennsylvania, to review recent improvement initiatives. A copy of NMPC's handout (Enclosure 2) and a list of attendees is attached (Enclosure 3).

[.

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l ATTACHMENT 1 l PARTIAL LIST OF PERSONS CONTACTED tilanara Mohawk Power Corporation D. Bosnic Manager, Operations, Unit Two S. Doty Manager, Maintenance, Unit One i N. Paleologos Plant Manager, Unit Two

,

F. Fox Acting Manager, Maintenance, Unit Two l R. Smith Plant Manager, Unit One

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N. Rademacher Manager, Quality Assurance l D. Topley Manager, Operations, Unit One INSPECTION PROCEDURES USED IP 37550 Engineering IP 37551 On-Site Engineering IP 61726 Surveillance Observations IP 62707 Maintenance Observations IP 71707 Plant Operations IP 71750 Plant Support IP 90712 In-Office Review of Written Reports of Non-Routine Events at Power Reactor Facilities IP 92700 Onsite Follow-up of Written Reports of Non-Routine Events at Power Reactor Facilities l

l ITEMS OPENED. CLOSED. AND UPDATED

CPENED and CLOSED 50-410/99-06-01 NCV Failure to have appropriate procedures to ensure proper performance and documentation of all required RCIC system l tuning and calibration.

l

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50-410/99-06-02 NCV A misapplication of ASME code requirements for inservice testing (IST) program resulted in deletion of 26 valves from the IST

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program j l

l CLOSED 50-410/99-10 LER Unit 2 Reactor Trip due to a Feedwater Master Controller Failure I

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Attachment 1 (cont'd) 2 LIST OF ACRONYMS USED l AC Alternating Current A/D Anchor / Darling j ASME American Society of Mechanical Engineers I

CDF Core Damage Frequenc CFR Code of Federal Regulations DC Direct Current DER Deviation / Event Report EDG Emergency Diesel Generators EHC Electro-hydraulic Control FIN Fix-It-Now ESF Engineered Safeguards Feature HPCS High Pressure Core Spray IPE Individual Plant Examination IR inspection Report ISI in-Service inspection IST In-Service Testing LCO Limiting Condition for Operation LER- Licensee Event Report LOSP Loss of Off-site Power NCV Non Cited Violation NMPC Niagara Mohawk Power Corporation NRC Nuclear Regulatory Commission OP Operating Procedure PRA Probability Risk Analysis 4

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QA Quality Assurance i RCA Radiological Controlled Area l RCIC Reactor Core Isolation Cooling -

SDC Shutdown Cooling SRV Safety Relief Valve i SRA Senior Reactor Analyst

'SSS Station Shift Supervisor TD Time Delay-TS : Technical Specification USAR Updated Safety Analysis Report Unit 1 Nine Mile Point Unit 1 -

Unit 2 Nine Mile Point Unit 2 WO Work Order l

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ENCLOSURE 3 LIST OF ATTENDEES U.S. Nuclear Regulatory Commission NAME TITLE l l

l H. Miller Regional Administrator A. Randolph Blough Director, Division of Reactor Projects (DRP)

R. Crienjak, Deputy Division Director, DRP W. Lanning Director, Division of Reector Safety M. Evans Branch Chief, Projects Branch 1, DRP R. Fernandes Resident Inspector, Nine Mile Point 1& 2 R. Conte Branch Chief, DRS '

W. Cook Project Engineer, DRP S. Chaudhary Senior Reactor Engineer, DRS Niagara Mohawk Power Corporation NAME TITLE l

J. Mueller Chief Nuclear Officer J.Conway V.P. Nuclear Generation C. Terry V.P. Nuclear Safety Assessment and Support R. Hall Director Human Resources J. LeClair General Supervisor Training Services J. Ringwald Supervisor Site Licensing M. Briggs Quality Assurance T. Brockman Unit 1 Operations Pennsylvania Power & Light Company NAME TITLE R. Kichune Senior Licensing Engineer j l ,

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