IR 05000361/1999006

Insp Repts 50-361/99-06 & 50-362/99-06 on 990404-0515.Non- Cited Violations Identified.Major Areas Inspected:Aspects of Licensee Operations,Maint,Engineering & Plant Support

ML20195E813
Person / Time
Site:	San Onofre
Issue date:	06/08/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20195E806	List: IR 05000361/1999006 ML20195E800
References
50-361-99-06, 50-361-99-6, 50-362-99-06, 50-362-99-6, NUDOCS 9906140107
Download: ML20195E813 (26)

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ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket Nos.: 50-361 50-362 License Nos.: NPF-10 NPF-15 Report No.: 50-361/99-06 50-362/99-06 Licensee: Southern California Edison Co.

Facility: San Onofre Nuclear Generating Station, Units 2 and 3 Location: 5000 S. Pacific Coast Hwy, San Clemente, California 92672 Dates: April 4 through May 15,1999 Inspectors: J. A. Sloan, Senior Resident Inspector J. G. Kramer, Resident inspector J. J. Russell, Resident inspector G. A. Pick, Senior Project Engineer Approved By: L. J. Smith, Chief, Branch E Division of Reactor Projects ATTACHMENT: Supplemental Information i

9906140107 990608 PDR ADOCK 05000361 0 PDR

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EXECUTIVE SUMMARY

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i San Onofre Nuclear Generating Station, Units 2 and 3 NRC Inspection Report No. 50-361/99-06; 50-362/99-06 This routine announced inspection included aspects of licensee operations, maintenance, engineering, and plant support. This report covers a 6-week period of resident inspection.

Ooerations

• The licensee's assessment of a vital dc bus cross-tie evolution accurately reflected Operations and Maintenance personnel performance. The overall performance of the evolution (prejob briefing, equipment manipulation, and independent verification of )

components) was good (Section O1.2).

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• Communication practices among control room reactor operators during the Unit 3 reactor coolant system draindown to midloop were poor and not in accordance with licensee management expectations. Incomplete and general component identifications were frequently verbalized while preparing for, and during, component manipulations.

However, the overall performance of the evolution was acceptable (Section O1.3).

• After the Steam Generator 3E088 feedwater regulating valve failed closed because of a faulty control card and the subsequent automatic trip of both main feedwater pumps o,1 May 13,1999, operator actions to manually trip the Unit 3 reactor from 97 percent power were appropriate. Licensee response to the event was characterized by good i management oversight and thorough initial event investigation (Section O1.4). )

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• - After the Steam Generator 3E089 feedwater regulating valve failed open because of a faulty pneumatic positioner on May 15,1999, operator actions to manually trip the Unit 3 reactor from 24 percent power were appropriate. Operator response to the trip was good. Operators followed appropriate procedures and avoided an excessive reactor coolant system cooldown that could have resulted from the nonresponding, open .

I feedwater regulating valve (Section 01.5).

Maintenance

• The licensee aggressively pursued inconclusive results of an inservice test and identified that the check valve disc nuts in the shutdown cooling return line to the suction of the low pressure safety injection pumps had corroded away, rendering the check

. valves degraded but operable. The licensee determined the nuts were carbon steel

. instead of stainless steel as designed. The licensee effected prompt repairs in both units and implemented appropriate compensatory measures to reduce the risks associated with the repairs in the operating unit (Section M2.1).

• A noncited violation (Enforcement Policy, Appendix C) of 10 CFR Part 50, Appendix B, Criterion V, was identified because the licensee installed shutdown cooling system check valves with carbon steel disc nuts instead of stainless steel nuts, and the nuts

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-2-corroded away. This occurred in 1984 and 1982 in Units 2 and 3, respectively. This violation is in the corrective action program as Action Request 990400907 '

(Section M2.1).'

Operations and Maintenance personnel, aware that the planned vent path might not provide for effectively draining the contaminated water from shutdown cooling system piping in preparation for check valve repairs, were not proactive in preventing workers

' from being sprayed by the water. However, the workers were wearing appropriate protective clothing, which prevented personal contamination. The radiological response to the occurrence was good (Section M2.1).

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. Containment loose debris inspections in Unit 3, conducted by the licensee prior to

' Mode 4 entry, were generally effective. However, the inspectors identified several items that the licensee missed, including a pair of pliers in a steam generator keyway and a fan screen that was partially unsecured from the fan base because of corrosion !

(Section M2.2). l

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Loose incore debris inspections conducted during the Unit 3 refueling outage were )

thorough. Foreign objects identified were removed; however, a time delay between l object identification and removal, with no restrictions on level and flow changes in the '

reactor vessel, had the potential to cause identified objects to change position and become unretrievable. This delay was a poor practice (Section M4.1).

A noncited violation (Enforcement Policy, Appendix C) of Technical l

. Specifications 4.3.3.7.2 (pre-1996) and 5.5.1.1.a (post-1996) was identified because a procedure error had caused the surveillance of fire detector supervisory circuits in i containment not to be performed at the required frequency since 1986. This violation is in the corrective action program as Action Request 981001241 (Section M8.2).

Enaineerina

The use of the remote fill station for adding oil to the lower oil reservoir for Reactor

. Coolant Pump 2P004 was acceptable. The compensatory measures to verify the .

condition and integrity of the remote oil fill lines before and during use, including l'

additional administrative measures to track the oil usage, were appropriate. Based on a pump walkdown, the licensee concluded that the leaking pump oil was being captured by the oil collection system (Section E2.1).

Engineering performance deficiencies resulted in mechanical nozzle seal assembly 2 mounting holes in the Unit 3 pressurizer being misaligned such that the assembly had to be redesigned before installation (Section E2.2).

A noncited violation (Enforcement Policy, Appendix C) of 10 CFR Part 50, Appendix B, Criterion ll!, " Design Control," was identified because the emergency diesel generator fuel storage tank design and procedures failed to provide the diesel fuel volume required by the design basis. This violation is in the corrective action program as Action Request 980700697 (Section E8.2).

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• During the 1998 Unit 2 midcycle outage, the licensee identified that seven inconel-600

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instrument nozzles in the reactor coolant system had indications of potential pressure boundary leakage. The licensee repaired the nozzles and accelerated its planned replacement of the remaining Inconel-600 nozzles on the reactor coolant system loops.

Because the corrective actions from a 1996 violation were still in the process of being implemented, the leaking nozzles reported by the licensee were considered to be additional examples of the previous violation and additional enforcement was not warranted. The licensee completed the replacement of the inconel-600 nozzles on the reactor coolant loops during the Cycle 10 refueling outages, leaving inconel-600 only in the instrument nozzles on the pressurizer, steam generatori;, and reactor vessel head in both units (Section E8.4).

Plant Sucoort

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• The general radiological controls for work areas in the Unit 3 containment were adequate (Section R1.1).

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Report Details Summary of Plant Status Unit 2 operated at essentially 100 percent reactor power during this inspection period.

Unit 3 began this inspection period in Mode 6, in the eighth day of the Unit 3 Cycle 10 refueling outage. The unit entered Mode 1 on May 9,1999, and the breakers were closed later that same day. On May 13, after a power ascension to approximately 97 percent power, a feedwater regulating valve failed closed, resulting in both main feedwater pumps tripping on high discharge pressure. _ Operators manually tripped the reactor prior to an automatic reactor trip (Section 01.4). On May 15 operators restarted the reactor. The main turbine was manually tripped because of high vibration shortly after being synchronized to the grid. Several hours later the other feedwater regulating valve failed open and, at approximately 11:58 p.m.,

operators manually tripped the reactor from approximately 24.5 percent power (Section 01.5).

The unit was in Mode 3 at the end of this inspection period.

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1. Operations 01 Conduct of Operations 01.1 General Comments (71707)

The inspectors observed routine and nonroutine operational activities throughout this inspection period. Some of the activities observed included:

• Outage turnovers (Unit 3)

Core reload (Unit 3)

Core reflood (Unit 3)

Reactor coolant pump (RCP) sweeps (Unit 3)

• Reactor' coolant system (RCS) heatup (Unit 3)

• Shutdown margin calculation for withdrawing shutdown control element assembly Bank B (Unit 3)

Operators were thorough and methodical in preparing for and conducting routine i evolutions. Close management and supervisory oversight of operational activities were evident. Procedure use and operator communications were generally consistent with written licensee management expectations. Specific comments on activities are discussed below.

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-2-01.2 Cross-Tie of Vital Busses D1 and D3 - Unit 3 a. Inspection Scope (71707)

The inspectors monitored the cross-tie of Vital DC Busses D1 and D3. The inspectors reviewed Procedure SO23-6-15 " Operation of 125 VDC Systems," Revision 13; Action Request (AR) 990400426; and Leadership Observation Program Reports 99001925 and 1 99001941.

b. - Observations and Findinas On April 5,1999, the inspectors observed a prejob briefing and the performance of a cross-tie of Busses D1 and D3 (energizing Bus D1 from the D3 battery and charger).

The briefing was attended by the shift technical advisor, the Operations assistant plant superintendent, and a Nuclear Oversight representative, in addition to the personnel directly involved in performing the evolution. The project coordinator performed the

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briefing and used a white board to display the electrical alignment required throughout the evolution. A cross-tie overview handout was given to personnel.

The inspectors observed operator performance during the cross-tie evolution. The operators used good self-verification. One section of the procedure indicated that the steps should be performed as rapidly as possible to minimize battery bank discharge, since the battery charger was momentarily disconnected. The operator performed a 4 walkthrough of the steps to become familiar with the component locations and then j properly performed the required steps. Independent verification was properly performed by an additional operator.

The inspectors reviewed the observers' comments (AR 990400426 and Leadership Observation Programs 99001925 and 99001941) about the evolution. The assessments of the performance accurately reflected the performance of personnel involved in the evolution and documented minor improvement items where necessary.

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c. Conclusions The licensee's assessment of a vital dc bus cross-tie evolution accurately reflected Operations and Maintenance personnel performance. The overall performance of the evolution (prejob briefing, equipment manipulation, and independent verification of components) was good.

01.3 RCS Draindown - Unit 3 a. Inspection Scope (71707)

The inspectors observed Unit 3 control room operators drain the RCS from 6 inches belou the reactor vessel flange to 26 inches above the bottom of the hot legs, in order to rernove steam generator (SG) nozzle dams. The inspectors reviewed portions of -

Procedures SO23-3-1.8, " Draining the Reactor Coolant System," Temporary Change Notice 14-1, and SO23-5-1.8.1, " Shutdown Nuclear Safety," Temporary Change

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-3-Notice 7-1. The inspectors reviewed portions of Operations Division Manual ODM-44,

" Professional Operator Development and Evaluation Program," Revision 0.

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b. Observations and Findinas )

The RCS draindown, performed on April 29,1999, was accomplished in a well-controlled manner. All level monitoring instruments, which included a local sight glass, the reactor wide-range level indicator, the digital level monitoring system, and ,

incore heated Junction thermocouples, were available and functioned well. The various )

level monitoring systems agreed within licensee specifications (2 inches) throughout the ]

draindown. The shift superintendent, the Operations plant superintendent, and the i Operations manager observed and, when appropriate, supervised operations from the l control room.

In some instances, communications among reactor operators performing the draindown were poor. During component manipulations, operators failed to designate valves and instruments completely, referring to components as "our manual mini-flow block," "my low level alarm," or"the valve" and coordinating valve manipulation by saying "you can" shut a valve, as opposed to using a direct order (i.e., " shut valve xx"). Using incomplete component identification was contrary to licensee management expectations, as expressed in Manual ODM-44, which stated in Section 3.6 that the component number and noun name should be used. The poor communication was limited to interactions among reactor operators in the control room. Communications between senior reactor operators and reactor operators, and reactor operators and field operators, were more complete and formal with respect to component identification.

c. Conclusions Communication practices among control room operators during the Unit 3 RCS draindown to midloop were poor and not in accordance with licensee management expectations. Incomplete and general component identifications were frequently verbalized while preparing for, and during, component manipulations. However, the overall performance of the evolution was acceptable.

01.4 Reactor Trio Resultina from Feedwater Reaulatina Valve Closina - Unit 3 .

a. Inspection Scope (71707. 93702)

The inspectors responded to the site and reviewed licensee actions following a reactor trip on May 13,1999. The inspectors observed operator actions and control room indications, attended the posttrip review meeting, and reviewed control room logs and ARs documenting aspects of the event.

b. Observations and Findinas

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During the initial power ascension following the Cycle 10 refueling outage, the licensee experienced various performance problems with the feedwater control systems. These problems included the extraction steam to second point feedwater Heater 3E038

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-4-automatically isolating on heater high level (level control problems in first point feedwater Heater 3E037 caused steam, instead of water, to drain to Heater 3E038),

abnormal performance of reheater bleed steam drain tank level controls, and an unexplained occurrence of both feedwater regulating valves drifting open from 60 to 70 percent on May 12. Operators stabilized the unit at 97 percent power while investigating these problems.

On May 13, instrument and Control technicians obtained voltage readings on Feedwater t

Regulating Valve 3FV1111, which controls feedwater flow to SG 3E089, in support of the troubleshooting efforts. The technicians then began taking voltage readings in the control cabinet for Feedwater Regulating Valve 3FV1121, which controls feedwater flow to SG 3E088. While in the process of taking the readings on Feedwater Regulating Valve 3FV1121, the valve unexpectedly closed. This resulted in both main feedwater pumps tripping on high discharge pressure. At 9:44 p.m., operators manually tripped the reactor in anticipation of an automatic reactor trip on low SG water level and manually initiated auxiliary feedwater.

All systems responded as designed to the reactor trip. Operators stabilized the unit in Mode 3 at normal operating pressure and temperature. The inspectors responded to the event and observed that control room indications were consistent with those of an uncomplicated reactor trip. Several managers, including the Operations manager and the Vice President-Nuclear Generation, were in the control room, overseeing the pesttrip activities. Operator response to the event was good.

The specific cause of the valve closure was not known at the time of the posttrip review meeting at 9 a.m. on May 14. However, the licensee ultimately determined that the valve closure resulted from a faulty control card in the control loop. During Operations acceptance testing, after the control card was replaced, operators identified that two of I the four bolts connecting the actuator to the valve had broken. The bolts were made of l stainless steel instead of carbon steel as designed. The licensee determined that the broken bolts were unrelated to the valve performance problem that caused the reactor l trip. The licensee initiated AR 990501187 to document the reactor trip. In addition to an

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assignment for assessing the root cause of the event, the AR included an Event Report Level 1 (most rigorous investigation level) assignment for evaluating performance issues related to the event.

Following resolution of the identified feedwater control system problems, the licensee restarted the reactor on May 15, c. Conclusions After the SG 3E088 feedwater regulating valve closed because of a faulty control card and the subsequent automatic trip of both main feedwater pumps on May 13,1999, operator actions to manually trip the Unit 3 reactor from 97 percent power were appropriate. Licensee response to the event was characterized by good management oversight and thorough initial event investigation.

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? 01.5 . Reactor Trio Resultina from Feedwater Reaulatina Valve Ooenina - Unit 3

~ a. insoection Scooe (71707. 93702)

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The inspectors were notified that at 11:58 p.m. on May .15,1999, the Unit 3 reactor was manually tripped from approximately 24.5 percent power after Feedwater Regulating Valve 3FV1111 failed open. The inspectors responded to the site and reviewed :

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. licensee actions, control room indications, and historical plant data trends for the time :

period of the trip. The inspectors attended licensee meetings and reviewed control room logs and ARs documenting aspects of the event. The inspectors also reviewed Procedure SO23-0-25, " Trip Transient Review," Revipion 2, completed for the subject manual trip and Procedure SO23-15-52.A, "52 A06 SG1 E089 Level Hl/LO," Temporary Change Notice 2-1, the annunciator response instruction for high SG 3E089 level.

b. - Observations and Findinas On May 15, the main turbine was on the turning gear with the steam bypass control system dumping main steam to the condenser. Operators received a high level annunciator for SG 3E089 and observed that Feedwater Regulating Valve 3FV1111 was opening. The operators took manual control of Feedwater Regulating Valve 3FV1111 and attempted to close the valve; however, the valve continued to drift open. The operators then took manual control of the SG 3E089 level master controller and attempted to lower SG level. The SG 3E089 main feedwater bypass valve closed; however, Feedwater Regulating Valve 3FV1111 continued to open and SG 3E089 level continued to rise. The operators then stopped one of the two operating main feedwater pumps, Pump P063. SG 3E009 water level continued to rise, pretrips on high SG level were received, and Channel A reactor trip on high SG level was received (two of the four trip channels will cause a reactor trip). With SG 3E089 level at approximately 89 percent narrow range, the operators manually tripped the reactor. Operators then stopped the other main feedwater pump and initiated auxiliary feedwater. The trip was uncomplicated, and operators stabilized the unit in Mode 3 at normal operating temperature and pressure. AR 990501305 was initiated to document the evaluation of this event.

The inspectors reviewed RCS temperatures and SG level data, observed that no excessive RCS cooldown occurred (the RCS did cool down approximately 13*F from normal operating temperature), and noted that SG 3E089 level did not rise above 190 percent narrow range. The operators manually initiated a reactor trip in anticipation of the automatic trip and appropriately entered and completed emergency operating instructions. Operator response to the event was good and in accordance with appropriate procedures.

The licensee determined that the valve failure resulted from a malfunction in the air actuator for the valve. A pneumatic posit;oner, which ports air to relays that open and

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close the valve, had failed. Consequently, automatic or manual signals to change va!ve ,

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position were not successful. The pneumatic positioner was replaced and Feedwater Regulating Valve 3FV1121 was verified to function properly. At the end of this inspection, the licensee continued to assess the failure mode of the pneumatic

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c. Conclusions Af ter the SG 3E089 feedwater regulating valve failed open because of a faulty pneumatic positioner on May 15,1999, operator actions to manually trip the Unit 3 reactor from 24 percent power were appropriate. Operator response to thn trip was good. Operators followed appropriate procedures and avoided an excessive RCS cooldown that could have resulted from the nonresponding, open feedwater regulating valve.

II. Maintenance M1 Conduct of Maintenance M1.1 General Comments a. Insoection Scoce (62707)

The inspectors observed all or portions of the following work activities:

• ' Saltwater from component cooling water (CCW) Heat Exchanger Valve 3HV6497 lubricant inspection (Unit 3)

• Volume control tank discharge Valve 3LV0227B feeder Breaker 38Z10 relaying and control preventive maintenance (Unit 3)

• CCW Train A surge tank nitrogen leak test (Unit 3)

• Test of CCW Train A Backup Nitrogen Regulator 3PCV6414 (Unit 3)

• - Motor-operated valve testing of the safety injection and containment spray i I

miniflow to the refueling water storage tank (Unit 3)

• SG tube plug insertion (Unit 3)

• CCW Heat Exchanger 3ME002 cleaning and coating (Unit 3)

• Installation of field change notice for emergency safety features testing in Train A Dome Air Circulation Fan 3B0419 (Unit 3)

• Reassembly of Valve 3HV9348, Train A refueling water storage tank miniflow Header 1502 (Unit 3)

• Repair of Train B CCW Heat Exchanger 3ME002 manway seating surface (Unit 3)

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Postmaintenance testing for RCP 3MM002 (uncoupled motor run) (Unit 3)

• Troubleshooting Control Element Assembly 91 motion failure sensor alarm (Unit 3)

Reconnection of control element drive mechanism cable (Unit 3)

b. Observations and Findinas The inspectors found the work performed under these activities to be thorough. All work observed was performed with the work package present and in active use. Technicians

. were knowledgeable and professional. The inspectors frequently observed supervisors and system engineers monitoring job progress, and quality control personnel were

- present whenever required by procedure. When applicable, appropriate radiation controls were in place.

In addition, see the specific discussions of maintenance observed under Sections M2.1, M2.2, and M4.1, below.

M1.2 General Comments on Surveillance Activities a. ' Inspection Scope (61726) '

The inspectors observed all or portions of the following surveillance activities:

• Train B Emergency Diesel Generator (EDG) 2G003 monthly surveillanco (Unit 2) )

• High Pressure Safety injection Pump 2P018 inservice test (Unit 2)

• Train A EDG 2G002 monthly surveillance (Unit 2)

Train B EDG 2G003 24-hour run (Unit 2) ,

• Train B EDG 2G0031-hour operability test (Unit 2)

• Dynamic test of Trip Throttle Valve 3HV4716 for Auxiliary Feedwater Pump 3P140 (Unit 3)

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• Lift setpoint test of Main Steam Safety Valve 3PSV8415 (Unit 3)

b. Observations and Findinas The inspectors found all surveillances performed under these activities to be thorough.

All surveillances observed were performed with the work package present and in active use. Technicians were knowledgeable and professional. The inspectors frequently observed supervisors and system engineers monitoring job progress, and quality control l personnel were present whenever required by procedure. When applicable, appropriate

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I M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Dearaded Shutdown Coolina System (SDC) Check Valves - Units 2 and 3

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a. Insoection Scope (61726. 62707. 71707)

The inspectors monitored licensee actions in response to indeterminate results of a check valve inservice test in Unit 3. The inspectors reviewed the surveillance test results; ARs 990301848,990400292,990400824, and 990400907; Unit 2 safety injection system Piping and Instrumentation Drawing 40112D; radiographs of similarly-designed check valves; portions of the Updated Final Safety Analysis Report; and Amendment Application 187, submitted on April 24,1999. The inspectors also j observed various repair activities in Unit 2 on April 27,1999, b. Observations and Findinas Valves MU200 and MU202 are 14-inch swing check valves in the SDC return line at the suction of Low Pressure Safety injection Pumps P016 and P015, respectively. Both check valves are isolable from the low pressure safety injection pump suction, and from the safety injection flow path, by normally locked open manual isolation valves. l The licensee performed a periodic inservice test of the Unit 3 valves on March 27, while the unit was in Mode 4, using Surveillance Operating instruction SO23-3-3.31.7,

" Containment Spray /SDC Valve Testing-Cold Shutdown and Refueling Interval,"

Temporary Change Notice 4 2, Attachment 2. The test of the closed function of the check valves was based on leakage rates from the system. However, the licensee determined that leakage past boundary valves in the system invalidated the test results.

The licensee then contracted a radiography service to radiograph the valves to verify the valve function. The radiographs revealed that the check valvos were closed. However, the radiographs did not definitively show the nuts (one per valve) that secure the disc to the hinge. Disc nut pins that secure the nut to the disc stem were clearly shown. After the unit was defueled and SDC was not required, the licensee disassembled the Unit 3 check valves and found that the nuts had corroded away. The licensee determined that the nuts, which were supposed to be stainless steel, had actually been made of carbon l steel, which was vulnerable to corrosion in a boric acid environment.

The licensee performed an operability assessment for the Unit 3 check valves, documented in AR 990400907. The operability assessment stated that the safety

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function of the check valves was to remain closed during the injection and recirculation l phases of an accident, and to open when SDC was placed in service for long-term l cooling for some accidents. Reclosure was not required. The licensee determined that the check valves could perform their design function, even under seismic conditions, with credit taken for the strength of the disc nut pins. The inspectors determined that the operability assessment was rigorous and was consistent with information in the Updated Final Safety Analysis Report.

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There are eight other safety-related check valves in each unit of a similar design to Check Valves MU200 and MU202. Of these, all but two were periodically rn:iographed as part of the inservice test. The licensee reviewed the radiographs for all taese check valves in both units and determined that the nuts were clearly in place in those check valves. The inspectors also reviewed the radiographs and verified the results. The other two check valves in each unit were of a lower pressure rating than Check Valves MU200 and MU202 and had been disassembled and inspected between 1986 and 1988 and found to be intact. The licensee determined that only Check Valves MU200 and MU202 in Unit 2 required additional inspection to establieh their condition. During the recently-completed Unit 2 refueling outage, these Unit 2 check valves had passed inservice tests, based on the leakage rate method, and were considered operable.

On April 22 the licensee radiographed Check Valves MU200 and MU202 in Unit 2. The radiographs indicated thtc Check Valve MU202 had a partial nut and that Check Valve MU200 had no nut. The disc nut pins were in place on both check valves, and the I

licensee determined that the check valves were operable but degraded.

The licensee determined that, although there were no Technical Specificatione that applied directly to SDC in Modes 1 through 3, some license commitments and accident analysis assumptions would not be able to be satisfied if SDC was removed from service to repair the check valves. The licensee evaluated the risks associated with repairing tb check valves at power and identified several contingency measures that l could ha taken to minimize the risks. A license amendrr.ent application was submitted !

on Ap.il 24 that described the risks and contingency measures. A one-time temporary l amendment was granted on April 26 that allowed Unit 2 to be outside the licensing basis during the period of the repair, j On April 27 the licensee repaired Check Valves MU200 and MU202 in Unit 2. The inspectors observed the as-four.d condition of the nuts and determined that approximately 70 percent of the nut in Check Vahn MU202 had corroded away and that the disc nut pins were in place. The inspectors observed that the disc of Check Valve MU200 did not appear to have been forced against the pin and determined that forces other than the pin strength had held the disc in place. The repairs were completed in one day.

During the repair activity, several gallons of radioactive water were forced (sprayed) out of the bonnet of Check Valve MU202 when the disc on Check Valve MU200 was opened. Two Boiler and Condenser technicians, and one Health Physics technician, were wetted by the water. Actions taken by Health Physics technicians on the scene, in response to the we".ing, wore good.

Water trapped between Check Valves MU200 and MU202 flowed out of the lower valve, Check Valve MU202. Personnel had opened a drain valve (MR031) and a vent valve (MR209) between Check Valves MU200 and MU202, in order to drain the pipe between the two check valves; however, the vent valve had not been effective in alleviating the pressure lock of the water between Check Valves MU200 and MU202. Before the repair

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activity commenced, the licensee had discussed the possibility that the "Kerotest' vent valve (MR209) might not provide a sufficient vent, but had taken no precautions to ensure that the piping between Check Valves MU200 ar d MU202 was effectively drained. The licensee documented this event in AR 990402248.

The inspectors found that Operations and Maintenance personnel, aware that the planned vent path might not provide for effectively draining the radioactive water from the piping, were not proactive in preventing workers from being sprayed by the water.

However, the workers were wearing appropriate protective clothing, and the radiological response to the occurrence was good.

The licensee determined that the four check valves (MU200 and 202 in both units) with ,

the incorrect nuts had been assembled by the vendor within 1 day of each other. Of the !

similarly-designed check valves installed in Units 2 and 3, only these four valves had bonnet nuts that were the same size as the disc nuts. Further, it was probable that tha vendor had incorrectly used carbon steel nuts, which were appropriate for the bonnets, j for the disc nuts. The licensee was communicating with the vendor regarding I reportability of the condition pursuant to 10 CFR Part 21.

The licensee had installed the check valves in 1984 and 1982 in Units 2 and 3, respectively. The licensee identified that there were indications during the installation process that all four valves had been disassembled to gain access to internal joints for fit-up and to secure a purge path. During the licensee's root cause investigation, no indication was found that the disc nuts had been replaced during the reassembly of the valves and, therefore, the carbon steel nuts were reinstalled during the original installations in 1984 and 1982.

10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality shall be prescribed by documented drawings and shall be accomplished in accordance with these drawings. Drawing SO23-408-1-6-275 indicated the check valve disc nuts contained stainless steel. However, the licensee installed check valves with carbon steel disc nuts. The failure to err ure that shutdown cooling check valve disc nuts were installed with stainless steel nuts was a violation of Criterion V. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 361; 362/99006-01). This violation is in the corrective action program as AR 990400907.

c. Conclusions The licensee aggressively pursued inconclusive results of an inservice test and identified that the check valve disc nuts in the SDC return line to the suction of the low piessure safety injection pumps had corroded away, rendering the check valves degraded but operable. The licensee determined the nuts were carbon steel instead of stainless steel as designed. The licensee effected prompt repairs in both units and implemented appropriate compensatory measures to reduce the risks associated with the repairs in the operating unit.

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A noncited violation (Enforcement Policy, Appendix C) of 10 CFR Part 50, Appendix B, Cnterion V, was identified because the licensee installed SDC check valves with carbon steel disc nuts instead of stainless steel nuts, and the nuts corroded away. This occurred in 1984 and 1982 in Units 2 and 3, respectively. This violation is in the corrective action program as AR 990400907.

Operations and Maintenance personnel, aware that the planned vent path might not provide for effectively draining the contaminated water from SDC piping in preparation for check valve repairs, were not proactive in preventing workers from being sprayed by water. However, the workers were wearing appropriate protective clothing, which prevented personal contamination. The radiological response to the occurrence was ,

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M2.2 Containment Debris - Unit 3 a. Insoection Scoo_e (71707)

On May 5,1999, Unit 3 was in Mode 5, and operators were preparing to transition to Mode 4. Operations had completed a containment walkdown in order to identify and remove loose debris and in preparation for Mode 4 entry. The inspectors walked down portions of the Unit 3 containment.

l b. Observations and Findinas The inspectors found that, overall, the Unit 3 containment was free of loose debris and clean. However, the inspectors did identify a pair of pliers in an SG 3E088 keyway.

Each SG has two keyways that allow the SG to move away from and toward the reactor, allowing for thermal expansion or contraction of the RCS piping. The pliers could have interfered with this SG movement or increased stress on the RCS pipe or the SG support while the RCS was thermally expanding. The inspectors had previously found debris in SG keyways during a Unit 2 outage, as documented in NRC Inspection Report 50-381; 362/98-03, Section M2.1. The inspectors also found a yellow rubber boot underneath a walkway. The licensee removed both items prior to Mode 4 entry.

The inspectors observed that a fan screen for Containment Recirculation Unit 3MA353 was torn (apparently because of corrosion) such that approximately 25 percent of the screen was not secured to the fan base. Recirculation Unit 3MA353 is located insioe the bioshield, near the containment emergency sump. The inspectors judged that the screen was sufficiently attached to the approximate 4-foot diameter fan basa. The licensee generated AR 990500422 to initiate screen repairs or replacement. In addition, a cable associated with RCP 3P003 seal bleed off instrumentation had substantial portions of rubber insulation missing; however, the wire mesh under the insulation was intact. The licensee evaluated this condition as acceptable fo< Mode 1 operation, c. Conclusions Containment loose debris inspections in Unit 3, conducted by the hcensee prior to Mode 4 entry, were generally effective. However, the inspectors .centified several items that the licensee missed, including a pair of pliers in an SG keyway and a fan screen that was partially unsecured from the, fa base because of corrosion.

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M4 Maintenance Staff Knowledge and Performance M4.1 Reactor Vessel Foreian Material Insoections - Unit 3 a. Insoection Scope (62707)

The inspectors assessed licensee actions in response to loose debris discovered cn the core plate during loose debris inspections and to a cotton cloth that was accidentally j dropped from the resueling bridge into the defueled reactor vessel. The inspectors reviewed ARs 990400684 and 990401577 and portions of Procedure SO123-I-1.18,

Foreign Material Exclusion Control," Temporary Change Notice 4 2. The inspectors also discussed these issues with refueling and Maintenance personnel, b. Observations and Findinas On April 9,1999, the licensee generated AR 990400684 to document several pieces of foreign material on the core plate identified after core offload during a loose debris i inspection. The objects included twc nut and bolt pieces, three pieces of a broken thermowell, two square pieces of metal, and one metal scraping. The licensee removed l the foreign objects and found them to be irradiated, indicating they had been in the RCS during unit operation. Based on the number and size of objects identified, the inspectors found that the identification of foreign objects was thorough.

The pieces of thermowell were considered by the licensee to have come from an RCS thermowell that had broken off and caused a unit shutdown during September 1996, as documented in NRC Inspection Report 50-361; 362/96-11, The licensee postulated that the approximate 9%-inch broken thermowell piece had broken again into the three smaller pieces identified. The inspectors noted that during 1996, when this thermowell had broken off and was not retrieved from the RCS, the licensee had analyzed and determined the thermowell could not get to a location where it could damage fuel, because the thermowell was too big. Since three pieces of the thermowell were discovered on the core plate, the inspectors found that the 1996 analysis did not realistically account for the possibility of the thermowell breaking into smaller pieces. l The licensee was unable to determine the exact origin of the other foreign material. i

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None of the material appeared to be indicative of reactor or supporting system failures, but rather of poor foreign material control at some point in the past.

The inspectors observed that the licensee left the foreign material described above in place on the core plate until a designated time for debris removal prior to core reload, as allowed by procedure. Refueling cavity level changes and initiation of GDC took place in between the time that the foreign material was discovered and the time it was removed.

Water flow had the potential to cause foreign material to shift position or f all below the core plate, requiring relocating the object and possibly complicating retrieval. The inspectors concluded that allowing a time lapse between foreign object discovery and retrieval, with activities allowed that could change the position of the foreign material, was a poor practice.

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-13-On April 21, a refueling person accidentally dropped a 12- by 22-inch white cotton towel into the reactor vessel during a debris inspection that was conducted after the removal of the objects discussed above. The core was defueled, and SDC was in service. The towel was drawn into a hot leg nozzle, and a short time later refueling personnel observed many tiny pieces of the towel flowing through the reactor vessel. The towel j had been forced through the SDC loop and shredded, probably by Low Pressure Safety i Injection Pump 3P015, which was in service as the SDC pump. The licensee generated AR 990401577. The licensee conducted visualinspections of the SOC Heat Exchanger 3E004 tube sheet, which had been in service at the time, and discovered and removed small pieces of the towel. An inservice test revealed no indication of damage to Pump 3P015. Filtration units were used in the refueling cavity to remove cotton particles suspended in the water. The licensee determined that cotton would dissolve into carbon dioxide and water at approximately 437 F, so any remaining cotton l in the RCS would be dissolved as the unit was heated up to normal operating I temperature.

The inspectors reviewed portions of Procedure SO123-1-1.18 and determined that no procedural violations had occurred. The use of the cotton towel, unsecured by a lanyard, was provided for in the program. The licensee was evaluating discontinuing the use of cotton towels above the refueling cavity, instead using disposable wipes that would more readily disintegrate. The inspectors found that the response to the dropped cotton towel was acceptable. Because the cotton was removed from the limiting portion of the emergency core cooling system not subject to normal operating temperature (the SDC system tube sheet) and expected to dissolve at normal operating temperature, the inspectors noted that the cotton would not clog emergency core cooling piping, valves, and nozzles with the unit in Mode 1.

c. Conclusions Loose incore debris inspections conducted during the Unit 3 refueling outage were thorough. Foreign objects identified were removed; however, a time delay between object identification and removal, with no restrictions on level and flow changes in the reactor vessel, had the potential to cause identified objects to change position and become unretrievable. This delay was a poor practice.

M8 Miscellaneous Maintenance issues (92700)

M8.1 (Closed) Licensee Event Recort (LER) 206: 361: 362/98-005-00: radiological effluent Technical Specifications flow indicator surveillance not performed.

in 1998 the licensee determined that, since 1982 when the sample flow rate measuring device was inoperable, compensatory sampling to verify sample flow rates for the Unit 3 condenser air ejector wide-range gas monitor had not been performed at the required interval. The requirement to perform the verification was remoud from Technical Specifications Table 3.3-13 and moved to the Offsite Dose Calculation Manual in 1990.

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The licensee interpreted the Technical Specifications requirement to mean that verification of the sample flow rate was required in the out-of-service radiation monitoring system. However, whenever the normal radiation monitoring system was out of service, auxiliary sampling equipment with its own sample flow rate instrumentation was placed into service; therefore, not determining the sample flow rate was inconsequential.

The auxiliary sampling equipment uses the same nozzle for sampling as the permanently installed equipment, but the sample flow rate is fixed. Changes in the process flow rate could result in the sample not being truly isokinetic. For this reason, I use of the permanently installed equipment was preferred. The auxiliary equipment was caly used during periods of maintenance on the permanent equipment, and these periods of operation of the auxiilary sampling equipment were reported in the annual effluents report to the NRC.

The licensee identified that, in one instance in 1998, licensee personnel had missed a procedural requirement to verify the sample flow rate on the auxiliary sampling equipment once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The verification had occurred 12 minutes late. During i the subsequent investigation, the licensee determined the required interval for f performing the flow estimate was every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. i The licensee initiated actions to clarify the Offsite Dose Calculation Manual, so that estimates of flow would not be required when flow measurement instrumentation was functioning and to apply the verification requirement to the auxiliary sampling equipment. Procedure changes were initiated to correct the verification internal.

The failure to perform the sample flow estimates was a violation of Technical )

Specification 3.3.3.9 (the Technical Specifications in effect prior to August 1996) and was in the corrective action program as AR 981000410. This failure constitutes a violation of minor significance and is nct subject to formal enforcement action.

I M8.2 (Closed) LER 361: 362/98-023-00: missed surveillance of fire detector circuit !

supervision inside containment. l The licensee determined that procedure changes made in 1987 resulted in inadvertently changing the frequency of fire detector supervisory circuit surveillance tests such that '

the requirements of Technical Specification 4.3.3.7.2 (effective prior to August 1996)

and Licensee Controlled Specification Surveillance Requirement 3.3.106.3 (effective j since August 1996) were no longer correctly implemented. This resulted in the i

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surveillance intervals being exceeded in Units 2 and 3 since December 1986 and February 1986, respectively. This was a violation of Technical Specification 4.3.3.7.2 (pre-1996) and Technical Specification 5.5.1.1.a (post-1996). This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC I Enforcement Policy (NCV 361; 362/99006-02). This violation is in the corrective action program as AR 981001241.

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i E2 Engineering Support of Facilities and Equipment E2.1 RCP Remote Oil Fill Reconnection - Unit 2 a. Insoection Scope (37551)

The inspectors performed a walkdown of the remote oil fill capabilities and reviewed the reconnection of a remote fill capability for the RCPs. The inspectors reviewed ARs 990201434 and 990300146 and Maintenance Orders 99030643 and 99031981 and discussed the reconnection with Station Technical.

b. Observations and Findinas During the Unit 2 refueling outaga, the licensee reconnected the remote fill capability for the RCP lower bearing oil reservoirs (except for RCP 2P002, which was alread/

connected). This allowea the filling of the lower reservoir from a remote hopper on the side of the motor instead of locally near the reservoir. However, except for RCP 2P002, the remote fillline and hopper extended beyond the boundaries of the RCP oil collection system. These additional components were normally dry and did not contain oil, except during tha actual filling process when the oil gravity flows to the reservoir. Therefore, the licensee performed an evaluation to determine the acceptability of using the remote fill capability. The licensee concluded that the remote fill capability did not invebre an unreviewed safety question and was acceptable for use. )

On February 19,1999, the inspectors performed a walkdown of the remote fillline and hopper for the RCPs. The inspectors concluded that the like!ihood of leaks from the remote fill station during RCP operation did not exist and that the likelihood of leaks during filling of a reservoir from the remote fill station were negligible.

The licensee recognized several advantages of using the remote fill station. Using the local fill station involved personnel climbing onto support structures and being in a high radiation field. The radiological exposure to the person performing the fill process was .

estimated to be 600 mR. The evolution would require the use of 8 to 10 liter-size bottles I of oil to return a reservoir to appropriate level. Using the remote fill station, the person performing the fill woula Jse the normal access from the 45-foot elevation with a single container of oil and receive approximately 10 percent of the dose. The licensee !

concluded that this would reduce the potential for inadvertent spillage of oil and significantly reduce personnel exposure.

The inspectors reviewed the safety evaluation and observed that the evaluation indicated that there would be oil in the fill line for a short duration (minutes per fill). )

However, the inspectors reviewed the computer-generated historical trend for the i RCP 2P004 lower reservoir fill that occurred on April 2. The inspectors obseved that it l took the oil approximately 7.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> to go from the hopper to the reservoir. The i inspectors questioned a Station Technical engineer about the discrepancy. The

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-16-engineer had also observed that the time to drain the oil from the hopper to the reservoir took longer than estimated and discussed the observation with supervision. Station Technical concluded the safety evaluation remained valid. The inspectors cor$ curred with the engineer's determination that the eva!uation remained valid and concurred with the conclusion that using the remote RCP fill station did not result in an unreviewed safety question.

The inspectors reviewed the additional administrative actions that the licensee planned for the use of the remote fill station. The licensee used the remote fill station to add oil to RCP 2P004 on March 19 and April 2. Prior to each fill, the remote oil fillI;nes were visually inspected for integrity. Shortly after the oil addition to the hopper, the fill lines were visually inspected for leakage. These activities were specified in the maintenance orders for the oil addition, in addition, the cognizant engineer monitored the reservoir level change on the plant computer. j i

On March 19 the licensee performed a walkdown of RCP 2P004. Oil level was low; however, the licensee was unable to locate the source of the leaking oil. The licensee concluded, therefore, that the oil was being captured by the oil collection system. The licensee verified that the drain collection tanks were empty (the tanks require approximately 20 gallons of oil before indicating on the sight glass). The licensee planned to track the total accumulated oil into the drain collection tanks to ensure there j was sufficient room to receive the oil from two RCPs, as required by design. '

c. Conclusions The use 'of the remote fill station for adding oil to the lower oil reservoir for RCP 2P004 was acceptable. The compensatory measures to verify the condition and integrity of the remote oil fill lines before and during use, including additional administrative measures to track the oil usage, were appropriate. Based on a pump walkdown, the licensee concluded that the leaking pump oil was being captured by the oil collection system.

E2.2 Mechanical Nozzle Seal Assembly (MNSA) Installation - Unit 3 a. Inspection Scope (37551) j The inspectors reviewed AR 990400369 and Nonconformance Report 990400369 and l

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physically inspected the modified MNSA after installation on the nozzle for Level Instrument 3LT-0110-1 on the Unit 3 pressurizer.

b. Observations and Findinas Several inconel-600 instrument nozzles in Units 2 and 3 had been identified as having developed cracks resulting in pressure boundary leakage, as discussed in Section E8.4. 1 The licensee obtained approval for installing MNSAs on some nozzles, in lieu of  !

performing weld repairs. MNSAs were also planned for precautionary installation on some nozzles, including Level Instrument 3LT-01101, which had not yet been identified as having leaked.

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l-17-During the 1998 Unit 3 Cycle 9 midcycle outage, the licensee drilled six mounting holes

! in the pressurizer lower end bell with which to mount an MNSA on the nozzle for Level Instrument 3LT 0110-1. This condition was documented in Nonconformance i Report 980301521, and a modified MNSA was fabricated for installation during the Cycle 10 refueling outage.

During the Cycle 10 refueling outage, the licensee attempted to install the modified MNSA on Level Instrument 3LT-0110-1. However, the licensee found that the previously-drilled holes were not correctly aligned and that the modified MNSA could not be installed without further modification. The orientation of the holes was approximately 12 degrees off center and, because of the curvature of the end bell at the nozzle location, an adequate seal could not be developed with the MNSA in that orientation.

AR 990400369 and Nonconformance Report 990400369 were initiated to address the deficiency. The licensee again modified the MNSA and installed it on Level Instrument 3LT-0110-1 before the end of the outage.

The licensee initiated a Level 3 event report assignment as part of AR 990400369. The intent of the event report was to determine the performance deficiencies that resulted in the misaligned mounting holes. The evaluation was stillin progress at the end of the i

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inspection period.

c. Conclusions Engineering performance deficiencies resulted in MNSA mounting holes in the Unit 3 pressurizer being misaligned such that the assembly had to be redesigned before installation.

E8 Miscellaneous Engineering lasues (90712,92700,92903)

E8.1 (Closed) LER 361: 362/93-006-01: licensing basis for Units 2 and 3 tornado-generated missile barriers not fully met.

This voluntary LER supplement reported additional examples of missile barrier design deficiencies previously identified in 1993. The licensee determined that, because the total annual probability of damage to critical components met the acceptance criteria of the Standard Review Plan, no physical changes to the existing barriers were necessary.

An amendment to revise the licensing basis for tornado-generated missile barrier protection had been submitted and was still under review by the NRC.

E8.2 (Closed) LER 361: 362/98-016-00: EDG fuel storage tank volume outside design basis.

During a review of design calculations, the licensee determined that the EDG fuel storage tanks did not provide the design basis volume with only the volume above the fuel transfer pump low-low level trip setpoint available. Licensee procedures did not permit operators to override the trip. The licensee revised alarm response procedures to defeat the transfer pump trip under accident conditions, thereby mak.ing the additional required fuel available.

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The licensee characterized the condition as having no safety significance because:

(1) the onsite fuel supply could be replenished before the available fuel was consumed; (2) the calculations assumed that all loads were carried by one EDG; however, there would be sufficient fuel if the redundant EDG was operating; or if only one EDG was operating, the fuel from the other EDG could be transferred to the operating EDG; and (3) the deficiency was offset by a 10 percent margin in the design basis volume. l After identification of the volume deficiency, the licensee temporarily implemented an administrative fuel storage tank minimum level of 93 percent,4 percent greater than the level required by Technical Specification 3.8.3. The licensee established thi's compensatory measure because personnel did not initially recognize that variances in the fuel quality (API gravity) within the range addressed in the Technical Specifications were encompassed by the 10 percent design margin. The limit was restored to the $

Technical Specifications value after the alarm response procedure had been changed.

The licensee subsequently implemented changes to the emergency operating instructions to reflect changes in the owners' group guidance, CEN-152, Revision 4.

These changes included no longer starting and running the third-of-a-kind high pressure safety injection pump during an event, so that only one high pressure safety injection :

pump would be running in each train. This change significantly reduced the diesel load during the most limiting accident scenario. Other less significant changes in diesel loading requirements were also implemented, as reflected in Calculation M'0016-008, ,

Calculation Change Notice 4. On the basis of this calculation, the licensee dewenined i that the fuel storage tank volume was acceptable without reliance on the ability to j override the fuel transfer pump low-low level trip. >

10 CFR Part 50, Appendix B, Criterion Ill, " Design Control," requires, in part, that

" measures shall be established to assure that applicable regulatory requirements and the design basis . . . are correctly translated into specifications, drawings, procedures, and instructions." The failure to ensure that the EDG fuel storage tank design and procedures provided the diesel fuel volume required by the design basis was a violation of Criterion Ill. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 50-361; 362/99006-03). This violation is in the corrective action program as AR 980700697.

E8.3 Administrative Closure of Violations Based Uoon Chanaes in the Enforcement Poligy The inspectors performed an in-office review of outstanding violations in the Engineering area. The Severity Level IV violations listed below were issued in Notices of Violation prior to March 11,1999. On this date, the NRC changed the policy for treatment of Severity Level IV violations (Appendix C of the Enforcement Policy). Because these violations would have been treated as noncited violations in accordance with Appendix C, they are being closed out in this report, consistent with the new Enforcement Policy for Severity Level IV violations. The inspectors verified that the licensee had generated a corrective action program reference (AR) for each of the violations listed in addition, these violations already have docketed responses or were generated with no response required.

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-19-Violation Description Corrective Actions Number Program Reference 361;- failure to ensure inclusion of appropriate 981100386 362/98014-01 quality standards in design documents 362/97015-02 incorrect classification for Unit 3 reactor 970701233 coolant system Review of the effectiveness of the corrective actions for selected violations will be performed in the future as a routine part of the review of the corrective action program.

E8.4 (Closed) LER 361/98-002-00: RCS boundary leakage.

During the Unit 2 Cycle 9 midcycle outage in January 1998, the licensee determined that seven RCS instrument nozzles (on the RCS loops, SG bowl, and pressurizer lower end bell) had apparently leaked slightly during Cycle 9 power operations. The leakage was too slight to have been detectable during power operation, and only small traces of boric acid were observed after the unit was shut down and insulation around the nozzles was removed.

The licensee determined that the inconel-600 nozzles had cracked and replaced the outer portion of three of the nozzles with inconel-690 material. The licensee obtained NRC approval for the use of MNSAs and used these to repair the four remaining leaking nozzles. Inspection of these assemblies was discussed in NRC inspection Report 50-361; 362/98-03. All inconel-600 nozzles on the RCS loops in Units 2 and 3 were replaced with inconel-690 nozzles during the Cycle 10 refueling outages, leaving Inconel-600 only in the nozzles on the pressurizer, SGs, and reactor vessel head in both units.

Several similar occurrences have been reported by the licensee. These issues were collectively reviewed in NRC Inspection Report 50-361; 362/97-15, during which the corrective actions were reviewed. A violation was identified for failing to adequately evaluate the appropriateness of the performance of preventive maintenance prior to placing the Unit 3 RCS under a 10 CFR 50.65(a)(2) category. Additionally, a noncited violation of Technical Specification 3.4.5.2(a) was identified in NRC Inspection Report 50-361; 362/96-02. All identified leaks were promptly corrected, and a long-term corrective action plan was developed to replace susceptible nozzles by the end of the Cycle 10 refueling outages in 1999.

Technical Specification 3.4.13.a allows no RCS pressure boundary leakage in Modes 1-4, so the apparent leakage was contrary to Technical Specifications requirements. Because the licensee was unaware of the leakage while operating at power, the action required by the Technical Specifications was not taken, This was another example of the violation previously-identified as NCV 362/9600m. Because implementation of the corrective actions for the previously-identified violations had not yet been completed but would have prevented the recurrence reported in LER 50-361/98-002, no further enforcement action was deemed appropriate.

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-20-IV. Plant SuuDort R1 Radiological Protection and Chemistry controls R1.1 Badioloaical Controls in Containment Work Areas - Unit 3 (71750)

The inspectors performed several walkdowns of work areas in the Unit 3 containment during the Cycle 10 refueling outage. The radiological briefings given to the inspectors were consistent with the actual radiological conditions observed, and Health Physics technicians conducting the briefings were knowledgeable. Radiological barriers were correctly posted. Temporary shielding was installed in several areas to reduce personnel exposure. The inspectors concluded that general radiological controls for the work areas observed were adequate.

V. Manaaement Meet!nas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the exit meeting on May 19,1999. 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 identified.

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i ATTACHMENT ]

l SUPPLEMENTAL INFORMATION j l .

PARTIAL LIST OF PERSONS CONTACTED I Licensee D. Brieg, Manager, Station Technical J. Fee, Manager, Mair..enance

'J. Hirsch, Manager, Chemistry R. Krieger, Vice President, Nuclear Generation J. Madigan, Manager, Health Physcs D. Nunn, Vice President, Engineenng and Technical Services A. Scherer, Manager, Nuclear Regulatory Affairs K. Slagle, Manager, Nuclear Oversight T. Vogt, Plant Superintendent, Units 2 and 3 R. Waldo, Manager, Operations

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INSPECTION PROCEDURES USED

• IP 37551:. Onsite Engineering IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 71707: Plant Operations IP 71750: Plant Support Activities IP 90712 Inoffice LER Review

- IP 92700: Onsite LER Review IP 92901: Followup - Operations IP 92902 Followup - Maintenance IP 92903: Followup - Engineering IF 92904: Followup - Plant Support

' IP 93702 - Prompt Onsite Response to Event ITEMS OPENED AND CLOSED  !

Opened and Closed 361; 362/99006-01 NCV failure to install stainless steel SDC valve disc nuts (Section M2.1)

i 361;362/99006-02 NCV missed surveillance of fire detector circuit supervision inside containment (Section M8.2) )

361; 362/99006-03 NCV failure to ensure EDG storage tank design and procedures I correctly reflect diesel fuel volume required by design basis (Section E8.2)

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• e-2-Closed 361;362/98014-01 VIO failure to ensure inclusion of appropriate quality standards in design documents (Section E8.3)

362/97015-02 VIO incorrect classification for Unit 3 RCS (Section E8.3)

206;361;362/98-005-00 LER radiological effluent Technical Specifications flow indicator (Section M8.1)

361/98-002-00 LER RCS boundary leakage (Section E8.4)

361;362/93-006-01 LER licensing basis for Units 2 and 3 tornado-generated missile barri9r not fully met (Section E8.1)

361;362/98-016-00 LER EDG fuel storage tank volume outside design basis (Section E8.2)

361;362/98-023-00 LER missed surveillance of fire detector supervisory circuits inside containment (Section M8.2)

LIST OF ACRONYMS USED AR action request CCW component cooling water CFR Code of Federal Regulations EDG emergency diesel generator LER licensee event report MNSA mechanical nozzle seal assembly NCV noncited violation NRC Nuclear Regulatory Commission RCP reactor coolant pump RCS reactor coolant system SDC shutdown cooling SG steam generator

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