IR 05000245/1987001

Insp Repts 50-245/87-01 & 50-336/87-01 on 870106-0209.No Unacceptable Conditions Identified.Major Areas Inspected: Action on Previously Identified Items,Ie Info Notice 86-104, IE Bulletin 83-03 & LERs

ML20212M170
Person / Time
Site:	Millstone
Issue date:	02/27/1987
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20212M167	List: IR 05000245/1987001 ML20212M163
References
50-245-87-01, 50-245-87-1, 50-336-87-01, 50-336-87-1, IEB-83-03, IEB-83-3, IEIN-86-104, NUDOCS 8703110192
Download: ML20212M170 (13)

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U.S. NUCLEAR REGULATORY C0p9tISSION

. REGION I Report: 50-245/87-01; 50-336/87-01

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Docket Nos /50-336- License Nos: -DPR-21; DPR-65 Licensee:' Northeast Nuclear Energy Company-Facility: Millstone Nuclear Power Station, Waterford.-Connecticut Inspection at: Millstone Units 1 & 2 Dates: January 6, 1987 through February 9, 1987 Inspectors: Theodore A. Rebelowski, Senior Resident Inspector Geoffrey E. Grant, Resident Inspector Douglas H. Coe, Lead Reactor Engineer (Examiner)

Approved: $ #1<. @44 ./2 7/(7

'E. C. McCabe,. Chief, Reactor Projects Section 3B Date Summary: ' Report No. 50-245/87-01; 50-336/87-01 (January 6 to February 9, 1987)

Areas Inspected: This inspection included routine and NRC resident inspection (109 hours0.00126 days <br />0.0303 hours <br />1.802249e-4 weeks <br />4.14745e-5 months <br />) and regional specialist inspection (8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) of action on previously identified items,. Unit 2 shutdown items, IE Information Notice No.86-104, IE Bul-letin 83-03 (Unit 2), Licensee Event Reports (Unit 1), Electrical Buswork Insula-tion Degradation (Unit 1), Operator Requalification Program, and IE Notice 86-106 on Feedwater Line Brea Results: No unacceptable conditions were identifie "

8703110192 870303 PDR ADOCK 05000245 G PDR;

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TABLE OF CONTENTS P_ age

~ Persons Contacted.................................................... -1 Summary of Facility Activities....................................... 1 Licensee Action on Previously Identified Items....................... l' Uni t 2 Shutdown Due to Steam Generator Tube Defects. . . . . . . . . . . . . . . . . . 2 IE Information Notice 86-104, Unqualified Butt Splice Connectors in Qualified Penetrations............................................ 4 IE Bulletin 83-03, Check Valves in Diesel Service Water Systems (Unit 2)............................................................. 5 Licensee Event Reports (Unit 1)...................................... 5 Electrical Buswork Insulation Degradation (Unit 1)................... 6 Battery Maintenance Review and Observations (Units 1 & 2)............ 7 1 On-site Safety Review Committee (Unit 1)............................. 7 11. Operator Requalification Program..................................... 8 1 IE Notice 86-106, Feedwater Line Break Wall Thinning Inspection.. . . . . 10 1 Management Meeting................................................... 11

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DETAILS '

. Persons Contacted

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Mr. W. C. Romberg, Vice President, Nuclear. Operations Mr.:S'.'Scace, Station Superintendent

" Mr. J._Stetz, Unit 1' Superintendent

.Mr. J. Keenan, Unit 2 Superintendent _

Mr. J.-Kelley, Station Services Superintendent-The inspector also contacted'other licensee employees . including members.'of the Operations,- Radiation Protection, Chemistry,' Instrument and Control,

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-Maintenance, Reactor Engineering, and Security _ Departments; Summary of Facility Activities-Unit 1: Ttte unit' operated at 100% power.with minor reductions in power for condenser tube inspection and cleaning, main steam isolation valve testing .

and main feedwater regulating valve noise level monitoring, t

Unit 2: The unit remained at 100% power.until a' normal shutdown on January 29 to repair I; team generator tube defects that exceeded the 40% degradation criteria. The unit remained in cold shutdow ,

3. . Licensee Actions on Previously Identified Items (Closed) Unresolved ~ Item (50-336/84-09-06), Radiation Monitors on Atmospheric Steam Dumps and Main Steam Lines The licensee had committed to install radiation monitors on the Unit 2 main steam lines when the equipment was availabl During the 1986 re-fueling outage, three monitors were installed on the steam lines exiting containment. Plant Design Change Requests-2-18-86 and 2-050-86 placed monitors on Main Steam Line No. 1, on the steam dump line, and'on Main Steam Line No. 2. The monitors are'Sorrento Electric RD-8 ion chambers with a recorde The inspector reviewed PDCR's, observed readouts in the control room, l and obtained radiation surveys of the areas where the monitors are mounted to verify that the radiation field does not exceed 10 mr/hr as specified in the PDCR. (Readings were 0.~1 mr/hr.)

.: i L Procedure Changes were made to aid in steam generator leak detection and

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in associated Emergency Operating Procedure use. Surveillance procedures

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were modified to encompass the detectors. The inspector had no further

questions on this item.

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- :2 (Closed)' Unresolved Item (50-336/84-21-01) Procedural Controls over

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Frisking Prior to Leaving a Radiation Area iThel inspector observed numerous _ radiation controlled ar4as-during the 1986 Refueling Outage. Both licensee personnel and contractors were adhering to posted requirements 1to frisk prior to exiting a radiation

- are Thelarea of concern in the ~ Auxiliary Building was observed on several tours. .It was found that< personnel frisking was. acceptable on all occasions. In addition, new frisking stations were established and were monitored by HP personne Based on numerous _ observations without-identifying any deficiencies, this unresolved item is close .- Unit 2 Shutdown Background Unit 2 was returned to service'from the 1986 refueling outage on December 15, reaching 100%' power on December 21. On January 24 the chemistry program identified a primary to secondary leak of 0.10 gpm in No.1 Steae GeneratorL (SG-1). On January 29, based on the leakage detection in SG-1, a review of

. December 1986 Eddy Current Testing (ECT) data on SG tubes was performe A tube defect of more than 40% through-wall was identified, requiring unit shut-dow The unit' achieved cold shutdown on January 30, 198 Identified Tube Defects Re-analysis of ECT data for tubes adjacent to the tie rods identified 4 two tubes with pluggable indications. The two tubes were SG-1 Line 136, Row 4 and SG-2 Line 48, Row 9 l (1) SG-1 Line 136, Row 42 Evaluation The licensee found that, in SG-1, the Line-136,. Row 42 tube had been previously identified as degraded by both the primary and secondary

L analyst. The Level III reviewer overruled their calls based on the l assessment that a combined dent and defect signal caused by copper p interference had caused a false indication of a defect.

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.. Licensee review of similarly positioned tubes found no similar de-fects. Nonetheless, the' licensee plugged all remaining tubes ad-

, jacent to tin rods in both steam generators as a preventive' measur Based on the Level III analyst misinterpretation, the licensee has initiated further review of all ECT interpretations where defect identification was overruled by the analyst who provides final re-view. This will assure that acceptance of identified deficiencies gets multiple evaluatio pW .. -

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Licensee review also-found an1 additional 36 tubes with repairable'

. indications.. These had previously been miscalled by the~same Level

III1 analyst, whose work was reviewed-in entirety. (Sampling of the data reviewed by the.four other Level'III analysts identified no

. mistaken calls.) Of the'36' miscalls identified, about~80% were Lwithin the ECT acceptability criterion, though close to1the 40%

-limit. All 36 of these ' tubes were plugged'as an overall conserva-tive measur <

'(2) SG-2 Tube Line 48, Row 94 Evaluation

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. Licensee review ident, ted a'94% through-wall indication that was

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not identified during the 1986 outage because of a labeling erro ,

-Incorrect placement of reviewers data notations at the tubesheet-instead of at the 1st eggcrate resulted in the tube being unreviewed~

between the eggcrate and tubesheet. The licensee reviewed all other i e

data that could have been mislabeled (1800 items) and found no additional defect SG-1 Leaking Tube Line 25, Row 19

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l The SG-1 leak' rate at shutdown was 0.15 gpm, with a Technical Specifica--

c tion limit of 0.5 gpm per SG. Upon shutdown of the unit, hydrostatic ,

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test. of SG-1-identified a leaking tube at Line 25, Row 19. ECT inspec-tion found a large volume indication at the top of the tubesheet. A-rotating pancake coil (RPC) ECT revealed that the large volume indication was circumferential1y orientated and extended approximately 225' around

the tube. The through-wall opening was approximately 40* of this cir-

- cumference, with an estimated 0.052" opening.

[ Further licensee review found that the 1985 and 1986 outage ECT program

! identified 31% through wall degradation of this-tube. Stress corrosion has been identified as the most likely cause of this failure. Licensee .

i structural analysis identified that this tube is in a high stress' area, '

I and near a tie rod support. For a tube pulled during the 1983-84 outage, l stress corrosion was determined to be the cause of a similar leak.

[ The presently leaking tube was plugged, and the five adjacent tubes were

, staked and plugged to prevent multi-tube failure from fretting and wea The licensee safety evaluation for startup was reviewed and.found accept-

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:sce's Nuclear Review Board. Resident inspector and Region I specialist review found the licensee's actions acceptable.

' Licensee's Action Summary Licensee actions takgn in this case include the followin .

! A total of 61 tubes were plugged in SG-1; 20 tubes were plugged in

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SG-2.

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4 A licensee administrative limit of 0.15 gpm leakage for each steam generator has been established. The chemistry program is the only present means of identifying 0.15 gpm primary to secondary leakag Related Technical Specification changes are to be discussed with NR . A licensee review of the ECT program is presently being formulate ' NRC Inspection Summary The inspector observed daily meetings that addressed on going licensee findings on tube defects, including ECT analyst disagreements and repairs to steam generators. _ Tube plugging and stake installation were observed on a sampling basis. In' addition, observation of work areas noted proper posting and health physics coverage. Based on the need for manual eddy current examination and tube plugging, the licensee expended 60 man-rems-during the outage. At the conclusion of this report, the unit was in cold shutdown with an administrative hold on proceeding to mode 4 (heatup)

until startup was authorized by the licensee's Nuclear Review Boar The inspector noted that the outage was well coordinated by reactor engineering, with thorough planning. Licensee evaluation of this~ matter was thorough, and corrective actions were conservative. The inspector will review the effectiveness of the corrective actions during routine inspection . IE Information Notice No.86-104, Unqualified Butt Splice Connectors in Qualified Penetrations (Unit 1)

Information Notice No.86-104 was issued on December 16, 1986. The utility chose to perform a sampling inspection of penetration terminations on December 10, 1986, while the plant was shutdow The inspection was .to verify that butt splice connectors were installed pro-perly'during the GE penetration replacement in 1983. Members of the licen-see's engineering and EEQ engineering staff, accompanied by the resident in-spector, entered the drywell on December 10 and inspected twenty control and instrumentation splices and ten power cable splices. All splices met instal-lation (RayChem) criteri Upon conclusion of the drywell inspection, a review of four work packages performed on splices of penetration 100X was conducted. Verification of the installation per inspection plans included Material Certification, visual in-spection of the butt splice crimping, and examination of proper installation of the RayChem type N shrink sleeving. All of the above was witnessed by licensee QC inspectors and found satisfactor The inspector had no further questions on this ite ,

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-' IE Bulletin '83-03, Check Valves in Diesel = Service Water Systems (Unit 2) - I

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The licen.see's' response to Bulletin 83-03'(Counsil/Murley letter; May 31,-

1983) identified two check valves, 2-SW-13A and:2-SW-138, in the service water flowpath for the Millstone 2 diesel generators. The ISI Program was modified g .to include inspection of these valves. Both valves were disassembled during-P

.'an April 1983 outage, exhibited wear, and were rebuilt. . An inspection of the

. valves in 1985 confirmed that only normal wear was experienced during the operating cycle. The-licensee determined that a-40 month inspection interval in the ISI program was adequate for determining the condition of the check '

valve The. licensee ordered new valves to be installed during the 1986 outage. These valves were received but did not meet purchase specifications and were re-turned to the vendo The ISI program for the second ten year period, (December 26, 1986 to December-26,1996) lists -these valves for testing for-flow at quarterly interval No documentation as to the forty month inspection was found in the ISI program submittaltto NR Pending addition of the 40 month inspection of valves 2-SW-13A and 2-SW-138 to the ISI program, this bulletin will remain ope . Licensee Event Reports (LERs) (Unit 1)

LER's submitted from November 1986 through January 1987 were reviewe .

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inspector assessed LER accuracy, whether further information was required, generic implications, adequacy of corrective actions, and compliance with reporting requirements of 10 CFR 50.73 and Administrative ~ Control Procedure ACP-QA-10.0 Selective corrective actions were. verified for completeness and implementatio The LER's reviewed were:

86-25-00, Differential Current Relays Fail to Meet Seismic Criteria ';

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The licensee's engineering staff determined that the General Electric Model 12 CFD differential relays did 'not conform to the seismic qualifications if located at plant elevations above 14'6". Equipment effected included the

, protection for the Emergency Gas Turbine Generator (EGTG) cables and the A

. & B Feedwater Coolant Injection (FWCI) pump motors. The relays were removed.

r The licensee PORC review concluded that these protection circuits were an i economic rather than a regulatory requirement. The inspector verified that

the removal of the relays was completed, thus preventing activation of the relays and loss of FWCI and the EGTG. The inspector had no further question , Main Transformer Failura l The Main Transformer failed on Ncvember 30, 1986, resulting in a reactor scram.

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All safety equipment operated normally. The transformer was replaced with

an onsite spare. The faulty transformer was shipped to G.E. (Canada) for

, repair. This event was discussed in Inspection Report 50-245/86-22. The  !

j inspector had no further question !

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86-28-00, Steam Line Low Pressure-(SLLP) Setpoint Drift While shutdown for replacementLof the Main Transformer, routine surveillance of main steam line low pressure switches found three out of four pressure switches out of tolerance. A previous licensee review, Reactor Protection System Setpoint Drift (NE-83-R-424), addressed this concern and found no sig-nificant safety consequences (the minor level change, increased cooldown rate, and greater loss of inventory were evaluated as acceptable). On site follow-up found satisfactory recalibration and retest on December 19. The inspector had no further questions on this even , Actuation of Engineered Safety Feature - Standby Gas Treatment System This event is described in Inspection Report 50-245/86-22. Onsite followup on the sensor unit, which has an internal check source, found the problem to be due to low check source activity. The inspector had no further question , 86-30-00, 86-31-00, Security-Related Events These events were inspected by on-site inspectors to determine that the cor-rective actions were satisfactory. No unacceptable conditions were identifie Regional security specialists will review these events for final dispositio . Electrical Buswork Insulation Degradation - Unit 1 Based upon Unit 2 electrical buswork insulation degradation found on 6.9 Kv and 4160v switchgear, (see IR 50-336/86-21), licensee and General Electric technical representative personnel inspected some Unit 14160v buswork in mid-January. Insulation on Bus 14C and 140 bus bars exhibited similar but less pronounced cracking than was found on Unit 2 bus bars. The NORYL" in-sulating sleeves are a high temperature thermoplastic which provide electrical insulation protection against possible phase-to phase arcing between bus bar Although not an immediate problem, the cracking and splitting of the sleeves could eventually lead to a significant safety hazard. If degradation of the sleeving exposed sufficient bus bar area, flash-over arcing could occur. If the sleeving partially peeled off of the bus bar and contacted switchgear internals, damage to the bus bar or a fire could resul Ihis potential for material failures has been previously identified by the equipment vendor (General Electric) and disseminated to the industry via in-struction and service advice letters.' Vendor investigations have shown that the NORYL, while normally stable and suitable for this application, may undergo stress cracking if significant stresses and any of several petroleum based greases, plasticizers, paint thinners, industrial cleaning fluids, or chemical contaminants are present. The stresses may be heat, vibration, or fabrication induced. Chemical contamination may result from cleaning or maintenance involving buswork connection a

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The vendor currently recommends the use of only one type of joint compound, having found that other types are not compatible with the sleeving. Also, the use of cleaning agents other than denatured alcohol is not recommende The licensee currently intends to complete buswork inspections and conduct any required repairs of insulation on the safeguards buses (14E and 14F)

during the next refueling outage (June 1987).

The resident inspector will monitor the inspection and repair process during routine inspectio . Battery Maintenance Review and Observations (Units 1 & 2)

Low temperature in a battery room at a nuclear power plant recently raised concern about low temperature effects on the station battery capacitie At Millstone 1 and 2, the temperature limits on the battery rooms vary. Unit 1 has no limits. The Unit 2 FSAR notes a range of 70 Fahrenheit (winter)

to 104 Fahrenheit (summer). No documentation of actual room temperature exists. Inspection of both units found that the safety-related battery rooms were at 70 Fahrenheit to 77 Fahrenheit. Individual pilot cell electrolyte temperatures, which are recorded, show that the temperatures for both units range from 70 to 74 .

The licensee was knowledgeable of the reasons for maintaining battery room and battery electrolyte at or above 70 in order to prevent a reduction in battery capacity. In addition, the licensee reviewed battery data based on INP0's December Operations and Maintenance Reminder 0M305 which details sta-tion battery system problems. On-site NRC inspector review of Unit 2 proce-dure 2720F1 and Unit 1 MP 773.2, Station and Switchyard Battery Systems, identified no violations of NRC requirements. The licensee indicated that additional guidelines are to be included in procedures to incorporate INP0 guidelines. This item will be reviewed during a subsequent routine inspection.

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1 On-Site Safety Review Committee Unit 1 The resident inspector attenried the meeting of the Unit 1 Plant Operatio Review Committee (PORC) on February 4. Technical Specification G.5.1 re-quirements for committee composition were me The meeting agenda incluced reviews of the following:

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Final resolution and close-out of multiple mid-1985 Plant Incident Re-ports covering loose bolts and motor housings on valve operators for several valves in the Low Pressure Coolant Injection (LPCI) and Core Spray (CS) system _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ - - - __-__-__-___ - _ _ _ _ _ - _ .

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Close-out of the Plant Information Report (PIR) cover #ng the Reactor

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Water Cleanup (RWCU) System 1" pipe weld failure and subsequent leak on July 23, 198 Follow-up on Licensee Event Report (LER) 86-06 covering the failure of the 1-MS-10 (Main Steam Isolation Valve) limit switch on February 6, 198 The Plant Design Change Request (PDCR) for an upgrade of the Automatic Pressure Relief (APR) 120 second delay time circuits and alteration of the Low Pressure Coolant Injection (LPCI) system pump start permissive circui Review of Bypass / Jumper Log audit result Minor Operations and I & C procedural and form change The presentations elicited active questioning and discussions, and indicated that adequate review and analysis of the items were conducted prior to the meetin The PDCR discussion was a resubmittal that had been previously re-jected by PORC pending further engineering review. Items having unresolved questions were tabled pending further analysis. Committee members presented an informed and critical overview of plant design and operations. No defi-ciencies in PORC performance were observe . Operator Requalification Program The licensee's administration of the licensed operator requalification program was found adequate to meet regulatory requirement The purpose of this inspection was: (1) to determine if operator error during the recent event reported by the licensee's LER 86-07 could be traced to a weakness in the licensed operator requalification program, and (2) to provide information for evaluation of the requalification program in addition to that gained by audit of the licensee's 1986 requalification examination. In addi-tion, a review of the following documents was conducted:

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Requalification lecture / training schedules

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Lesson plans and simulator training scenarios

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Annual written examinations

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Progress written examinations

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Written examination grading and results evaluation

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Individual operator training records Lecture and simulator training attendance

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w 9 Performance reviews and remedial actions Proficiency evaluations

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Required reading

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Regular procedure review program Findings:

An event at Millstone Unit 2 was described by LER 86-07 as partly due to operator error. Operators did not recognize that a steam generator level instrument, which reads out in the main control room and which had been re-moved from service for two weeks, also provi:%s an input to the Remote Shut-down Panel (C-21). Thus', Technical Specification requirements for out of-service C-21 instrumentation were not met. Resident ilupector review of this item found that it was identified and acceptably corrected by the licensee, not of serious safety significance, and not due to licensee failure to imple-ment appropriate corrective actions on other violations. Therefore, no violation citation was issue The examiner found that the facility's 1985 annual written requalification exam, given in December 1985, had identified a general knowledge weakness related to the design and operation of C-21. The training staff then sched-uled and delivered a lecture on C-21 to all licensed operators between Febru-ary and March 1986, and held simulator training on C-21 operations. A written progress exam was administered in May-June 1986 and included at least two questions involving C-21 operations. The event involving operator error occurred in September 198 A review was conducted of the C-21 lesson plan presented during the 1986 re-qual cycle. The learning objectives were complete, well conceived and speci-fically included Technical Specification applicability to C-21 instrumentatio However, the lesson plan notes which were available for review had been hand-written and did not adequately cover all learning objectives regarding Tech-nical Specifications. Other lesson plans given during the 1986 requal cycle were typewritten and indicated that careful attention had been paid to ensure all learning objectives were fully covered in the tex Conclusion:

Overall, the Millstone Unit Two requalification program is well-organized, well-documented, and functions to identify individual, as well as generic, operator knowledge weaknesses. Additional training is conducted for identi-fied weaknesses. Lesson plans used for training lectures are generally com-plete and utilize a format which helps to prevent missing any of the stated learning objective _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

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The operational incident described by LER 86-07 should not have happene Weakness in the relevant knowledge area was identified by the licensee train-ing staff prior to the incident and factored into the 1986 requal trainin The training staff execution of this knowledge upgrading effort lacked suf-ficient emphasis in Technical Specification and C-21 instrumentation input This appears _to be an isolated case and not representative of the licensee's general requalification program. However, it points to a continuing need for the licensee to be as aggressive at upgrading training deficiencies as it is in finding them. This inspection of requalification found no regulatory non-complianc . IE Notice 86-106, Feedwater Line Break Wall Thinning Inspection In response to IE Notice 86-106, the pipe thinning that ultimately resulted in a complete fracture of a pressurized feedwater line at another facility has been reviewed by the licensee. Programs for monitoring thickness meas-urements were previously established in 1980 for Unit 1 and 1982 for Unit Unit 1 (BWR)

Unit 1 engineering has had a program of identification of pipe thinning in use for carbon steel piping since 1980. Heater drains, extraction steam piping, and moisture separator piping have been tested. Extraction steam lines have been inspected and approximately 200 feet of extraction steam piping has been replaced. All extraction steam piping is scheduled for re-placement during the June 1987 refueling outage. IEN 86-06 resulted in selected areas on feedwater suction piping being examined and found acceptabl The licensee plans to have a full program established to identify pipe thin-ning that addresses all concerns of IEN 86-106 prior to the refueling outage (June 1987). The inspector plans to review this program prior to the refuel-ing outag Unit 2 (PWR)

Unit 2 has a formal wall-thickness evaluation program that was established in 198 Procedure EN 21153, " Thickness Testing of Secondary Piping," iden-tifies and monitors locations of thin wall piping in the secondary syste Replacements of eroded / corroded sections of piping are scheduled for refueling outage Although the condensate and feed lines are not presently addressed in this procedure, the following areas are routinely examined during perform-ance of Procedure EN 21153:

Continuous Vents for heater 1A,1B, 2A, 2B, 3A, 3B, 4A, 4B, 5A, 5B, 6A, and 6B valves on Main Steam Reheaters (MSR) 1A and 1B high pressure drains, M. lA and 1B second stage steam supply high pressure drains, Main Steam high pressure drains, extraction steam to feedwater heaters 1A, 18, 2A, 28, 3A, 3B, 4A, 4B, including ist stage reheat to the M.S.R.'s, and the Steam Genera-tor blowdown pipin ,- .

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Iniaddition,Elicensee actions ~in response to IEN 86-106 included the examina-- .

tion of; portions of the feedwater piping. The results of this. inspection were

-Section~of Piping Nominal Wall ' Data % Loss-24" X 24' TEE 1.218" 1.26" None w. , ' Pipe "A" 1.218". 1.31" None-Pipe "G" 1.218". '1.16"

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24" X I18" Reducer .b Reducer "A" 1.218" 1.22" None .4

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18" Pipe "E"~ 0.938"- 0.99" None-The: inspector observed preparations for piping. examinations of the 24" X 24'!

Tee and a pipe reducer for surface preparation ~and use.of high temperature coupling material prior to nondestructive examination (NDE).' -NDE calibration test' samples were found acceptable. The licensee has committed.to document-pipe thinning and to replace piping that reaches established minimum limit This program will be routinely reinspected during licensee refueling outages'.

The inspector had no further. questions at this tim . Management Meetings s

LAt periodic intervals during this inspection, meetings were held with senior plant management to. discuss the findings. No proprietary information was

identified as being in the inspection coverage. No written material-was "

provided to the licensee by the inspecto I