IR 05000322/1985043

Insp Rept 50-322/85-43 on 851201-31.No Violations or Deviations Noted.Major Areas Inspected:Completion of Neutron Source Outage & Transition Prior to Reactor Water Level Ref Leg Replacement Outage

ML20151T946
Person / Time
Site:	Shoreham File:Long Island Lighting Company icon.png
Issue date:	01/31/1986
From:	Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20151T917	List: IR 05000322/1985043 ML20151T912
References
50-322-85-43, NUDOCS 8602100394
Download: ML20151T946 (23)

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U.S. Nuclear Regulatory Commission Region I REPORT N /85-43 DOCKET N LICENSE N NPF-36

- LICENSEE: Long Island Lighting Company P. O. Box 618 Shoreham Nuclear Power Station Wading River, New York 11792 INSPECTION AT: Wading River, New York INSPECTION CONDUCTED: December-1 - 31, 1985 INSPECTORS: John A. Berry, Senior Resident Inspector APPROVED: .

Agaan'b /!8/ IS JV R. Strosnider, Chief, Reactors Projects Date signed Section 18, Division of Reactor Projects

- SUMMARY: During the inspection period, December 1 - December 31, 1985 the licensee completed the Neutron Source Outage, and entered a transition period prior to the Reactor Water Level Reference Leg replacement outage scheduled to begin January 8, 1986. The licensee completed Environmental Qualification of Electrical Equipment and Fire Detection Instrumentation installation during this perio Several incidents of personnel error causing Engineered Safeguard Feature actua-

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tions also occurred during this perio Completion 'of the Transamerica Delaval Diesel Generator inspections required by an American Air Filter Part 21 report was accomplished, and repair and inspec-tion of Anchor Darling Swing Check Valves continue This inspection involved 106 hours0.00123 days <br />0.0294 hours <br />1.752645e-4 weeks <br />4.0333e-5 months <br /> of inspection by the Senior Resident Inspector, and 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of inspection by Region-based inspectors. Thirteen items were closed as a result of this inspection and 1 item was opened. No deviations or violations were note ~

8602100394 060204 PDR ADOCK 05000322 G PDR

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DETAILS 1. Status of Previous Inspection Items 1.1' (closed) 50-322/85-39-03, Part 21 Notification - American Air Filter NRC Inspection Report 50-322/85-39 detailed a potential deficiency with Intake Silencers supplied to Transamerica Delaval (TDI) for use on Emergency Diesel Generator The deficiency involved the absence of required welds on an internal part of the silence NRC Inspection Report 50-322/85-42 updated this open item to detail the licensee's inspection of two of the three TDI Diesel Generator Intake Silencers (EDGs 101 and 102).

The licensee completed inspection of the third and final TDI Diesel Generator (EDG-103) on December 28, 1985. The presence of the re-quired welds was verified by Quality Controls Division inspector ~

Upon completion of this inspection, the licensee closed LILC0 Defi-ciency Report No.85-167 on December 30, 198 This item is close .2 (Update) 85-36-02, RHR Bolt Failure NRC Inspection Report 50-322/85-36 opened unresolved item 85-36-02 regarding the failure of bolts on the minimum flow bypass valve for RHR Loop The bolts which held the valve operatcr to the yoke had failed, disconnecting the operator from the valv Subsequent inves-tigation by the licensee of bolts in the RHR, HPCI, and Core Spray systems discovered other bolt ~ problems. The licensee initiated a program to inspect the bolting material used on. safety related motor operated valves to provide assurance that it is as specifie By memorandum from the Nuclear Engineering Department to the Mainte- "

nance Division Manager the licensee establishei guidance regarding the method and schedule of inspections. The licensee began inspec-tion of 278 safety-related valves on Tuesday, December 10, 198 Inspection was completed on December ~16, 1985. The results of the inspections are as'follo,<s:

. One hundred eighty-eight (188) passed the inspectio . Fifteen (15) valves were found to contain one stud that was ap-propriately marked with the material grade. The licensee con-siders there valves acceptable at this tim Fifty-one (51) valves contained studs that were 5/16 inch diame-ter with no markings. These valves will be subject to a 10%

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. Two (2) valves with studs larger than 5/16" diameter were found to have no readable stud markings. One of these, IE11*MOV055A, was marked, but the grade marking could not be determined. The other valve, IN23*MOV-026, is in the steam tunnel near the tur-bine building. This valve is accessible from the platform at the main steam bypass valve . Ten (10) valves had their operators restrained with material that was considered either inappropriate or suspec . Twelve (12) valves with mounting bolts larger than 5/16" diame-ter were inaccessible for examinatio The lic~ensee's evaluation of these results, as well as the results of the 10*.' sampling inspection will be detailed in a future NRC Inspec-tion Repor .3 (Update) 50-322/85-39-01, RWCU Inboard Isolations While Adjusting Blowdown Flow NRC Inspection Report 50-322/85-39 detailed problems that the licensee had experienced with spurious isolations of the Reactor Wa-ter Cleanup System (RWCU) during adjustment of blowdown flow to the Main ondensor. The licensee had attributed the cause of the problem to the flow sensing circuitry of the RWCU system. Action was taken to calibrate all of the components of the flow sensing circuitry to determine the cause of the proble The licensee submitted an update to Licensee Event Report 85-036 to the NRC on November 6,.1985 to provide revised information as to the cause of the isolation problem. The licensee had completed recalibration of the flow sensing circuitry in the system, after which, another system isolation occurre Subsequent investigation and additional troubleshooting discovered a loose ground connection on the Square Root Extractor portion of the circuitry. This loose connection was retightened. The licensee feels that this will cor-rect the problem of isolation of the inboard and outboard isolation valves. This will be verified upon return to rated condition Additionally, the licensee has experienced spurious trips of the sys-

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tem inboard isolation valve only. The individual components of the RWCU inboard isolation circuitry are being examined to determine the cause of the isolations. The licensee will issue a supplemental re- I port once the cause of these isolations has been determined and l correcte .4 (closed) 50-322/85-36-03, Reactor Water Level deviation

'NRC Inspection Reports 50-322/85-35 and 85-36 detailed deviations which occurred with the Reactor Vessel Narrow Range Level Syste The licensee implemented corrective action to correct the deviation

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6-problem, and the Nuclear Engineering Department and Plant Staff began an evaluation of the need for additional corrective actio The evaluation has been completed by the licensee. The licensee has decided to perform modifications to the 'A' and 'B' Reactor Pressure Vessel Reference legs as a permanent solution to the level deviation problem. This modification will involve the shortening of the steam piping from the Reactor Pressure Vessel to the reference leg condens-ing chamber. Additionally, more insulation will be added to the pip-ing to prevent condensation from forming in the pipin This modification work is scheduled to begin on or about January 8, 1986, and will continue for approximately two months. Activities related to this modification will be tracked as part of the routine monthly resident inspection repor ~

This item is close .5 (Update) 50-322, 85-20-01, Review of Licensee Response to GE SIL

1. 402, Nitrogen Inerting of Containment

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A region-based inspector conducted an in-office review of the licensee's response to SIL 402 recommendations 1 and 2 indicated in letters dated September. 18, 1984 and November 8, 1984. As a result of the licensee's system design evaluation, the licensee has commit-ted to a_ plant modification in Station Procedure Change Notice (SPCN)

85-1037 and Design Output Package (D0P)84-275. This notification will tccomplish the following: A temperature-controlled valve will be added upstream of the nitrogen vaporize A control panel local to the vaporizer (in the yard) will be installed. This will signal the temperature-controlled valve to close when the nitrogen temperature downstream of the vaporizer is below 40 degrees ,

l A thermocouple will be locat i on the nitrogen piping inside secondary containment, and will provide the signal to the con-

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trol panel in the yar , A pressure relief valve (setpoint of 350 psig) will be installed upstream of the temperature-controlled valv These changes will be implemented prior to initial inerting of the containment. An additional requirement for licensee close out of

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work associated with SPCN 85-1037 is a revision to Station (Operat-ing) Procedure (SP) 2.3.425.01 Rev. 8 which will then procedurally prevent cold nitrogen injection.

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-The licensee is not able to evaluate the operating experience of the inerting system (SIL 402 Recommendation 2) as Shoreham is not yet operational and the primary containment has not been interte An NRC re-review of the nitrogen. injection system procedures will be made following completion of licensee activities associated with SPCN 85-103 .6 .(Update) 85-08-01, Leakage Reduction Program NRC Inspection Report 50-322/85-08 cited the licensee for one viola-tion involving the failure to establish and fully implement the Leak-age Reduction Program from Primary Coolant Sources Outside Containmen The inspector reviewed the licensee actions in response to the Notice of Violation and subject report. The licensee had been cited for: Failure to establish a program to reduce leakage from those por-tions of the Reactor Building Floor Drains, Reactor Building Equipment Drains, and Reactor Building Standby Ventilation Sys-tem outside containmen The following items being absent from established program for

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the nine remaining systems:

(1) Procedure steps for Technical Specification required visual inspections and for NDE surface emission bubble testing per SP No. 84-002-01, Rev. 1 (2) Definition of parameters such as Test Pressur (3) Acceptance criteria for leakage rata (4) Requirements for retest after repai '

The licensee responded to the Notice of Violation and Inspection Report by letter dated May 14, 198 (Ref: SNRC-1174, J. Leonard, LILCO to T. E. Murley, NRC, " Leakage Reduction Program, Personnel Qualifications and Training, Shoreham Nuclear Power Station,. Docket No. 50-322, May 14, 1985). In that response, the licensee detailed the corrective actions to be taken to achieve complianc The inspector reviewed the licensee's corrective actions in.this matter. The results of that review follo . NRC Inspection Report 50-322/85-08 noted that SP N .080.01, Rev. 3, Leakage Reduction and Control Prograni,.

did not address or reference the subject of the qualifica-tion of personnel to~be used in the progra . __- . - -

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The inspector verified that SP 12.80.01 was replaced by SP 14.404.01, Leakage Reduction and Control Program Implemen-tation, on July 2, 1985, and that Step 6.4 of the new pro-cedure addresses these qualification . The inspection report noted that SP 12.080.01 did not con-tain appropriate or approved data sheets for visual inspection The inspector verified that these data sheets were incorpo-rated in the new SP 14.404.0 . The inspection report noted that SP 84.002.01, Leakage Re-duction and Control Program Implementation, did not include three systems required by the Technical Specification 'The inspector verified that SP 84-002.01 was replaced by SP 14.404.01, and that the three systems were included in SP 14.404.0 . The. inspection report noted that SP 84.002.01 did not. con-tain provisions for scheduling the Technical Specification required " periodic visual inspections", and that the proce-dure provided no detailed implementation steps for the Technical Specification required periodic visual inspec-tions nor for maintaining the status of the visual inspec-tions. The procedure also lacked data sheets addressing visual inspection The inspector verified that the new procedure SP 14.404.01 incorporated scheduling and implementation of the TS re-quired visual inspections in Sections 8.1 and 3.3.1, and that data sheets for these inspections were provided as Appendixes 12.2.A through 1 . The inspection report noted that the SP 84.002.01 data '

sheets lacked sufficient detail for maintaining test status for leak test The inspector verified that SP 14.401.01 corrected this deficienc . The inspector report noted that SP 84.002.01 was deficient in its definition of the system boundary to be tested and the interfaces with other system boundarie The inspector verified that SP 14.401.01 corrected this deficienc . The inspection report noted that SP 80.002.01 did not pro-vide detailed steps covering liquid bubble testing, nor did

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it provide a reference to another NDE procedure covering this testin The inspector noted that the licensee, in their response to the Notice of Violation (SNRC-1174), stated that " Emission

- Bubble Testing is not used to quantify leak rates on sys-tems. Make-up flow rate measurements are used to quantif system leakage. Bubble checks are only used to locate the source of leakage. As such, no procedure for NDE surface emission bubble testing is required". The inspector veri-fled that SP 14.404.01 contains instructions on use of

" Leak Tec (TM)" for bubble emission testing. The inspector finds this satisfactor . The inspection report noted that SP 80.002.01 did not stip-ulate test pressures for conducting various system test The inspector verified that these pressures are incorporat-ed in SP 14.401.0 . The inspection report noted that SP 80.002.01 contained no initially developed acceptance criteria for leakage rates from systems in the Leakage Reduction Progra The' inspector verified that FSAR Section 11I.D.1.1 and Step 3.3.1 of the new procedure satisfied this requiremen . The inspection report noted that the procedure contained no requirement in the Leakage Reduction Program or Procedures that specified retest after repair to ascertain whether or not the repair was effectiv The inspector verified that SP 14.404.01, Step 6.3 now con-tains retest requirement . The inspection report noted that SP 80.002.01 did not ad-dress or reference qualifications of personnel to perform test in accordance with the procedur As previously noted, the inspector verified that' Step of SP 14.404.01 now addresses such qualification . The inspection report noted, during Field Inspections, that the Core Spray and RHR system data sheets were minimally adequate (Core Spray) or inadequately (RHR) detailed for maintaining test status. The report further noted that the RHR test boundary interfaces were not defined nor were steps provided for inspecting insulated pipin The inspector verified that the data sheets in SP 14.404.01 and steps 8.1.4, 8.1.5, 8.1 and 8.2.d adequately address these concern .

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. The inspection report noted that many of the piping areas inspected would require additional lighting, or would re-quire the use of mirrors for adequate inspectio The inspector verified that flashlights and mirrors are listed as Materials and Test Equipment in SP 14.401.0 Two portions of NRC Inspection Item 85-08-01 remain open, the revi-sion of procedures SP 74.030.02, "RBSVS in Place filter Testing", and SP 84.402.01, " Hydrogen Recombiner System Leak Rate Test", to include reference to the qualifications of personnel used to conduct the tests. The licensee has committed to completing these procedure re-visions by January 31, 1986. Upon verification by the inspector that these procedural revisions are complete and approved by the Review of Operations Committee, NRC Inspection Item 85-08-01 will be close .7 (closed) Various NRC Inspection Report 50-322/84-46 Fire Protection System Open Items Between December 3 and 7, 1985, members of the NRC staff from the Office of Nuclear Reactor Regulation and from NRC Region I inspected the licensee's activities in relation to Appendix R of 10CFR50. On December 21, 1984, NRC Inspection Report 50-322/84-46 was issued sum-marizing the results of that inspection. Twelve (12) items were des-ignated as unresolved pending evaluation by NR By letters dated January 29, April 5, and June 3, 1985, the licensee provided additional information on these items, including commitments to implement fire protection modifications in certain area The NRC staff's evaluation of that information was formalized in Sup-plement No. 9 ~to the Safety Evluation Report related to the operation of Shoreham Nuclear Power Station, Unit No.1, NUREG-042 This SSER was issued in December 198 Based on this SSER, the following items are closed. Details on these items, and their closure may be found in NRC Inspection Report '

50-322/84-46 and NUREG-0420, Supplement No. . (closed) 50-322/84-46-05, Spacing of Fire Detectors 1. (closed) 50-322/84-46-07, Fire Door Degredations 1. (closed) 50-322/84-46-08, Diesel Fire Pump Cables 1. (closed) 50-322/84-46-09, Fire Damper in Heating, Ventilation, and Air Conditioning Chiller Rooms-1.7.5 (closed) 50-322/84-46-10, Design Concentration of Carbon Dioxide in Battery Rooms and Cable Tunnel 1.7.6 (closed) 50-322/84-46-11, Fire Detectors in Computer Room 1.7.7 (closed) 50-322/84-46-12, Damaged Fire Proofing 1.7.8 (closed) 50-322/84-46-13, Fire Hazards Analysis for Control Building Corridors and Manhole #1

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1.7.9 (closed) 50-322/84-46-14, Single Water Supply Header in the Reactor Building 1.7.10 (closed) 50-322/84-46-15, Structural Integrity of Penetration Seals 1.7.11(closed) 50-322/84-46-16, Sizing of Water Storage Capacity 1.8 (Update) 50-322/85-42-01. Check Valve Failures NRC Inspection Report 50-322/85-42 detailed failures on High Pressure Coolant Injection System Swing check valves manufactured by the Anchor / Darling Valve Co. The report stated that the licensee would be conducting an inspection of all Anchor / Darling swing check valves, and determining a course of corrective action. This update details the results to date of this licensee's action As discussed in Inspection Report 50-322/85-42, the licensee discov-ered, on November 4, 1985, that the swing check valves located in the-steam discharge line of the High Pressure Coolant Injection System (HPCI) Turbine had come apart. The cause of the valve failures was determined to be the separation of the hinge support assembly from the valve bonnet due to the disengagement of the two capscrews hold-ing the pieces togethe The licensee initiated an investigation into the cause 'of the valve failure. As part of this investigation, all other Anchor / Darling-swing check valves were to be inspected, the failure mechanism of the HPCI valves was to be analysed, and determination of whether there was a valve assembly deficiency was to be mad On December 20, 1985, the licensee issued Interim Report N , "An Investigation Into Failure of the HPCI Turbine Exhaust

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Check Valves manufactured by Anchor / Darling for the Shoreham Nuclear Power Station". The report presented the licensee's findings to that date resulting.from their investigatio There are a total of 12 Anchor /3arling swing check valves installed in the Shoreham plant. They are:

2 HPCI Steam Discharge 18 inch valves

., 2-HPCI Pump Suction 16-inch valves 4 Residual-Heat Removal System Pump Suction 16 inch valves (one for each of the four RHR Pumps A - 0)

2 Feedwater Discharge 18 inch valves 2 Fuel Pool Cooling System 6 inch valves Of these 12 valves, 9 are of the design where the hinge support piece bolts to the bonnet (including the two failed HPCI Steam Exhaust valves). Three valves, (the two Feedwater, and one of the two Fuel Pool Cooling), are of the hinge support to body type. Ten of the twelve valves are carbon steel, while the two Fuel Pool Cooling Valves are stainless stee .

During the licensee's inspection of these valves, they discovered, on

~ December 3, 1985, that valve 1E11*16V0020B, (RHR Pump 'B' Discharge Check Valve) was missing one of the two capscrews. The hinge support piece was still intact, held firmly by the remaining capscrew. The capscrews, as in the case of the HPCI turbine exhaust valves, were neither tack welded nor lock-wire As of the end of the inspection period, December 31, 1985, the licensee had completed inspection of 8 of the 12 Anchor / Darling check valves. With the exception of the two HPCI steam valves, and the RHR Pump 'B' discharge check valve,.all valves had capscrews intact with no signs of loosening. None of the valves inspected had their capscrews tack-welded or lock wire The licensee has concluded that the failure of the valves is the re-sult of the lack of a suitable locking mechanism on the capscrew Licensee review of the Anchor / Darling vendor generic documentation for swing check valves of this design indicates that the hinge sup-port piece capscrews should be tack-welded. Review of Shoreham spe-cific valve drawings indicates no such weld for any of the valves except the.6" stainless steel Fuel Pool Cooling System valves. The licensee, Stone & Webster, and Anchor / Darling are investigating the-discrepancy between the vendor drawings and Shoreham specific drawing As detailed in Inspection Report. 50-322/85-42, there were three capscrews and two spring pins missing from the HPCI check valves.when they were disassembled following discovery of their failure. An in-spection of the sparger in the steam line failed to discover the missing parts. There was also a missing nut and washer from the RCIC check valves which had failed. The nut and washer were discovered in the RCIC steam exhaust sparger in the Suppression Poo When the licensee inspected the RHR pump 'B' discharge check valve they determined that the capscrew which had come out was also missin This capscrew is approximately 5/8" in diameter and 21/2 inches lon On December 16, 1985, a diver was sent into the Suppression Pool to attempt to locate the missing valve pieces. The diver recovered one missing spring pin and one capscrew from the HPCI check valve Still missing are two 5/8" diameter by 2 1/2" long capscrews from HPCI and one 3/16" diameter by 2 inch long spring pin. These pieces are still assumed to be in the Suppression Pool. Further diver in-

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spections will be performed to attempt to locate there parts. Addi-tionally, the' licensee is performing an engineering analysis to document the effect of any'unrecovered parts on system operabilit The missing capscrew from the RHR system is assumed to be in the RHR piping. The licensee is presently analysing the effect this capscrew could have on RHR system operation, as well as the potential for its migration throughout the system and to the reactor vessel due to

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system flow. The results of-these analyses will be the subject of future NRC inspection reort The licensee has decided upon a course of corrective action for bo.th the HPCI check valves, as well as for all other Anchor / Darling swing

. check valves. These actions are as follows:

HPCI Turbine Steam Exhaust Check Valves - The licensee has concluded that the HPCI steam valves will be reassembled with the capscrews lock-wired. By letter from M. D. Cowell, Project Engineer for Archor/ Darling to Tom Bennet, LILCO, the valve manufacturer has in-formed the licensee that lock-wiring the capscrews is a satisfactory mechanism to prevent loosening. The licensee determined that the valves could be returned to service with lock-wiring based upon:

. The fact that examination of the recovered capscrews found them to be intact with no signs of distres . The fact that other nuclear power plants with Anchor / Darling swing check valves which are properly lock-wired or tack-welded have not experienced the type of failures seen at Shoreha . The licensee's implementation of an augmented inspection of the HPCI valves, and other Anchor / Darling valves in the plan The licensee has also committed to replacement of the HPCI Turbine exhaust valves at the first plant refueling outage. These valves will be replaced with lift-check valves which have been shown to per-form better in this type of servic Other Anchor / Darling Check Valves - The licensee will lock-wire all other Anchor / Darling swing check valves that lack the required tack wel The justification for lock-wiring comes' from the Anchor / Darling memo discussed above. The licensee will then imple-ment an augmented inspection schedule for these valves to ensure that this corrective action is effectiv '

The licensee's continued action in this matter, as well as the re-sults of their further inspections will be the subject of future in-spection reports. Pending completion of the licensee's actions, and review by the NRC, this matter will remain ope . Review of Facility Operations

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2.1- Operational Safety Verification The inspector toured the control room daily to verify proper shift manning, use of and adherence to approved procedures, and compliance with Technical Specification Limiting Conditions for Operation. Con-trol Panel instrumentation and recorder traces were observed and the status of annunciators was reviewed. Nuclear instrumentation and reactor protection system status were examined. Radiation monitoring

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instrumentation, including in plant Area Radiation monitors and ef-

. fluent monitors were verified to be within allowable limits, and ob-served for indications of trends. Electrical distribution panels were examined for verification of proper lineups of backup and emer-gency. electrical power sources as required by the Technical Specification The inspector reviewed Watch Engineer and Nuclear Station Operator logs for adequacy of review by oncoming watchstanders, and for proper entries. A periodic review of Night Orders, Maintenance Work Re-quests, Technical Specification LC0 Log, and other control room logs and records was made. Shift turnovers were observed on a periodic basi The inpsector also observed and reviewed the adequacy of access con-trol; to the Main Control Room, and verified that no loitering by unauthroized personnel in the Control Room Area was permitted. The-inspector observed the conduct of Shift personnel to ensure adherence to Shoreham Procedures 21'.001.01, " Shift Operations" and 21.004.01,

" Main Control Room - Conduct for Personnel".

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Due to the activities related to the maintenance and modification work during the neutron source outage, the inspector conducted peri-odic detailed reviews of Station Equipment Clearance permits and Tag-ging Orders. The inspector also verified proper tagging in the control room and in the plant. Tags were verified to be hung proper-ly, with valves, breakers-and components in their proper positio The inspector verified proper completion of SECP forms, and double verification of tags hun No unacceptable conditions were identifie .2 Plant and Site Tours The inspector conducted periodic tours of accessible areas of plant and site throughout the inspection period. These included: the Tur- .

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bine and Reactor Buildings, the Rad Waste Building, the Control Building, the Screenwell Structure, the Fire Pump House, the Security Building, and the Colt Diesel Generator Buildin During these tours, the following specific items were evaluated:

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Fire Equipment - Operability and evidence of periodic inspection of fire suppression equipment;

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housekeeping - Maintenance of required cleanliness levels;

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Equipment Preservation - Maintenance of special precautionary measures for installed equipment, as applicable;

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QA/QC Surveillance - Pertinent activities were being surveilled on a sampling basis by qualified QA/QC personnel;

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Component Tagging - Implementation of appropriate equipment tag-

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ging.for safety, equipment protection, and jurisdiction;

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Personnel adherence to Radiological Controlled Area rules, in-cluding proper Personnel frisking upon RCA exit;

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Access control to the Protected Area, including search activi-ties, escorting and badging, and vehicle access control;

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Integrity of the Protected Are'a boundar No unacceptable conditions were identifie . Licensee Reports 3.1 In Office Review of Licensee Event Reports The inspector reviewed Licensee Event Reports (LERs) submitted to the NRC to verify that details were clearly reported, including accuracy of the cause description and adequacy of corrective action. The in-spector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite follow-up. The following LERs were reviewe LER Number Title 85-52 RPS Actuation when switching from RPS ALT to RPS "A" Bus 85-53 Temporary Procedure Change Notice not approved in time limit specified in Tec Spe Loss of RPS 'A' due to operator error

• • 85-49, Rev. 1 Update on LLRTs which exceeded the Allowable Tech. Spec. limits

• 85-55 Environmental Qualification of Electrical Equipment

• Discussed in NRC Inspection Report 50-322/85-42

• • This revision concerns the failure of the RCIC Turbine exhaust check valves. Details may be found in NRC Inspection Report 50-322/85-4 .2 Onsite Followup of Licensee Event Reports For those LERs selected for onsite follow-up, the inspector verified; the reporting requirements of 10 CFR 50.73 and Technical Specifica-tions had been met, that prompt and effective corrective action had

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been taken, that the licensee had reviewed the event to determine ways to prevent future occurrence, and determined whether follow-up action is require The inspector conducted on site follow-up on LER 85-54, ' Loss of RPS

"A" due to Operator Error', as well as two LERs from NRC Inspection Report 50-322/85-42, (85-48, "B" RBSVS Initiation due to Technician

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Error", and 85-50, "RBSVS/CRAC 'B' side initiation due to Technician error").

These LERs were chosen for review due to their relation to the sub-ject of ' personnel' error'. Details on this subject may be found in Section 7. of this report, entitled " Personnel Errors".

3.3 _ Review of Periodic and Special Reports During the inspection period, the inspector reviewed the Shoreham Startup Test Report submitted to the NRC by letter dated November 22, 1985. (Ref: SNRC-1216, J. D. Leuard, Jr. , Vice-President, Nuclear 0perations to Harold R. Denton, Dire.-tor, Office of Nuclear Reactor Regulation, "Startup Test Report-Shoreham Nuclear Power Station, Docket No. 50-322). This report is required by the Shoreham Techni-cal Specifications, Section 6.9.1.1 through 6.9. The report ad-dresses the startup tests identified in Chapter 14 of the Shoreham Final Safety Analysis Report (FSAR) which were performed in the test conditions "Open Vessel and Heatup." In the report, the licensee de-scribes the measured values of the operating conditions or charac-teristics obtained during the startup test program to dat The values are compared to the pre-determined acceptance criteria, and where necessary, corrective actions and/or test exceptions are de-scribed. The report also includes a discussion of license conditions which affect plant startup and power escalation testin The report coted that, as Shoreham has not completed its startup. test orogram, the tests identified in the FSAR to be performed in test conditions 1 through 6, and during the warranty demonstrations are '

outside the scope of the report. The report also noted that modifi-cation activities on the reactor vesse. level instrumentation system and the High Pressure Coolant Injection System will require startup retesting. These modification activities involve the replacement of the condensing chambers and piping for the reference legs of the water level system, and modification to the HPCI Woodward Governor Control system. These modifications will invalidate the results of the' portions of STP-9 and STP-15 which were completed in the startup test progra The inspector noted that the report indicated, with exception of the following items, that all test results met acceptance criteria or approved test exception The items which did not meet acceptance criteria, or which will require further corrective action are:

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. ~ Control Rod Drive 22-35 was inoperable at the time rods were scrammed at rated pressure. Rod 22-35 was replaced during the source outage, and will be retested prior to entering Test Con-dition . The control rod drive flow controller's decay ratio has not yet been analysed. This will be completed upon retesting after the outag . Pro'olems with the A and B reference legs were discovered during the testing program (see NRC Inspection Reports 50-322/85-35, and 85-36). The. licensee is replacing the piping from the ves-sel to the reference leg condensing chambers, anc' complete in-strument loop calibration will be performed when retesting begin . -LPRM Calibration testing identified 10 LPRMs which must.be retested at higher power levels, and one (LPRM-20-37-C) will be repaired prior to retesting at higher power level . The RCIC system exhibited flow oscillations during Reactor vessel

' injection system testing on September 26, 1985 and October 4, 1985. The RCIC speed and control. systems will be recalibrated to stabilize the circuitr Retest of the system will be com-pleted upon return to powe . HPCI Woodward governor modifications, mentioned earlier, will require HPCI retes . Safety Relief Valve ' A' failed to meet the acceptance criteria which requires that steam flow through each relief valve, as measured by the initial and final bypass valve position, shall not be less than 10% of valve position under the average of all valve responses. This SRV will be retested at rated pressure during Test Condition 2. The decision to delay-retest to test condition 2 was made to limit the amount of cycling of the SRVs at low pressur '

. The Recirculation Flow Control System for the 'B' Recirculation MG-Set test indicated violations of the acceptance criteria regarding limit cycles. This is believed to be caused by non-linearities which exist in the scoop tube position vs. speed characteristics in the 20% to 30% range. Corrective action to prevent MG-Set operation below 24% will be taken prior to entering Test Condition 1. After completion of TC 1-3 testing, an evaluation will be made as to the need for reshaping of th scoop tube cam to eliminate the non-linearitie . Reactor Water Cleanup system testing determined the need for replacement of a Flow Transmitter in the bottom head

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18-drain line. This transmitter was replaced during the source outage _and new data will be obtained upon retesting.

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No unacceptable conditions were identifie ~4. Monthly and Maintenance Observation

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4.1 Maintenance Activities The inspector observed the conduct of various maintenance activities throughout the inspection period. During this observation, the in-spector verified that; maintenance activities were conducted within the requirements of the plant's administrative procedures and techni-cal specifications, proper radiological controls were implemented and observed, proper safety precautions were observed, and that activi-ties which have the potential to impact. plant operations are properly coordinated with the control roo Activities related to the neutron source outage maintenance and modi-fication work were observed by the inspecto See Section 8.0 for details of these activitie No unacceptable conditions were identifie . Review and Followup of IE Notices, Bulletins and Generic Letters 5.1 IE Notices The inspector reviewed notices issued by the Office of Inspection and Enforcement during the inspection period. Review was to determine; if the subject of the no' ice was applicable to the Shoreham Nuclear Power Station, and if followup of the licensee's action was required by the inspecto . Licensee Response to NRC Inspection Report No. 50-322/85-22 Allegations involving the calibration of certain instrumentation and con-trols, as well as training and qualification of instrument technicians and supervisors, were made to the New York State Consumer Protection Borad by a private citize These allegations were the subject of a special NRC inspection conducted during the period April 10 - May 10, 1985 by an inspector from the NRC Region I Offic The results of that special inspection were documented in NRC Inspectio Report 50-322/85-22. The transmittal letter for that report required the licensee to respond to those allegations that were substantiated as a re-sult of that inspection, and to also provide additional information on

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calibration procedures. (Ref: R. W. Starostecki, NRC, to J. D. Leonard, Jr., LILCO, " Subject - Inspection 50-322/85-22", dated September 10,1985)

The licensee responded to NRC Inspection Report 50-322/85-22 on November 1,1985 by letter, (Ref: SNRC-1212, J. D. Leonard, Jr. , LILC0 to T. Murley, NRC Region I, Inspection Report No. 50-322/85-22 Shoreham Nuclear Power Station - Unit 1, Docket No. 50-322"). The following provides de-tails of NRC Region I's review of that respons .1 Response to Detail 4.2: Tapping of Instrumentation During Calibration It was alleged that during calibration of instrumentation, tapping was done to defeat the hysteresis effect, which thereby invali-dates the calibration. It was alleged the Weston indicators located throughout the plant would fail the calibration if not tappe It was stated that QC personnel witness the tapping and then " sign-off on this fudged data".

Licensee response has indicated that both procedures for panel-mounted meters (SP 46.030.01 and SP 46.030.02) will be revised to require upscale, downscale and downscale-tapped readings. The revision will also change the acceptance criteria to clearly indicate that all three sets of data must be within the allowable tolerance This will allow for the determination of hesteresis effect and deadband of the mete Licensee further states that this allegation should not be considered confirmed as their research demonstrated no utilization of the tapped reading for calibration purpose .2 Response to Detail 4.4: Pressure Switch Head Correction It was alleged that pressure switches PS-124 and PS-125 had an uncor-rected design error which had previously been brought to the atten-tion of a " Technical Support" group. The lack of a head-correction .

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factor during initial calibration of the switches caused them to be over-ranged and "made" (i.e., contacts closed) all the tim Licensee response indicates that'this alleged " design error" was, in fact, an oversight by a Startup Test Engineer. The licensee also indicates that this is an isolated case with no broad implications as it has been ascertained that the engineer concerned had correctly applied head correction factors in the calibration of other, similar-ly configured, instruments for which he was responsibl With regard to the switches being "over-ranged", the nominal range of these units is typically 30 psig. The current setting of'PS-125 slightly exceeds this value. An EEAR has been initiated to evaluate the long-term acceptability of this condition, and if necessary, specify a replacement switch. The licensee further states that no

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immediate corrective action is required since the calibration was successfully completed and the switch is currently functioning

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normall With regard to the " design error" having been reported to a "Techni-cal Support" group, the licensee states that the concern was written up on a Maintainability Task Force (MTF) Problem Identification For It has been determined that this form was never processed and pre-sented to MTF for consideration since it was not identified as a problem with the ability to maintain the instrument (which was the

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intent of the form). The correct method of identifying design, engi-neering and calibration problems is through the use of E&DCR or LILCO Deficiency Report, which will receive the appropriate attention and resolutio .6.3 Response to Detail 4.7: Impulse Line Trap A pressure sensing impulse line in the High Pressure Coolant Injec-tion (HPCI) system was alleged to create a " trap" due to its field-run configuratio The " trap" was alledged to cause false in-dication to HPCI pump suction pressure switch PS-1211, which results in keeping the pump "off". Also the calculated head correction fac-tor was allegedly applied wrong to the switch setpoin Review of this problem by_the. licensee's " Technical Group" was alleged to have been requested (by an unidentified source), however, "the foreman told the technician that management didn't want to hear about things like this now".

The licensee agreed with the results of the NRC investigation there were "no obvious traps". The licensee concluded that there were two areas of concern relative to the initial calibration. The first &rea was that the head correction was not properly applied during the C&IO in 1981. This condition was subsequently discovered and corrected by plant staff in 1984. The proper head correction factor assumes that the impulse line is full of water. The HPCI system Operating Proce-dure (SP 23.202.01) will be changed to add a step requiring the in- '

strument senstr.g line to be vented every time the system is filled and vented. The second concerns the setpoint. The nominal setpoint was originally 15". For a period, during 1984, a setpoint of 14" was used due to the temporary use of a 0-15" svitch. This switch was used as a replacement for a malfunctioning switch, until the correct replacement could be obtained. A decision was made to not use the switch at the absolute limit of its range. The correct switch has since been obtained and installed, and the 15" setpoint returne The licensee further states that the 15" setpoint is acceptable since the purpose of this switch is to protect the pump from a loss of suc-tion (due to improper valve lineup, blocakge of suction line. or loss ofinventory). Protection from cavitation is not the primary func-tion of the switch. In addition, the 2% tolerance applies to the trip point, not the reset point. The licensee states that this ap-plication is standard practic ..

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6.4 Response to Detail 4.15: Radwaste Laundry Drain Tank The licensee states that they do not agree that the allegation was fully substantiated. Although the switches are set slightly high (80%) they are still below the overflow level (90%). The licensee does agree that there is a difference between actual and indicated inventories in the tank, however this does not consititute a problem of great safety significance. Any overflow from one tank goes to~ the other, and excess beyond tank capacities goes to the Radwaste Build-ing Floor drain sump. To improve the situation, high level alarms have been calibrated so that alarm occurs at 1338 gallons, which is within 2% of intendeo 80% setpoint, and results in perfect agreement between high level alarm and indicated gallons. Instrument 0 has been changed to the center of the sensing line ta This gives excellent accuracy (1.2%) error) from 50% -75%. This also results in a difference from indicated level by approximately 9% for the full range of the instrumen '

The licensee-has committed to review the calibration methodology of all radioactive waste tank level . instrumentation loops during their next regularly scheduled preventive maintenance perio The inspector concluded that the licensee's response to the individual allegations is acceptable. . Revisions to procedures SP 46.030.01, SP 46.030.02 and SP 23.202.01 will be reviewed by the resident inspector when they are_ completed. The response to Detail 4.4, relating to pressure switch head correction points up a weakness in training, in that it shows that personnel were not aware of the correct means of reporting and re-solving engineering, design and calibration problems. The licensee should review this aspect of training and implement means to strengthen as necessar . Personnel Errors .

During this inspection period, December 1 - December 31, 1985, as well as during previous inspection periods, a number of events occurred, including actuations of Engineered Safeuard Feature systems, which were the direct result of errors by plant personne During December 1985, the following three events, which were required to'

be reported to the NRC, occurred:

. On December 17, 1985 during performance on a surveillance test, a technician accidentally pushed a wrong contact and caused an ESF Ac-tuation of the RBSVS syste . On December 18, 1985 during' performance of a surveillcnce test, a technician error caused isolation of the shutdown cooling and reactor

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water cleanup systems, initiation of the RBSVS system, loss of the

'B' RPS MG set, and a. Main Steam Line Hi Radiation isolation signa . -On December 19, 1985 a half scram, full isolation, 'A' RBSVS initia -

tion occurred when the RPS EPA breaker, IC71*BKR-004B was de-energized. The direct cause of this event has not been deter-mined, but the breaker was either deliberately placed in the "off" position by someone, or was accidentally bumped to the "off" position-during work in the are During November'1985, three events, which were required to be reported to the NRC, occurred. Additionally, one event was not required to be reported only due to plant conditions at the time. .They were:

. On November 2, 1985, during performance of a surveillance test, a technician error caused initiation of the RBSVS/CRAC side 'B' syste . On November 4, 1985, a full reactor trip and isolation occurred when personnel were transferring the power supply for the 'A' RPS bus from its alternate source back to its normal source-of power. This was due to.the switch being taken too fa . On November 12, 1985, the wrong breaker was orened by personnel dur-ing a taggout. This caused a half-scran, half-isolation and RBSVS initiation due to the loss of RPS Bus 'A'.

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On November 8, 1985, due to personnel error, Dis. charge Waste Sample Tank 'B' was receiving influent from the waste evaporator a' t .the same time the tank was being discharged overboard. This event was non-reportable only because activity of the discharged water was within limit These events, as well as other personnel errors over the previous months, have raised concern within the NRC. On December 20, 1985 the Senior Resi-dent Inspector met with the Plant Manager, Operations Division Manager, Maintenance Manager, Outage and Modifications Division Manager and Opera-tional Compliance Engineer to discuss this matter. Prior to that meeting, the inspector had given the Plant Manager a list of topics for discussio The NRC desired to have the licensee address these topics in relation to the problem of personnel errors at the plant. These topics included:

. What is the cause of these problems

. What are short and long term corrective actions?

. Have these problems been addressed in the past?

. Are there related problems or undiscovered other problems that could exist due to the same root causes?

. What can be done to. ensure management that the root cause of such problems are really discovered and solved?

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At the meeting, the Plant Manager emphasized to the inspector the licensee's concern over this matter and their intention to correct the problem. The licensee has initiated an extensive investigation into the situation to determine-root causes and corrective actions. The Plant Man-ager stated that the results of this investigation would be completed and submitted to NRC.for its review no later than January 10,- 1985. The licensee's immediate corrective action for the situation included a brief-ing for all supervisory personnel, from the foreman level up, on the need for caution and attention to detail. The foreman were instructed to en-sure that personnel under their supervision were cognizant of all aspects of their jobs, and were aware of the need for a reduction in personnel errors. Foreman and supervisors were also instructed to increase their direct supervision of personnel in the " field" to help minimize error The licensee has committed to provide NRC with the result 2 of its detailed investigation, and~its proposed corrective action by January 10, 198 NRC will review this information, and a determination will be made at that time as to what further actions, if any, need to be taken by the licensee or the NR Pending submission of the licensee's report, and review by NRC, this is designated as a inspector followup item 50-322/85-43-0 . Neutron Source Outage and Environmental Qualification of Electrical Equipment On December 30, 1985, the final Environmental Qualification (EQ) modifica-tions were completed, bringing the Neutron Source Outage which had begun on October 8, 1985 to a close. The licensee entered a transition period until the start of the Reactor Reference Leg modification. This was scheduled to begin on or about January 8,198 The final EQ modification, which was completed on December 30, was re-placement of the flow transmitters in the Main Steam Isolation Valve-Leakage Control System. This modification was one of the six that had not been completed by- the November 30, 1985 deadline (see NRC Inspec-tion Report 50-322/85-42). Completion of the other five modifications had been accomplished on; December 24 for the Low Range Accident Monitoring *

Panel, December 26 for the Hydrogen Recombiners, December 27 for the High Range Area Monitor Assemblies, December 18 for the Low Pressure Coolant Injection MG Set Power Supply and December 20 for the Raymond Actuators in the Reactor Building Standby Ventilation System. Although the EQ portion of two of the modifications, the Raymond Actuators and High Range Area Monitor Assemblies, were completed, some non-EQ problems were being worked as of the end of the inspection perio In addition to EQ modification work, the licensee also completed other maintenance and modification activities during the neutron source outag The Reactor Core Isolation Cooling (RCIC) system turbine exhaust check valves were replaced. The two old valves were of the swing-check desig The licensee, based on General Electric and vendor recommendations, deter-mined that these valves should be replaced with lift-type check valve _ - , .- .

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(See NRC Inspection Report 50-322/85-42 for further details). The instal-lation of these valves was completed during this inspection perio Reassembly of the Main Generator, after work on the statcr water cooling system, was complete on December 16, 1985. The licensee plans to complete all Turbine & Generator work so that it will be in a state of readiness for roll and initial synchronization by February 7,198 The licensee implemented inspection and modification to Anchor / Darling swing check valves during this outage (See Section 1.8). Modification 85-267 was generated to accomplish lock-wiring of the check valves. Com-pletion of the lock-wiring must be coordinated with other outage work due-to system availability, and this modification will be carried through to the reference leg outag The licensee completed. Fire Detection installation work, and is now in the process of testing. The licensee submitted a proposed Technical Specifi-cation change to the Office of Nuclear Reactor Regulation (Ref: SNRC-1211, J. D. Leonard, Jr., LILCO to H. R. Denton, NRC, " Licensee. Change Applica-tion #2, Shoreham Nuclear Power Station-Unit 1, Docket No. 50-322, Opera-

'ing License NPF-36", Dated November 16,1985) to reflect changes in the number and type of fire detector The modifications to the fire detection system were made in response to the findings of NRC Inspection Report 50-322/84-46. That report required the reworking of the fire detectors in all safety-related areas to comply with NFAP Nos. 720 and 72E. On December 9, 1985 the licensee submitted an update to this Technical Specification change to account for changes made in the as-built location of some fire detectors (Ref: SNRC-1220, J. D. Leonard, Jr. , LILC0 to H. R. Denton, NRC, " Additional Information Concernir.g License Change Application #2, Shoreham Nuclear Power Station-Unit 1, Docket No. 50-3f2. Operating License NPF-36, dated December 9, 1985). As of the end of the inspection period, the NRC had not dispositioned LILCO's request for a Technical Specification chang With the completion of the source outage, the inspector noted that the licensee had completed a significant number of activities with few prob-lem The inspector noted that activities were well coordinated among all licensee organizations to ensure that schedules were met and that problems were alleviated. The inspector noted that management of outage activities by Outage and Modifications Division personnel, at all levels, was excellent. The inspector also noted that licensee Senior management attention to the details of the outage was evident, and that this atten-tion permitted prompt and effective action to mitigate problems that aros No unacceptable conditions were identifie . 10 CFR 73.71 Report On December 29, 1985, the licensee made a one-hour Physical Security /

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The notification involved a security guard who was found sleeping on duty. The inspector reviewed the licensee's actions with regard to the event and found them acceptabl . Unresolved Items-Areas for which more information is required to determine acceptability

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are considered unresolved. One Unresolved item is discussed in Section . Management Meetings At periodic. intervals during the course of this inspection, meetings were held with licensee management to discuss the scope and findings of this inspectio Based on NRC Region I review of this report, and discussions with licensee

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representatives, it-was determined that this report does not contain information subject to 10 CFR 2.790 restriction The inspectors also attended entrance and exit interviews for inspections conducted by region-based inspectors during the peric .

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