ML20056C166

Insp Repts 50-220/93-01 & 50-410/93-01 on 930124-0227. Violations Noted.Major Areas Inspected:Plant Operations, Radiological Controls,Maintenance,Surveillance,Security & Safety Assessment/Quality Verification Activities

ML20056C166
Person / Time
Site:	Nine Mile Point
Issue date:	03/12/1993
From:	Raymond W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20056C158	List: ML20056C157 ML20056C164 ML20056C166
References
50-220-93-01, 50-220-93-1, 50-410-93-01, 50-410-93-1, NUDOCS 9303300173
Download: ML20056C166 (49)

See also: IR 05000220/1993001

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report Nos.: 93-01; 934)1 ,

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Docket Nos.: 50-220; 50-410  :

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License Nos.: DPR-63; NPF-69 i

Licensee: Niagara Mohawk Power Corporation l

301 Plainfield Road  ;

Syracuse, New York 13212  !

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Facility: Nine Mile Point, Units 1 and 2  ;

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Location: Scriba, New York i

Dates: January 24 through February 27,1993

Inspectors: W. L. Schmidt, Senior Resident Inspector

R. A.. Plasse, Resident inspector

W. F. Mattingly, Resident Inspector (in training)

S. A. Greenlee, Reactor Engineer  ;

D. S. Brinkman, Project Engineer, Unit 1, NRR

J. E. Menning, Project Engineer, Unit 2, NRR i

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App oved by: / //c////// 8 /2 73

f Date

William J. Rayng'Sectiof

Reactor Projectf No. l And, A fing Chief

Division of Reactor Projects ,

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Inspection Summary: This inspection report documents routine and reactive inspections of.

plant operations, radiological controls, maintenance, surveillance, security, and safety  ;

assessment / quality verification activities.  :

Results: See Executive Summary.  !

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9303300173 930323 (

PDR ADOCK ONOO220

0 PDR

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EXECUTIVE SUMMARY

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Nine Mile Point Units 1 and 2  ;

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NRC Region f Inspection Report Nos. 50-220/93-01 & 50-410/93-01

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01/24/93 - 02/27/93

Plant Operations

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Control room operators conducted routine activities well at both units. Unit 1 operators  !

performed well during an inadvertent reactor scram, unit restart, and unit shutdown to support

the scheduled refueling outage. Outage planning meetings, conducted by shift managers, i

provided excellent guidance of outage priorities, ensuring approved work was performed within l

the appropriate system windows.

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Radiological Controls  ;

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, The implementation of the radiological control program was observed to be satisfactory over the  ;

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period. Good planning and use of ALARA principles were observed during reactor water

cleanup filter work at Unit 1.

Maintenance ,

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Unit 2 maintenance personnel performed well during repairs to the Division II emergency diesel

generator pneumatic start control system. An unresolved item was identified concerning weak

work control and post-maintenance testing of Agastat relay reorientation maintenance. An

umesolved item was identified dealing with the supply and installation of an inadequate rotating

element (shaft and impeller assembly) for service water pump 1 A.  ;

Surveillance

The failure of I&C technicians to follow the reactor protection system surveillance test which

directly caused the Unit 1 trip was a violation. However, NMPC need not respond to the

violation because corrective actions were aggressive and well documented in LER 220/93-02.

Two unresolved items were identified which concern weaknesses in the measuring and test

equipment (M&TE) program and the inservice testing (IST) program.

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Exwutive Summary

Enrineerine and Technical Support

Inspectors reviewed concerns raised in a 10 CFR 2.206 petition, concluding that the Unit-1

primary containment isolation valves were: properly identified, properly tested, and that leakage ,

rates were accounted for properly.

An unresolved item was identified concerning a recent technical specification interpretation of  ;

the control building and electric tunnel unit cooler at Unit 2, and the effect of this determination

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on previous plant operating conditions. Inspector review of an engineering calculation to support

the acceptable vibration level of the standby liquid control system resulted in an unresolved item.

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The inspectors observed that the security force properly implemented the observed portions of  ;

the security plan.

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Safety Assessment /Ouality Verification

The inspector attended several site operations review committee (SORC) meetings and a safety

review and audit board (SRAB) meeting. In depth discussions at the meetings focused on safety.

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TABLE OF CONTENTS ,

1.0 SUMMARY OF FACILITY ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . I

1.1 Niagara Mohawk Power Corporation Activities . . . . . . . . . . . . . . . . . I

1.2 NRC Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I

1.2.1 Review of Containment Isolation Valve Concerns from a 10 CFR ,

2.206 Petition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 ,

2.0 PLANT OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2.1 Routine Control Room Observations . . . . . . . . . . . . . . . . . . . . . . . . 1 ;

2.2 Outage A ctivities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 f

2.3 Review of January 26 Reactor Scram . . . . . . . . . . . . . . . . . . . . . . . 3 j

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3.0 RADIOLOGICAL AND CHEMISTRY CONTROLS . . . . . . . . . . . . . . . . . . 4 ,

3.1 Routine Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

4.0 MAINTENANCE ....................................... 4

4.1 Emergency Diesel Generator Preventive Maintenance ............. 4

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4.2 Emergency Diesel Generator and Power Board Markup . . . . . . . . . . . . 5

4.3 Recirculation Flow Comparator Troubleshooting ................ 5

4.4 Energized Cable Damage During Flammastic Removal ............ 5

4.5 Agastat Relay Improperly Installed in the Low Pressure Core Spray

S y s te m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6  !

4.6 Service Water Pump Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . 7

5.0 S URV EI LLA N C E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

5.1 Reactor Recirculation Flow Converter Surveillance Testing . . . . . . . . . . 9

5.2 Control Measuring and Test Equipment . . . . . . . . . . . . . . . . . . . . . 10

5.3 Inservice Testing Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

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6.0 SECURITY AND SAFEGUARDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . I1 ,

7.0 ENGINEERING AND TECHNICAL SUPPORT ................... 12

7.1 Control Building and Electrical Tunnel Unit Cooler ............. 12

7.2 Standby Liquid Control System Vibration . . . . . . . . . . . . . . . . . . . . 12

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8.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION . . . . . . . . . . . . 13

8.1 Review of Licensee Event Reports (LERs) . . . . . . . . . . . . . . . . . . . 13

8.2 Site Operations Review Committee Meetings ................. 13

8.3 Safety Review and Audit Board Meeting . . . . . . . . . . . . . . . . . . . . 14

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TABLE OF CONTENTS (Cont'd) {

9.0 MANAGEMENT MEETINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 .

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• The NRC inspection manual procedure or temporary instruction that was used as inspection l

guidance is listed for each applicable report section. l

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DETAIIS

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1.0 SUMMARY OF FACILITY ACTIVITIES

1.1 Niagara Mohawk Power Corocration Activities

The Niagara Mohawk Power Corporation (NMPC) conducted nuclear activities safely at Nine

Mile Point Unit I (Unit 1) and Unit 2 (Unit 2). Unit 1 operated essentially at full power, until

January 26, when an improperly performed surveillance test resulted in an erroneous flow biased

neutron flux reactor scram. NMPC completed their review of this event and restarted the unit

on January 27. End of cycle coastdown limited reactor power following restart. A 55 day

refueling outage began with the unit shutdown on February 20. NMPC operated Unit 2 safely,

essentially at full power. Two personnel changes occurred during the period, Mr. J. Kaminski

temporarily replaced Mr. A. Salemi as the emergency preparedness coordinator for the site.

Mr. P. Smalley replaced Mr. W. Thomson as the Unit I radiation protection manager. Both  :

Mr. Salemi and Mr. Thomson have left NMPC.

1.2 NRC Activities

Resident inspectors conducted inspection activities during normal and off-normal hours,

including: 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> of backshift (evening shif*j and 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> of deep backshift (weekend, holiday,

and midnight shift).

1.2.1 Review of Containment Isolation Valve Concerns from a 10 CFR 2.2% Petition

During the week of February 1, the NRC Project Managers for Unit I and Unit 2 reviewed the

Unit 1 primary containment isolation valve program. This inspection was part of the NRC's

review of concerns identified in a 10 CFR 2.206 Petition filed on October 27,1992, by Mr. Ben

L. Ridings and provided assurance of the operability of the primary containment. Attachment

A to this report includes the details of the inspection.

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2.0 PLANT OPERATIONS (71707,93702)

2.1 Routine Control Room Observations  !

Control room operators conducted routine activities well at both units. Observations showed that

the Unit 1 operators performed well during scram recovery, and unit restart and shutdown

evolutions. Senior reactor operators (SROs) provided good direction to the reactor operators for

reactivity changes. Station shift supervisors (SSSs) and assistant SSSs (ASSSs) conducted good

turnovers and briefings, providing clear and concise guidance and shift priorities. NMPC

continued to place emphasis on reducing the number of lit annunciators in each control room. l

The inspector noted operators and reactor analysts utilizing appropriate procedures to support I

safe operation of both units.

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2.2 Outage Activities

The inspector observed the Unit I shutdown from power on February 19. The SSS conducted

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a good briefing of the activities that the shift would be performing, including power reduction,

removal of the turbine generator from the grid, and a low power manual scram. The crew had

completed training on the shutdown the previous day using the plant specific simulator. The

ASSS performed well in direction of the control room operators, leading to systematic

recirculation flow reductions and monitoring of reactor parameters by control room operators.

Outage planning meetings, conducted by shift managers, provided excellent coverage of

scheduled work and changing priorities. These shiftly meetings involved department supervisors

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with discussions focused on the activities of the highest priorities for the given shift. High

quality printed daily schedules and time lines allowed supervisors / management overview of

activities.

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The Unit 1 operations department prepared a well developed guideline, to allow management

of the risks associated with outage work. This guideline followed well with the outage planning

schedule as the windows for out-of-service equipment were reached. The operations department -

performed a shiftly assessment of plant conditions to ensure the operability of equipment

necessary for: decay heat removal, reactor water inventory, electrical distribution, reactivity

control, and containment closure. Operators used a prepared form, listing the possible  ;

components and systems available to reduce risk, to conduct these assessments, and posted the

completed assessments in several locations. NMPC intended these postings to give plant and

contractor personnel information to reduce the possibility of conducting work on a system relied

upon to reduce risk.

2.3 Review of January 26 Reactor Scram

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The operating crew performed excellently in response to the reactor scram on January 26. Unit

I received an erroneous high neutron flux reactor scram, generated by an improperly performed

, surveillance test. The plant responded as designed, reactor water level decreased, resulting in

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the feedwater system initiating in its high pressure coolant injection mode to reestablish level.

Immediate operator actions included commencing scram recovery and emergency operating

procedures to begin a controlled plant shutdown. The operations staff and plant management

exhibited very good questioning attitudes during the post-scram review process. The inspector  ;

attended the pre-restart site operations review committee (SORC) meeting and found that all the

issues necessary for restart were either dispositioned or tracked for resolution. Section 5.1 ,

discusses the NMPC critique and root cause evaluation conducted following this event.  !

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4 3.0 RADIOLOGICAL AND CHEMISTRY CONTROLS (71707) l

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3.1 Routine Observations

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The inspectors observed proper radiological controls during routine tours at both units. Good

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planning and use of ALARA principles were observed during reactor water cleanup filter work

at Unit 1. Implementation of a new entry and exit point into the radiologically controlled area,

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at Unit 1, was a good initiative. The inspectors found that NMPC used good radiological ,

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practices in tracking the immersion dose due to airborne radioactivity, in the reactor building

and on the refueling floor, early in the Unit 1 outage. Observations on the refuel floor indicated 7

a good radiological protection supervisory presence and knowledge of activities in progress and  ;

planned.

4.0 MAINTENANCE (62703)

Through observations of safety-related maintenance activities, interviews, and reviev of records

the inspectors verified the: proper use of administrative authorizations and tag outs, adequacy

of procedures, use of certified parts and materials, calibration of measuring and test equipment

(M&TE), proper implementation of radiological control requirements, use of controlled system

prints and wiring removal documentation, and proper establishment of quality control hold

points.

4.1 Emergency Diesel Generator Preventive Maintenance l

The inspectors observed an excellent example of preventive maintenance activities to address an

observed degradation, although within TS limits, of the start time for the Division II emergency ,

diesel generator (EDG). System engineering identified a delay in the startup sequence after

reviewing the EDG monthly operability surveillance procedure, N2-OSP-EGS-M001.

Specifically, during diesel starts, the procedure directs the operator to obtain a GETARS  !

(General Electric Transient Analysis Recording System) plot to measure the EDG's speed and  !

voltage during the first 10 seconds. Based on the speed information obtained, the Division II

EDG satisfied the TS operability acceptance criteria, however, the plot showed a slight ,

degradation in the response between 150 rpm and 600 rpm. Previous troubleshooting activities,

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of similar trends, determined that pneumatic start control system components could allow the

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fuel racks not to reach the full fuel position immediately following a start signal, thereby ,

delaying the acceleration of the engine. j

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NMPC system engineering and instrument and controls (I&C) determined that replacement of

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the associated pneumatic air valves should be conducted as a precautionary measure to prevent  :

a future EDG test failure. Operators properly remove the EDG from service, entered the '

appropriate LCO and preformed the appropriate tagout. I&C technicians satisfactorily completed

the replacement and as found bench testing of the 3-way air valves. Operations surveillance

procedure, N2-OSP-EGS-M001 satisfactorily retested the EDG and it was declared operable.

This timely identification and correction was an excellent example of preventive maintenance to

ensure EDG reliability.  ;

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4.2 Emergency Diesel Generator and Power Board Markup

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The inspector observed the establishment of electrical alignments to allow the rebuild of the 102

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emergency diesel generator (EDG) and preventive maintenance on components in its associated

power board. Review of the associated TS and TS interpretation for this condition and the  ;

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equipment status log showed that appropriate limiting condition for operation for the EDG and

power board outage were met. It should be noted that while the TS interpretation was adequate

Unit I does not have specific TS that address the requirements for on-site or off-site power

while shutdown or in refueling mode.

4.3 Recirculation Flow Comparator Troubleshooting

On January 28, the inspector observed proper performance and documentation of troubleshooting

activities for the channel #11 recirculation flow comparator. During reactor startup the

comparator unit trip locked up resulting in a rod block. This condition has been a recurring

pmblem and the previous troubleshooting activities determined the comparator circuit to be

temperature sensitive, however, the specific solid state circuit device susceptible to over-heating

was not determined. The I&C technicians performed the appropriate electrical checks of the

circuit and provided forced cooling of the internal components of the comparator circuit. The

technicians verified the unit reset with no existing trip condition. While NMPC could not

determine which component was temperature sensitive the converter was subsequently replaced

with newer refurbished equipment.

4.4 Energized Cable Damace During Flammastic Removal

On February 2, a contractor worker separating a retired cable from a bundle of flammastic

covered cables, pierced the insulation jacket of an energized cable with a screwdriver, resulting

in arcing between the screwdriver and ground. No automatic control circuit actuations or circuit

protective device tripped. Installed ground detection instrumentation indicated a -12 V DC

ground on the # 12 safety-related DC bus. Voltage measurements between the screwdriver blade

and ground indicated -65 V DC. The operations department and engineering determined the

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affected cable and the components. Engineering then completed an appropriate operability

determination to support operation with the screwdriver left in place pending a removal action

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plan.

The screwdriver removal plan covered the potential impact on safety systems and appropriate

contingencies to support the evolution including support from: fire fighters, electricians,

operators, and technical support personnel. The action plan also included operator guidance for

applicable limiting conditions of operation, fuse identification, and emergency operating

pmcedures necessary in the event cimuit damage resulted during the removal. NMPC handled

the removal as a special evolution and the inspector attended a well conducted briefing. The

inspector observed that electricians completed the screwdriver removal without incident. NMPC

preplanning, pre-evolution briefing, and management attention to this issue showed a strong

regard for minimizing the potential impact on plant safety.

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NMPC management placed a stop work order on Unit I contractor work pending review of the ,

event and approval of appropriate corrective actions. NMPC determined the primary cause of

the event to be: work instructions that failed to identify the need to remove flammastic to

support the cable removal; and, the contractor supervisor assigned a workman that did not have

training or experience in the proper removal of flammastic.

Construction services completed a formal root muse evaluation and lessons learned transmittal.

Plant management discussed the corrective actions with contractor personnel prior to release of

the stop work order. The inspector considered the review conducted by construction services

to have fully addressed the incident and adequately identified the needed corrective actions, prior

to resuming work. The primary corrective action was to review all work in progress and

scheduled work to ensure the WIP sheets fully describe not only the overall job, but also any

intermediate steps that have the potential for plant impact. In addition, a checklist was

developed to improve pre-job briefing guidance. For the specific example of flammastic

removal, a procedure was developed for installation and removal of flammastic inhibiting the  ;

use of sharp tools.

4.5 Agastat Relay Imoronerly Installed in the Low Pressure Core Spray System

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On February 21, NMPC identified an improperly installed relay in the low pressure core spray

system (LPCS). During performance of surveillance test N2-ISP-RHS-MO10, an annunciator

failed to alarm for pump discharge line pressure high via trip unit E21-N655. Initial review

determined Agastat GP series relay E21-K55 was improperly installed, seated in only 12 of 16 7

pins missing one row of stabs, which prevented the relay from performing its required function.

The SSS directed that the relay be properly reseated and completed the retest of the circuit in

accordance with the procedure. No other problems were identified and the ST was completed

satisfactorily.

NMPC determined that electrical maintenance had removed and rotated this relay 180 degrees

on January 23, after finding it upside down during a panel inspection. Based on the this and the

last surveillance test date, NMPC determined that the alarm function had been inoperable since

. January 23.

Based on an independent reviewed of the inspection procedure performed on January 23, ,

discussions with the SSS who authorized the activity, and observations of the location of the

relay in the cabinet, the inspector had the following observations:

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The impact of relay removal was not documented c:d a TS LCO was not entered. The ,

electrical maintenance department procedure N2-EPM-GEN-R724, Agastat GP Series

Relay Inspection and Seating required electricians to verify installation of the relays with  !

the nameplate (model number) facing up. On January 23,2 relays were found with the l

nameplates oriented down, relay E21 A-KO55 discussed above and relay E21 A-KO14. )

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Procedure step 7.3.2 provided a space for documentation of the plant impact of

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removing, rotating, and reseating relays. From discussion with the SSS and review of

the completed procedure, the inspector determined that no specific plant impact was  ;

! documented, the space was filled in with " as per operations". It appeared this activity '

was routinely performed verbally based on the simplicity of the reorientation actisity.

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Through review of plant electrical drawings the inspector determir,ed that relay E21 A- l

K055 only affected the alarm circuit and did not have an effect of system operability.

However, relay E21 A-KO14 provided the loss of coolant accident (LOCA) opening

signal to the core spray pump injection valve MOV-104 and its removal rendered the

valve inoperable. Based on inspector review it appeared the SSS authorized this work l

, without formally addressing the appropriate limiting condition of operation for an  !

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inoperable core spray system. l

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No post-maintenance testing was performed following miay reinstallation. Procedure I

j step 8.3 required the determination of PMT on a case-by-case basis after completion of

the relay reorientation. The inspector determined no PMT was prescribed for the

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reorientation of these two relays. The inspector reviewed site administrative procedure

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GAP-SAT-2, Post Maintenance Test Requirements, which provides guidance that for

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PMT. The inspector determined a lack of performance of circuit verification to be an

! example of inadequate PMT.

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Electricians did not identify the misinstallation of the relay using the procedure. After i

4 reorientation of the relay, procedure step 7.3.8 required the technician to perform a

seating clearance check with a feeler gauge between the relay base and relay socket, on  ;

diagonally opposite corners. The technician failed to properly perform this step in that

j he failed to identify the improper relay installation during the seating check.

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j The safety significance of the incorrect relay installation by the technician for relay E21-IL55 was

l low in that the LPCS system wou!d have still performed its safety function without the

J annunciator alarm. However, it concerned the inspector that this maintenance activity has

apparently been routinely performed without a formal plant impact documented, an appropriate

i technical specification LCO entry, and a lack of an adequate retest to ensure proper relay

i reinstallation and system operability. The inspector could not determine the safety significance

of this maintenance activity in the past. At the end of the inspection period NMPC was

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reviewing past records to determine how often relays were reoriented without proper work

, control and PMT. The inspector considered this item unresolved (410/93-01-01) pending NMPC

providing the maintenance history for agastat GP series relay reorientation.

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a 4.6 Service Water Pumo Maintenance

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In November 1992 mechanical maintenance disassembled service water (SW) pump P*lA

) looking for worn wear rings and reinstalled a refurbished rotating element (i.e., shaft and

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impeller). At that time, inservice testing (IST) identified degradation in developed head but the

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differential pressure developed was not in the alert range. With the new rotating element

installed, normal quarterly IST surveillance testing, done as post-maintenance test (PMT) showed

a degradation in developed head. Based on the old reference values from the previous impeller

the differential pressure developed was in the alert range. The pump was declared operable,

because it met the criteria stated in TS 3.7.1.1 for a SW pump to develop 80 psig discharge

pressure at 6500 gpm.

In early January mechanical maintenance disassembled the pump to investigate why improvement

was not shown with the new impeller installed. Upon disassembly technicians determined that

the diameter of the impeller was less than the designed size. Further, NMPC review showed

that the pump manufacturer (Goulds Pumps Inc.) refurbished the rotating element, which was

then left in the warehouse as a spare. Goulds replaced the originally installed impeller and

neither they nor NMPC verified that it was the same as originally installed. The rotating

element was removed and sent to Goulds to be refitted with the correct impeller. Subsequent,

IST reassembly showed improvement at the specified flow conditions.

The USAR, the Goulds pump certification, and operating procedures state that each SW pump

was designed to deliver 10,000 gpm at 185 feet of developed head. However, post-maintenance

testing for the impeller replacement in November 1992 and January 1993 did not include a

validation of a pump curve to ensure that the design flow requirements were met. GAP-SAT-02

Post-Maintenance Testing gave guidance that a pump curve validation should be done following

impeller replacement. The inspector was most concerned with the determination that the pump

was operable following the installation of the wrong impeller in November. With the smaller

impeller the developed head was lower at the IST test condition and due to the smaller impeller l

the flow and developed head design specification of 10,000 gpm at 185 feet of developed head,  !

may not have been met. The inspector considered the issue of supplying and installation of the  ;

impeller with the wrong diameter and the failure to validate the pump curve as an unresolved )

item (410/93-01-02) pending further review of the service water system flow design basis.

5.0 SURVEILLANCE (61726,61707)

Through observation of safety-related surveillance activities, interviews, and review of records,

the inspectors verified: use of proper administrative approvals, personnel adherence to procedure

precautions and limitations, accurate and timely review of test data, conformance of surveillances

to technical specifications, including required frequencies, and use of good radiological controls.

Surveillance activities observed included these listed and discussed below:

N1-STP-31 Diesel Generator Imd Testing

N1-ST-Q6B Containment Spray Quarterly Operability Testing

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5.1 Reactor Recirculation Flow Converter Surveillance Testing

On January 26, with the plant operating at full power and rated flow, Unit 1 experienced a high

flow biased flux reactor scram during the performance of procedure N1-ISP-032-004, Reactor

Recirculation Flow Converter Calibration. Each of the five reactor recirculation pumps has two

transmitters measuring discharge flow. Each of the two recirculation flow conveners (RFCs)

receives a flow input from each loop allowing the circuit to calculate total recirculation flow.

One flow convener supplies a signal to the four average power range monitors (APRMs) reactor

protection (RPS) channel #11 while the other supplies a signal to the APRMs in RPS channel

1. 12. The APRMs use the flow input to calculate the setpoint for the flow biased high reactor

power scram. If RFC sends a flow signal that is inadequate for the existing APRM power level

or if the power level is higher than the calculated level for a given flow, a half scram will result.

During the performance of N1-ISP-032-004, the procedure required inserting a manual half i

scram on RPS channel #11 while testing RFC channel #11. After completion of all the

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procedure prerequisites and preliminary actions, the I&C technician incorrectly completed step

7.2.1, which states that if recirculation flow was greater than 20% then N/A step 7.2.2 through

step 7.2.5. The I&C technician correctly determined the recirculation flow condition, however,

he failed to N/A the required steps and continued the procedure at step 7.2.2. Step 7.2.4 ,

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required the technician to rotate the RFC channel #12 mode switch from operate to test. This

action resulted with RFC channel #12 sending a zero flow signal to the RPS channel #12

APRMs. The APRMs saw power that was too high for zero flow and caused a half-scram on ,

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RPS channel #12, which coupled with the previously inserted manual half- scram on channel

1. 11, caused a full scram.

< The inspector determined NMPC completed a timely and effective determination of the primary ,

and contributing causes of the event. NMPC initiated a DER, held an accountability meeting

to capture the facts, and conducted a formal root cause analysis of the event. The inspector .

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attended the accountability meeting and the SORC meeting which reviewed the root cause

evaluation and the LER submittal describing the event. The inspectors considered the corrective '

actions, documented in LER 93-02 and discussed below, appropriate for this specific event and

for the broad scope of prevention of personnel errors during maintenance activities.

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Unit I maintenance management developed good written maintenance performance

principles, providing site personnel with fundamental management expectations in such

areas as pre-job briefings, self and peer verification of procedure steps, and procedure

adherence. These specific areas were identified as weaknesses in this particular event ,

and had they been performed in accordance with these guidelines, the event could have  ;

been prevented.

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NMPC committed to perform a self-assessment evaluation, by December 31,1993, to verify

adherence to these concepts and to determine the effectiveness of these corrective actions in

reducing personnel errors. '

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- NMPC plans to upgrade I&C technical knowledge level in high risk surveillance and

preventive maintenance activities. NMPC plans to improve the on-the-job training (OJT)

process with a focus on individual qualification signoffs and technical knowledge

requirements. NMPC stated that this action would be completed by March 31,1994.

In the interim, NMPC has committed to provide supervisory coverage for all I&C

procedures that involve half-scram initiations, engineered safety feature (ESF) actuations,

or have the potential for significant plant impact.

The safety significance of the incorrect actions taken by the technician was low, however, the  ;

unnecessary plant transient was not desirable. The inspector independently verified that the

circuits performed as designed. The inspector determined that the technician's failure to follow

the procedure caused the scram, due in part to, the lack of a second verification of the steps  ;

being performed, and an apparent weak technical knowledge of the equipment being tested. The

failure by NMPC personnel to follow the surveillance test procedure was a violation

(220/93-01-03) of TS 6.8.1, which requires the implementation of written procedures for

surveillance testing. Based on the timeliness and completeness of NMPC's corrective action a

response to this violation is not necessary, however, the issue will remain open pending further

inspector review.

5.2 Control of Meascring and Test Eculpment

The inspectors found that the NMPC program for the control of measuring and test equipment

(M&TE) met regulatory requirements and commitments. However, the knowledge of NMPC

personnel with respect to expectations for the control of M&TE following issue was weak. The

following are examples:

• The M&TE group expects that equipment not in use will be placed in a secure storage

area or controlled by an individual. The inspectors found several pieces of test

equipment in the Unit I and Unit 2 reactor buildings that were not in use, were not in  !

a secure storage area, and were not being controlled by an individual. Workers had

placed the equipment near the work area for use the next day or had left it on open ,

tables. The expectation to secure the equipment not in use or controlled by an individual

was not clear.

• Typically, the list of M&TE on the " Delinquent List" is long. This list, published

weekly, contains items checked out on a short term basis, and not returned within about ,

a week. Based on the volume of equipment items on this list, it is obvious that many

equipment users do not understand or are not sensitive to the expectations for return of

the items.

'

The NMPC administrative procedure for the control of M&TE (GAP-MTE-Ol) simply states

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that: "M&TE should be returned to storage immediately after use." This did not appear to

provide a clear statement of the expectation of plant management for the storage and return of

M&TE following use. The inspectors did not see any specific instances where M&TE control .

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brought into question the operability of the equipment. However, the inspector remained

concerned that if not properly controlled M&TE could be damaged without the knowledge of

the end user, and could lead to an operability concern. This issue was unresolved

(220/410/93-01-04) pending further inspector review of the M&TE program.

5.3 Inservice Testine Review ,

The inspectors reviewed and compared portions of the IST programs in place at both units

including: the establishment of fixed flow and reference differential pressure values and use of

installed plant instrumentation.

At both units the procedures specify a band of i2% of the fixed flow variable (i.e., if 6700

gpm was the fixed flow the operators could set flow at 6666 to 6734 gpm). NMPC stated that

this was done to take advantage of ASME Section XI IWP-4150 which states that " Symmetrical

dampening device or averaging techniques may be used to reduce instrument fluctuations to

within 2% of the observed reading." This did not appear to be in the spirit of Section XI since

the flow value could be set higher or lower than the fixed reference value, when it should be set

as close as possible.

'

One area where the units differ is that at Unit 1 operators are allowed to set the flow within the

required band and then look at differential pressure (delta-P). If delta-P is not within the

specified reference band, the operators can then adjust flow toward the end of the 2% band to

get the differential pressure to meet the requirements at the fixed flow value. This did not

appear to be in the spirit of Section XI since it states that the fixed flow shall be established and

the references data taken, not allowing for resetting of the flow. Depending on the shape of

the pump curve this could mean that a pump that did not meet its reference differential pressure

values at the fixed value could be passed by lowering the flow to the lower - 2% value.

The inspector reviewed the in plant instrumentation being used on several systems. Calibration

ofIST instruments was controlled by the PM/ST data bases. For panel instruments the inspector

found that the overall loop accuracies and readability of the panel meters was properly taken into

account. This ensured that a reading within i2% of the actual sensed parameter could be

disp?ayed. Loop calibration procedure generally contained steps to verify the accuracy of the

entire loop using a differential pressures device and recording the transmitter output and meter

outputs, verifying that readings were within specified ranges. If the ranges were not met,

calibration of the specific components in the loop was specified.

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The inspectors considered the use of the i2% band for the establishment of the fixed flow

variable and the use of flow band in conjunction with differential pressure measurements an .

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unresolved (220/410/93-01-05) issue pending further NRC review.

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6.0 SECURITY AND SAFEGUARDS (71707)

The inspectors toured the protected areas and did not identify any concerns. NMPC aggressively

pursued action on a previous unresolved item dealing with the effect of snow buildup.

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7.0 ENGINEERING AND TECIINICAL SUPPORT (71707,92703,37700)

7.1 Control Building and Electrical Tunnel Unit Cooler

At the SORC meeting on February 22 licensing and engineering personnel described some

incorrect assumptions used to meet environmental qualification requirements for certain

equipment. Because of a misunderstanding, the wrong assumptions were used originally

regarding the necessity to remove the heat generated during an accident and the effects of not

removing the heat. Engineering determined that temperatures in the divisionalized chiller

equipment rooms, cable areas and electrical tunnel area would exceed the design assumption of

104 F following a LOCA in 50 minutes to three hours depending on the location, if the coolers

were not operable.

'

Using this information engineering then reviewed the equipment that would be affected by the

loss of each unit cooler and determined specific LCOs for implementation. These ILOs were

based on how components would react to the high temperature, based on environment  :

qualification information. The inspector remained concerned over how the initial technical

specification interpretation (TSI) was developed and, based on the new information, whether any

operability problems existed in the past. The inspector considered this unresolved

(410/93-01-06) pending funher review of NMPC engineering calculations and judgements.

7.2 Standby Liquid Control System Vibration

The inspectors reviewed the standby liquid control system (SLC) design with respect to

vibrations and possible fatigue failure of the positive displacement pump discharge piping.

NMPC engineering had reviewed this issue and found it not to be a concern since (1) vibration

testing of the SLC piping was performed during pre-operational testing, and was satisfactory;

and (2) the probability of fatigue failure was extremely improbable since the piping is only in i

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service four times a year for about fifteen minutes for surveillance testing.

The inspectors re :wed the pre-operational data and found that the testing and the associatcd

acceptance calculations did not encompass the piping between the discharge of the SLC pumps

and the two explosive charge valves. Additionally, no calculations had been done to verify that

the probability of fatigue failure for these piping sections was extremely improbable.

Following the inspectors' review, engineering performed an evaluation of the discharge piping

vibration. Part of the evaluation consisted of simplified calculations assuming a 0.25 inch piping

displacement. The calculations showed that one point in the system (node point 65) could

experience fatigue failure assuming operation for four hours per year for forty years. The

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calculation also showed that no failure would occur if the vibration displacement was only 0.20

inches. Since NMPC does not have any actual data, pipe displacement will be measured during

the next surveillance test to confirm adequate system design. This issue was unresolved

(410/93-01-07) pending final disposition by NMPC and review by the NRC.

8.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION (71707,92700)

8.1 Review of Licensee Event Reports (LER_s)

Umt 1

LER 93-01 Described an event where the unit operated in excess of 100 percent rated core

thermal power after restoring the reactor water cleanup (RWCU) system to

service, due to a lack of a procedure requirement to verify core heat balance

parameters, after the restoration. The RWCU system flow rate process computer

point input dropped out of the computer's core thermal power calculation, causing

Unit I to operate at 100.5 percent. This event was discussed in detail in

combined inspection report 92-29/34. The inspector considered the immediate

actions taken to be timely and adequate, however, the issue remained open

pending issuance of the LER. Additional corrective actions discussed in the LER

included providing periodic refresher training for control room operators on the

operation of the 3D-monicore system and on shift training of OD-3, core thermal

power calculation. To determine potential safety significance NMPC evaluated

the affect of exceeding rated core tiiermal power on thermal limits by running a

3D monicore predictor log.

The 3D-monicore predictor log was run for a core thermal power slightly higher

than the actual reactor power level during the event. The prediction showed that

all core thermal limits were not exceeded for the most limiting locations in the

core. The analyses for the fission production barriers (i.e., the fuel clad, reactor

pressure vessel, and the primary containment) at 100.5 percent core thermal

power are bound by the accident analyses in the Updated Final Safety Analysis

Report (FSAR), which assumed a design basis accident at 102t ercent core

thermal power. The inspector determined NMPC corrective actions were

adequate to prevent recurrence and the event was of minimal safety significance.

This LER is closed.

Unit 2

LER 93-01 This event concerned the opening of the normal division II emergency switchgear

breaker due to a faulty optical isolator. This event, reviewed in combined

inspection report 92-29/34 was adequately discussed in the LER and the

corrective actions appeared appropriate.

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8.2 Site Operations Review Committec Meetines

The inspectors attended several site operations review committee (SORC) meetings. At each

meeting a quorum of members was present, and discussions were focused on safety.

A Unit 2 meeting on February 23 found changes to the site off-site dose calculation manual ,

(ODCM) and changes to a TS interpretation on unit cooler operability. The ODCM changes

were well presented and had previously been reviewed by SORC members. The changes to TS

interpretation 25 were the result of engineering review of the need for unit cooler opemtion in

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the control building. The revision of TSI 25 in force at the time allowed these specific unit  !

coolers to be taken out of senice without the entry into a TS LCO. On February 19 engineering

! had completed a study and determined that several control building and cable tunnel unit coolers,

,

which had previously been determined not to be necessary to support the operability of cooled

equipment, were necessary. A night note gave this information to the operating crews on that

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day and listed the TS LCOs for cooled components which needed to be utilized if a cooler was

i

not operable.

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8.3 Safety Review and Audit Board Meetine

i The inspectors attended portions of the February 3 Safety Review and Audit Board (SRAB)

meeting and verified that a quorum of members existed. The plant status briefings provided by

each plant manager were very good, leading to in-depth discussions amongst SRAB members.

!

The SRAB showed good safety perspective during discussions ofissues such as; the grounding

of the DC bus with a screwdriver, and the installation of an impeller of the wrong size in a Unit

l 2 service water pump.

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9.0 MANAGEMENT MEETINGS

,

At periodic intervals and at the conclusion, the inspector met with senior station management

to discuss the scope and findings of this inspection. Based on the NRC Region I review of this

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report and discussions held with NMPC representatives, it was determined that this report does

not contain safeguards or proprietary information.  ;

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A*ITAClIMENT 1

Nine Mile Point Unit 1

Primary Containment Isolation Valve Review

A. Inspection Scope

During the week of February 1 - 5,1993, the NRC Project Managers for Nine Mile Points Unit

1 and Unit 2 reviewed the Unit 1 primary containment isolation valve program. The inspection,

conducted as part of the NRC's review of concerns identified in a 10 CFR 2.206 Petition filed

on October 27,1992, by Mr. Ben L. Ridings, provided assurance of primary containment

isolation valve operability. Areas independently reviewed included: (1) validation of NMPC's

list of containment isolation valves and the list in the technical specification tables proposed by

the license amendment submitted by letter dated February 7,1992, (2) validation of isolation

signals to the valves, (3) validation of the valve testing according to the applicable requirements ,

of the Unit 1 inservice testing (IST) program plan and the 10 CFR Part 50, Appendix J, leak

rate test programs, (4) review of how NMPC addressed the petitioner's concerns, and

(5) verification that the proposed license amendment addressed the administrative deficiencies

listed in Attachment (5) to the Petition.

B. Background

NMPC designed, constructed (construction permit issued April 21,1965), and began operation

of Unit 1 (provisional operating license issued August 22,1969) prior to the publishing of 10

CFR Part 50, Appendix J, on February 14,1973. By letter and attached safety evaluation dated

May 6,1988, the NRC staff provided an evaluation of Unit I compliance with the requirements

of Appendix J to 10 CFR Part 50. The NRC staff's May 6,1988, letter and attached safety

evaluation required several changes to the technical specifications for containment isolation

valves and requested that NMPC submit an appa ,.riate license amendment application.

.

By letter dated November 20,1990, NMPC submitted a proposed license amendment to update

the containment isolation valve tables and to bring the technical specifications into conformance

I

with the requirements of 10 CFR Part 50, Appendix J, and the NRC staff's safety evaluation

dated May 6,1988. NRC staff and NMPC representatives discussed the contents of the

November 20,1990, submittal in a meeting held on March 5,1991. Follow'mg this meeting,

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NMPC representatives requested that the NRC staff suspend review of the November 20,1990,

submittal since NMPC would be revising and resubmitting the proposed technical specifications

based on comments from the March 5,1991, meeting.

By letter dated February 7,1992, NMPC submitted a proposed license amendment that '

superseded the November 20,1990, submittal and incorporated the comments from the March 5,

1991, meeting between NMPC and NRC staff representatives. The NRC staff reviewed the

February 7,1992, submittal and issued a request for additional information (RAI) to NMPC on

November 30,1992. The RAI identified 14 areas where the NRC staff had questions regarding

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Attachment 1 2

the amendment request. NMPC responded to this RAI by letter dated January 29,1993. ,

NMPC's January 29,1993, response and a February 18, 1993, submittal that superseded the

February 7,1992, submittal are being reviewed by the NRC staff.

'

On October 27,1992, Mr. Ben L. Ridings filed a petition with the NRC pursuant to 10 CFR

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2.206. The petition sought relief based on allegations that: (1) Unit I does not meet NRC

requirements for an engineered safety feature system (ESFS) grade high-pressure coolant  ;

injection (HPCI) system, (2) 45 percent of the containment isolation valves have administrative

deficiencies, and (3) NMPC, NMPC's quality assurance group, and the NRC have reviewed

these safety concerns and, contrary to any practical justification, have remained silent. These

allegations repeated concerns Mr. Ridings had identified to NMPC in January 1990, while he

was employed as a contractor at Unit 1.

'

By letter dated December 4,1992, the Director of the Office of Nuclear Reactor Regulation

, acknowledged receipt of Mr. Ridings' petition and informed Mr. Ridings that the Unit 1

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emergency core cooling systems satisfy the requirements of 10 CFR 50.46 without reliance on

the HPCI mode of the feed water system. The December 4,1992, letter also informed Mr.

Ridings that the NRC staff will review his petition in accordance with 10 CFR 2.206 and that i

a final decision regarding the petition will be issued within a reasonable time. Mr. Ridings  ;

supplemented his petition in a letter received by the NRC's Office of the Executive Director for l

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Operations on January 5,1993. The supplemental response also alleged that Unit I would not  !

! meet the leakage limits of 10 CFR Part 50, Appendix J, when the leakage rates of Category A l

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containment isolation valves were added to the leakage total for the primary containment.

The Unit I technical specifications list primary containment isolation valves in two tables: Table

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3.2.7 provides a list titled Reactor Coolant System Isolation Valves and Table 3.3.4 provides

. a list titled Primary Containment Isolation Valves Lines Entering Free Space of the Containment.

1

C. Completeness of Proposed Technical Specification Isolation Valve Tables

The inspectors independently developed a list of primary containment isolation valves using as-

built piping and containment drawings. In order to compare this list with TS Tables 3.2.7 and  ;

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j 3.3.4 of the February 7,1992, license amendment request, the inspectors needed to understand

the criteria used by NMPC in the development of the tables. NMPC stated that the tables were

developed to list any containment isolation valves that received an automatic isolation signal i

from the reactor protection system (RPS). Based on the comparison usmg this criteria, the l

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inspectors concluded that the two lists were consistent, with two exceptions. Specifically, the

proposed TS tables did not included valves 63-04 and 63-05 (post-accident sampling system

return isolation valves) identified on drawing F-45089-C, Sheet 8, Revision 3, as containment

isolation valves.

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Attachment 1 3

Following discussions with the inspectors, NMPC decided to change the criteria for listing

valves as containment isolation valves in the TS tables to correct this inconsistency. The revised

criteria would include only those isolation valves closest to the containment. Based on this

change in criteria the following changes would be made in the supplement to the February 7,

1992 submittal:

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Valves 63-04 and 63-05 would be left out of the TS table.

The inspectors verified that while these valves receive automatic isolation signals from

the reactor protection system, they are located in a branch line outside of containment

isolation valves 63.1-01 and 63.1-02 that also receive automatic isolation signals from

the reactor protection system.

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Valves 05-02 and 05-03R (emergency cooling high point vent to main steam); 39-llR,39-12R,39-13R, and 39-14R (emergency cooling steam line drain to main steam); and

05-0lR, 05@R, 05-11, and 05-12 (emergency cooling high point vent line), would be

removed from TS Table 3.3.4.

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The inspectors verified that containment isolation valves 39-03,39@,39-05,39-06,39-

07R,39-08R,39-09R, and 39-10R, located between these valves and the reactor coolant

system are included in proposed TS Table 3.2.7.

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Valves80-114 and 80-115 (containment spray discharge to waste disposal system) would

be deleted from TS Table 3.3.4.

The inspector verified that isolation valve 80-118 although not currently in the TS tables

could provide the containment isolation function. NMPC stated that Table 3.3.4 would

be updated to include valve 80-118 by a supplement to the February 7,1992, submittal.

Based on this review the inspectors agreed that the proposed change in criteria was appropriate,

since it minimizes extensions of the containment.

The inspectors also determined that the proposed TS tables did not included six normally closed

manual isolation valves. NMPC stated that these valves had not been included since they were

normally closed manually operated valves. During the inspection, NMPC decided, in order to

provide TS tables that list all containment isolation valves, to include four of these manual valves

(72-479,72-480,114-114, and 114-116) in TS Table 3.3.4. NMPC representatives stated that

these valves will be included in TS Table 3.3.4 in the supplement to the February 7,1992,

submittal. The other two valves (110-165 and 110-166) will not be included in the TS tables but

will be capped and tested as part of Type B penetration testing.

The inspectors concluded that if the supplement to the February 7,1992, submittal includes the

changes discussed above, all Unit I containment isolation valves will be listed in the two TS

tables.

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Attachment 1 4

in addition, the inspectors performed an independent review of the technical data in the TS

tables. With the exception of three errors described below, all entries were independently

verified as correct. ,

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, 1. On proposed TS page 148, the bracket indicating that the listed Initiating Signal is

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applicable to all four penetrations (Drywell Supply, Suppression Chamber Supply,

Drywell Return, and Suppression Chamber Return) of the H2 02 #12 Sampling system is

incorrectly drawn. The bracket erroneously indicates that the Initiating Signal is

applicable to the Self Actuating Check valves when in fact the Initiating Signal is

applicable only to the DC Solenoid valves in the Drywell Supply and Suppression

] Chamber Supply lines.

On proposed TS page 148, Note (1) was incorrectly applied to four places on the #11

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2.

H:0 2Sampling entries (Drywell Supply, Suppression Chamber Supply, Drywell Return,

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and Suppression Chamber Return). Note (1) states: "These valves do not have to be

vented during the Type "A" test. However, Type C leakage from these valves is added

to the Type A test results." Since these lines are required to be vented during Type A

tests, this note should not apply to these valves. In accordance with the NRC staff safety

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- evaluation dated May 6,1988, Note (1) is properly applied to the #12 H:02 Sampling

, entries on proposed TS page 148 since the #12 lines are used for monitoring during the

Type A test.

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. 3. On proposed TS page 148a, Note (1) was also incorrectly applied to the Containment

Atmosphere Monitoring Supply Line entry since this line is required to be vented during  ;

Type A tests.

These administrative deficiencies were discussed with NMPC and will be corrected in the

i supplement to the February 7,1992, submittal. The inspectors concluded that all other technical

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data entries in the TS tables were correct. The above noted three deficiencies were of no safety

significance. ,

D. Isolation Initiating Signals

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The inspectors verified consistency between the pertinent elementary RPS wiring drawings and

the valve isolation actuation signals listed in the license amendmcrl request. The inspectors i

reviewed a sample of recent test data to determine if these valves responded properly to their i

actuation signals. Specifically, test results from the most recent performance of procedure

N1-ST-R2, " Loss of Coolant Accident and Emergency Diesel Generator Simulated Automatic

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Initiation Test," during the period July 9-11,1992, were reviewed. This test inserted low-low

reactor water level and high drywell pressure signals (the most common actuation signals for

2 containment isolation valves) and verified that the specified isolation valves closed. Review of

the test results revealed that all valves listed in the procedure responded properly.

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Attachment 1 5

The inspectors verified that NMPC had similar test procedures in place and that these procedures

were being used to verify proper isolation valve response to other actuation signals.

[

E. Inservice Testing of Valves

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The inspectors reviewed Revision 3 of the Second 10-Year Inservice Testing Program Plan for

Unit I and verified that the plan included the independently developed list of containment

isolation valves and appropriate exercising and stroke time test requirements (for power operated

valves). Two surveillance tests which implement the IST requirements were reviewed.

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N1-ST-04, " Reactor Coolant System Isolation Valves Operability Test," performed

November 16-18, 1992.

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N1-ST-05, " Primary Containment Isolation Valves Operability Test," performed on

November 7,1992.

This review revealed that all the isolation valves listed in the procedures had been exercised and,

if required, stroke time tested. The procedures specified stroke time limits and the measured

results were consistent with the IST program and, if specified, with the TS limits. Based on

these reviews of IST data, the inspectors concluded that the valves included in the license

amendment have been properly exercised and stroke time tested as part of the licensee's ongoing

IST program.

F. Appendix J Testing of Valves

The inspectors reviewed the most recent local leak rate test (LLRT) results associated with l

procedure N1-TSP-201-550, "Iocal leak Rate Test - Summary (Type B and C Tests)." This ,

procedure is used to track the total containment leakage as LLRTs are performed following an

integrated containment leak rate test, to verify the 0.612 leak rate and the leak rate  ;

requirements of TS 4.3.3.f(l)(b)(i) and (ii) and 4.3.3.f(l)(c) are not exceeded. The inspectors  ;

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determined that leak rate totals were consistent with the requirements of Appendix J and the TS

as of January 29,1993. The inspectors verified that the leakage from all primary containment ,

isolation valves requiring Type C testing were included. Independent calculations of the total  ;

Type C leakage, based on the test data in the procedure, confirmed the correctness of the value

determined by NMPC. P

The inspectors noted that the calculation for total Type C leakage properly included the six ,

normally closed manual isolation valves that were not included in the license amendment request. *

However, Step 9.8 indicated that the leak rate limit of TS 4.3.3.f(l)(b)(i) applies to the sum of

the leakage from testable penetrations and the isolation valves listed in the TS tables. NMPC

stated that a Procedure Change Request would be initiated to correct the deficiency.

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Attachment 1 6

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The inspectors reviewed Drawing F-45089-C, Sheets 8 through 10, and verified that test

procedures have been identified for all of the containment isolation valves requiring Type C

testing per Appendix J of 10 CFR Part 50.

The inspectors reviewed the most recent leak testing results for water sealed valves designated

in the proposed TS, per 10 CFR 50, Appendix J. All such valves met their applicable leak test

requirements during their most recent tests.

The inspector determined the following during review of TS Table 3.3.4 Note (6), which states

that referenced valves are provided with a water seal capability but no Appendix J or IST testing

is required:

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Valves 63.1-01,63.1-02,05-05, and 05-07 are properly excluded from Appendix J and

IST testing since these valves do not provide an atmospheric leak path.

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Valves 80-15, 80-16, 80-17, 80-18, 80-19, 80-35, 80-36, 80-37, 80-38, 80-39, 80-65,

80-66, 80-67, and 80-68 were determined to have adequate water seals that did not

require water leak rate tests in accordance with the NRC' staff's safety evaluation dated

May 6,1988. ,

Therefore, the inspectors concluded that these valves are properly excluded from Appendix J and

IST testing.

G. Review of Concerns by NMPC Regulatory Compliance Group

,

The inspectors reviewed NMPC records regarding the processing of Mr. Ridings' concerns by

the NMPC Regulatory Compliance Group and by the NMPC Quality First Program (QlP).

NMPC stated they employed Mr. Ridings at Unit 1 as a contmetor from November 13,1989 -

January 18,1990. During his employment, Mr. Ridings identified and submitted to the NMPC -

Regulatory Compliance Group several concerns regarding the feedwater system operating in the

HPCI mode and containment isolation valves. NMPC reviewed these concerns between January

1990 and July 1990.

NMPC determined the HPCI concerns were invalid, since the Unit I accident analyses do not

rely on the HPCI system for mitigation of any accidents. Based on review of NMPC's records,

the inspectors concluded that NMPC had properly reviewed Mr. Ridings' concerns regarding

the HPCI system.

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In January 1990, Mr. Ridings identified to the NMPC Regulatory Compliance Group what he

believed were various inconsistencies in the listings of containment isolation valves in the i

technical specifications, in the updated final safety analysis report (UFSAR), and on the plant

drawings. Mr. Ridings also identified administrative deficiencies regarding the performance

of IST and leak tests according to the requirements of Appendix J. Reports of the identified ,

deficiencies were submitted to the NMPC Regulatory Compliance Group. NMPC reviewed the

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Attachment 1 7

identified deficiencies between January 1990 and July 1990. NMPC determined that some of

the deficiencies had been previously found acceptable by NRC staff-approved safety evaluations

and that some other deficiencies had been resolved by issuance of NRC staff-approved schedular

exemptions. NMPC also referred his list of deficiencies to the NMPC Licensing organization

to ensure that the deficiencies would be resolved by including them in the license amendment

then in preparation with the purpose of resolving deficiencies identified in the NRC staff's safety ,

evaluation dated May 6,1988. Based on review of NMPC's records, the inspectors concluded

that the NMPC Regulatory Compliance Group processed Mr. Ridings' concerns in an

appropriate manner. b

II. Review of Concerns by NMPC Quality Mrst Program (Q1P)

NMPC representatives stated that NMPC personnel had searched the QlP files and found no

record of Mr. Ridings contacting the QlP prior to receipt of a letter from Mr. Ridings dated

July 31,1990. NMPC informed the inspectors that QlP records were not considered plant

records unless a valid quality concern was determined to exist. Therefore, it is possible that

records of previous contacts may not exist if they had been dispositioned as a invalid quality

concern.

The inspectors reviewed a copy of a letter NMPC received from Mr. Ridings dated July 31,

1990, in which concerns regarding the Unit 1 HPCI system and the containment isolation valves

were outlined. These were a repeat of those he had previously identified to the NMPC

Regulatory Compliance Group. As was the practice at the time, the NMPC Q1P organization

contacted the NRC Resident Inspectors several times per month and informed them of the

receipt, status, and closure of QlP issues.

According to records reviewed by the inspectors, NMPC had reviewed Mr. Ridings' concerns

between August 1990 and November 1990. These records showed that NMPC closed out these

concerns on November 28,1990, after contacting Mr. Ridings and obtained his agreement for

closure. NMPC again determined that the concerns regarding the feedwater system operating

in its HPCI mode were invalid since the Unit I safety analyses do not rely on this operation to

satisfy the emergency core cooling requirements of 10 CFR 50.46. The NMPC licensing

organization received the concerns regarding the containment isolation valves for consideration

in the proposed license amendment development. The inspectors concluded that the NMPC Q1P ,

organization processed Mr. Ridings' concerns appropriately.

I. UFSAR Update I

In its January 29, 1993, letter, NMPC committed to update the UFSAR by June 30,1993, to

make it consistent with the proposed TS changes. This update to the UFSAR will resolve the  ;

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specific deficiencies identified in Mr. Ridings' petition.

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Attachment 1 8

J. Petitioner's Notes

The inspectors reviewed the administrative deficiencies associated with the containment isolation

valves identified in Attachment 5 of the October 27,1992,10 CFR 2.206 petition to determine

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if the deficiencies are being properly corrected by the February 7,1992, license amendment

request. Each of the notes listed in Attachment 5 of the petition and specific findings are

discussed in Enclosure (A).

i

The petitioner's comments in several notes relative to compliance with the General Design

Criteria (GDC) of Appendix A to 10 CFR Part 50 are not individually addressed in Enclosure

(A) since the inspectors concluded that the GDC do not apply to Unit 1. As stated in a Staff

Requimments Memorandum (SRM) dated September 18,1992, the Commission has determined

that the NRC staff will not apply the GDC to plants with construction permits issued prior to

May 21,1971. However, as noted in the SRM, each plant, including Unit 1, licensed before

May 21,1971, was evaluated on a plant specific basis and determined to be safe. The SRM

went on to state:

"At the time of promulgation of Appendix A to 10 CFR 50, the Commission stressed that the

GDC were not new requirements and were promulgated to more clearly articulate the licensing

'

requirements and practice in effect at that time. While compliance with the intent of the GDC i

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is important, each plant licensed before the GDC were formally adopted was evaluated on a

plant specific basis, determined to be safe, and licensed by the Commission. Fmthermore,

nrrent regulatory processes are sufficient to ensure that plants continue to be safe and comply

w;th the intent of the GDC. Backfitting the GDC would provide little or no safety benefit while

requiring an extensive commitment of resources. Plants with construction permits issued prior

to May 21,1971 do not need exemptions from the GDC."

K. Conclusion

The inspectors concluded that the Unit 1 primary containment isolation valves listed in related

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TS tables have been properly identified, that the valves receive proper actuation signals, and are

being tested in accordance with the applicable requirements of the IST program. The

acceptability of the Appendix J program will be determined by the NRC staff during its review

of the proposed license amendment. The inspectors concluded that the deficiencies related to

these valves, identified in the 10 CFR 2.206 petition, will be properly corrected by the proposed  ;

license amendment, as supplemented, and by the related UFSAR update that NMPC has ,

committed to make. The deficiencies were administrative in nature and of no safety l

significance, since the containment isolation valves were operable and being properly tested in

accordance with applicable regulatory requirements. Further, NMPC's Regulatory Compliance

and QlP organizations processed Mr. Ridings' concerns in an appropriate manner.

.

d

. _ _ __ _ - .__ _ _ _ . _ _ - .__

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Attachment 1 9

The inspectors also concludexi that NMPC's management provided weak support for timely

resolution of the containment isolation valve issue. The NRC staff safety evaluation dated

May 6,1988 identified the need for a complete review of this issue. Additionally, the staff

identified deficiencies in the November 20,1990, and February 7,1992, licensee submittals.

Further, the inspectors identified deficiencies during the February 1-5,1993, on-site inspection.

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A'ITACIIMENT (1), ENCLOSURE (A)

REVIEW OF A'ITACIIMENT (5) TO OCTOBER 27,1992,10 CFR 2.206 PETITION l

Note 1: "FSAR Section VII requires these valves to go open within 20 sec Hi Drywell or

low-low reactor level R.PS signal and this times fails to appear in either TS Table l

3.3.4 or FSAR Table VI-3a. Also, these valves are 10 CFR 50 Appendix A l

Criterion 55 valves and are not being tested accordingly." l

\

Findings: Note 1 applies to core spray valves 40-01,40-02,40-09,40-10,40-11 and 40-12.

NMPC determined that the correct maximum opening time for these valves is j

22.5 seconds, as indicated in Revision 8 of UFSAR Section VII. A.4.0 (page VII-  :

9). The proposed TS amendment request (page 119) is consistent, requiring a  !

22.5 seconds opening time on reactor water level low-low or high drywell

pressure signals. The inspectors verified that these valves were being properly

tested.

Note 2: " Containment Spray Test line currently does not receive RPS signal to go closed. )

The effectiveness of one containment spray pump is lost until operator response l

i manually closes valve should the accident occur during testing of containment .

I

spray pumps. Also, this is a criterion 56 valve and is not being tested

accordingly and should appear in TS 3.2.7 and FSAR Table VI-3b." l

-  ;

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Findings: Note 2 applies to the remote manual containment spray test valve 80-118. The I

inspectors reviewed NMPC Safety Evaluation (SE) No. 89-13, which considered

reduction of containment spray flow due to valve 80-118 remaining open. NMPC

concluded that sufficient system flow is available under accident conditions even

if valve 80-118 fails in the fully open position. The inspectors reviewed NMPC's 1

approved SE No. 89-13 (Revision 5) dated September 15, 1991, and concluded l

that it provided an appropriate basis for concluding that sufficient flow would be l

available. NMPC indicated during the inspection that valve 80-118 would be

added to TS Table 3.3.4 in a supplement to the February 7,1992, license

amendment request. The inspectors verified that these valves were being properly

tested.

• Note 3: "FSAR Table VI-3b shows these valves receive no RPS signal. TS Table 3.3.4

shows these valves receive signal to open. P&ID C18012C shows RPS logic to

these valves. Also, these are criterion 56 valves and are not being tested

accordingly."

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Attachment (1), Enclosure (A) 2

Findings: Note 3 applies to containment spray valves 80-15, 80-16, 80-35, and 80-36.

Thcse are normally open valves. The NMPC amendment request (page 147a)

shows that these valves open on remote manual initiation, consistent with

Drawing C-18012C, Sheet 2, Revision 36. The inspectors verified that these

valves were being properly tested.

Note 4: "FSAR Table VI-3a shows a close stroke time of 18 seconds while TS Table

3.2.7 shows 10 second closure. Even though this is more conservative, the

discrepancy came about as an error because components are not individually listed

in tables."

Findings: Note 4 applies to scram discharge volume valves 44.2-15 and 44.2-16. The 18-

second closing time previously listed in the UFSAR was recognized by the

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licensee as being in error. The error was corrected and Revision 10 of UFSAR

Table VI-3a shows a closing stroke time for these valves of 10 seconds, consistent

with page 119a of the license amendment request. The inspectors reviewed

NMPC SE No.89-033 which was approved by NMPC on December 18,1989,

and concluded that it provided an appropriate basis for this change.

Note 5: "FSAR Table 3a shows RPS logic to close with core spray actuation while TS

Table 3.2.7 does not."

Findings: Note 5 applies to core spray high point vent valves 40-30,40-31,40-32, and 40-

33. Revision 10 of UFSAR Table 3a (page VI-48) indicates that these valves

close on low-low water level, high drywell pressure, or core spray actuation

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signals. The license amendment request (page 119) states that the valves close

on low-low water level or high drywell pressure. Although both the UFSAR and

proposed license amendment are correct and in agreement, the licensee committed

in their submittal of January 29,1993, to change the UFSAR to eliminate

reference to the core spray actuation signal since it is redundant. Core spray ,

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actuation is initiated by low-low water level or high drywell pressure signals.

Note 6: "FSAR Table 3b shows these valves with a 70 second and 90 second stroke time. i

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These valves should appear on TS Table 3.3.4."

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Findings: Note 6 applies to containment spray valves discharge valves to rad waste 80-114

and 80-115. Revision 10 of UFSAR Table 3.b (pages VI-50A and 50B) shows 3

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maximum stroke times of 70 and 90 seconds for valves80-114 and 80-115,

respectively. The license amendment request (page 147b) incit. des these valves

but does not provide stroke time limits. The inspectors discussed this matter with ;

licensee representatives who initially indicated that the proposed license i

amendment would be supplemented to include the proper maximum stroke time

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4 Attachment (1), Enclosure (A) 3

for these valves (60 seconds). However, NMPC subsequently decided to delete

valves80-114 and 80-115 from TS Table 3.3.4, as stated in Attachment (1),

Section C above. The licensee committed in their January 29,1993, submittal

to update the UFSAR.

Note 7: "P&ID 18014C sht [ sheet] 2 shows these valves receive an RPS signal however, i

FSAR Table VI-3b and TS Table 3.3.4 fail to include these penetrations and

stroke times."

Findings: Note 7 applies to containment atmosphere monitoring valves 201.7-08 and 201.7- (

09. The license amendment request (page 148a) includes these valves and shows

that they automatically close on low-low water level or high drywell pressure  ;

signals with a maximum allowable stroke time of 60 seconds, but they were not <

in the UFSAR. The licensee committed in their January 29,1993, submittal to

update the UFSAR.

,

Note 8: "These valve are criterion 56 valves which appear in FSAR Table VI-3b. These l

valves may or may not (see note 12) appear in TS Table 3.3.4. TS as written, ,

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it is impossible to distinguish however these valves are identified in surveillance

test (N1-ST-Q5) as TS acceptance criteria." r

f

Findings: Note 8 applies to the #12 containment H2/02 analyzer system valves 201.2-23 l

through 201.2-30 (8 valves). The license amendment request (page 148) includes ,

these valves and shows that they close on low-low water level or high drywell  :

pressure signals with a maximum stroke time of 60 seconds, which is consistent ,

"

with the UFSAR.

Note 9: "FSAR Table VI-3a shows RPS logic to close however TS Table 3.2.7 does not  !

identify these valves. Also, valves (*) appear on P&ID C18006C with no RPS l

logic while they are identified with RPS logic on P&ID C18017C."

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Findings: Note 9 applies to emergency cooling vent and drain valves 05-02,05-03, 39-11,

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39-12,39-13, and 39-14 and recirculation system sampling valves 110-127 and -

110-128. The license amendment request (page 118) includes valves 05-02,05-

03, 39-11,39-12,39-13, and 39-14 and indicates that they automatically close on

specified signals with a maximum permissible closing time of 10 seconds. Page

"

i 119a of the license amendment request includes valves 110-127 and 110-128 and

shows that they have a maximum allowable closing time of 20 seconds and close

automatically on specified signals. However, NMPC decided to delete valves

05-02, 05-03, 39-11, 39-12.,39-13, and 39-14 from TS Table 3.2.7., as stated in

a Attachment (1), Section C above. The licensee committed in a December 21,

1992, letter providing comments on Mr. Ridings' petition to issue a Document

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Change Request to revise Drawing C-18006-C to properly identify the RPS logic

inputs.

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11

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Attachment (1), Enclosure (A) 4

Note 10: "These valves are deactivatix! and the TS and appropriate FSAR sections should be

revised to reflect this change."

Findings: Note 10 applies to torus fill from condensate sptem valve 58.1-01 and head spray

valve 34-01. Neither valve is included in the proposed license amendment request

since they are not containment isolation valves. The licensee committed in the

January 29,1993, submittal to update the UFSAR to reflect the current status of

these valves.

Note 11: "These valves are identified on P&ID C18014C sht 1 as receiving RPS logic yet do

not appear in FSAR Table VI-3b or TS Table 3.3.4."

Findings: Note 11 applies to the #11 containment H,/0 2analyzer system valves 201.2-109,

201.2-110,201.2-111,201.2-112,201.7-01,201.7-02,201.7-03,201.7-04,201.7-

10, and 201.7-11 and post-LOCA vent valves 201.1-09, 201.1-11, 201.1-14,

201.1-16. The proposed license amendment request (pages 148 and 148a) includes

these valves and indicates that they automatically close on low-low water level or

high drywell pressure and have a maximum allowable stroke time of 60 seconds,

which is consistent with the UFSAR.

Note 12: "FSAR Table VI-3b show RPS logic to close however TS table 3.3.4 does not  !

identify sese valves. Effects surveillance program and procedure revision."

,

Findings: Note 12 applies to post accident sampling valves 63-04, 63-05, and 122-03 and l

normal reactor building ventilation valves 202-07, 202-08, 202-35, and 202-36. l

Drawing C-18013C, Revision 23, shows that valves 202-07, 202-08,202-35, and l

202-36 are not primary containment isolation valves. These valves are actuated l

by signals from the Reactor Building Protection system, rather than by the RPS.

The license amendment request (page 119a) includes valve 122-03 and indicates

that it closes automatically on specified signals with a maximum allow 2ble stroke

time of 30 seconds. NMPC decided that valves 63-04 and 63-05 will not be l

included in the license amendment request, as discussed in Attachment (1), Section

C above.

Note 13: "P&lD C18005C sht 1 show HPCI logic to close yet are not identified in TS or

FSAR. Also not identified in IST Program."

Findings: Note 13 applies to feedwater system valves 30-31,30-32, and 29-51. These valves

are not identified in the TS or UFSAR tables since they are not containment

isolation valves, as shown on Drawing C-18005C, Sheets 1 and 2. These HPCI-

related valves are beyond containment boundary valves31-01R and 31-02R. HPCI

valves are not safety related and therefore, are not part of the IST Program.

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Attachment (1), Enclosure (A) 5

Note 14: "FSAR Table VI-3b show RPS logic to close however TS Table 3.3.4 does not

identify these valves. Also, tested 1AW NI-ST-Q5, current procedure 5 sec TS l

acceptance criteria that does not exist. Also, these valves do not appear on

drawings C18014C as identified in IST plan."

Findings: Note 14 applies to traversing incere probe (TIP) valves TIP-1, TIP-2, TIP-3, and

TIP-4. (These valves are also identified as36-147,36-148,36-149, and 36-150,

respectively.) The proposed license amendment request (page 148a) includes these

valves and indicates that they automatically close on low-low water level or high

drywell pressure with a maximum acceptable stroke time of 60 seconds. NOTE

1 on pages 111-12-1 and -2 of the Second Ten-Year Interval IST Program dated

October 12, 1992, states that these valves are not shown on P&ID C-18014-C, L

Sheet 2. This is acceptable as the valves are adequately tracked in the IST

program.

Note 15: " Currently tested I AW N1-ST-Q7 with IST acceptance criteria of 60 sec. No FSAR

or TS Stroke times identified."

Findings: Note 15 applies to reactor building closed loop cooling water valves 70-92,70-93,

70-94, and 70-95. Valves 70-92 and 70-94 are remote manual valves and valves

70-93 and 70-95 are self-actuated check valves all are in closed loops inside the

containment. The proposed license amendment request (page 148a) includes these

four valves and indicates that the two remote manual valves (70-92 and 70-94)

have maximum permissible stroke times of 60 seconds. The current TS table and

UFSAR list a 30 second stroke time. The licensee committed in their January 29,

1993, submittal to update the UFSAR.

Note 16: "FSAR VI-3c identifies these valves as criterion 57 valves. TS Table 3.3A

identifies these valves as both criterion 56 and 57 valves. This is physically

impossible. Secondly, these valves are not tested to either criterion."

Findings: Note 16 applies to reactor building closed loop cooling water valves 70-92,70-93,

70-94, and 70-95. The proposed license amendment (page 148b, Notation 4) states

that the valves do not require leak testing as they do not meet the requirements of

Section II.H of 10 CFR Part 50, Appendix J. The valves do not require Appendix

J 1eak ate testing since they provide isolation for a closed loop inside containment.

The inspectors verified that these valves were being properly tested.

Note 17: "TS Table 3.3.4 identified these valves as Criterion 56, however, are not being

tested according. FSAR Table VI-3b shows these valves as lines entering free space

of containment yet are not being tested according."

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Attachment (1), Enclosure (A) 6

Findings: Note 17 applies to containment spray valves 80-01, 8002, 80-15, 80-16, 80-17, 80-

18, 80-21, 80-22, 80-35, 80-36, 80-37, 80-38, 80-65, 80-66, 80-67, and 80-68.

The license amendment request (page 147a) includes all of these valves. Valves 80-

17, 80-18, 80-37, 80-38, 80-65, 80-66, 80-67, and 80-68 are self-actuating check

valves and therefore do not require stroke time testing. Valves 80-15,80-16, 80-35,

and 80-36 are normally open remote manual valves with a maximum allowable

stroke time of 60 seconds. Valves 80-01, 80-02, 80-21, and 80-22 are normally

open remote manual valves with a maximum allowable stroke time of 70 seconds.

The inspectors verified that these valves were being properly tested.

Note 18: "FSAR Table VI-3b and TS Table 3.3.4 identify these valves as criterion 56 valves

howcVer are not being test accordingly."

Findings: Note 18 applies to the core spray system pump suction valves 81-01,81-02,81-21,

and 81-22. The license amendment request (page 147) includes these valves and

shows that they are remote manual valves with a maximum stroke time of 90

seconds, which is consistent with the UFSAR. Note 3 ca page 148b of the license

amendment request states that these valves are provided with a water seal and will

be tested during each refueling outage not to exceed 2 years consistent with

Appendix J water seal requirements. leakage rates are not to exceed 0.5 gpm per

nominal inch of valve diameter up to a maximum of 5 gpm. The inspectors verified

that these valves were being properly tested.

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