ML20133A503

Insp Rept 50-213/96-11 on 960921-1115.Violations Noted. Major Areas Inspected:Plant Operations,Maint,Engineering & Plant Support

ML20133A503
Person / Time
Site:	Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png
Issue date:	12/24/1996
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20133A483	List: ML20133A481 ML20133A491 ML20133A503
References
50-213-96-11, NUDOCS 9612310147
Download: ML20133A503 (71)

See also: IR 05000213/1996011

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U.S. NUCLEAR REGULATORY COMMISSION

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REGION I

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Docket No.:

50-213

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License No.:

DPR-61

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Report No.:

50-213/96-11

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Licensee:

Connecticut Yankee Atomic Power Company

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P. O. Box 270

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Hartford, CT 06141-0270

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Facility:

Haddam Neck Station

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Location:

Haddam, Connecticut

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Dates:

September 21,1996 - November 15,1996

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inspectors:

William J. Raymond, Senior Resident inspector

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Peter J. Habighorst, Resident inspector

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Edward B. King, Physical Security inspector

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Barry C. Westreich, Resident inspector

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Larry L. Scholl, Reactor Engineer

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Alfred Lohmeier, Senior Reactor Engineer

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Approved by:

John F. Rogge, Chief, Projects Branch 8

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Division of Reactor Projects

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9612310147 961224

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ADOCK 05000213

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EXECUTIVE SUMMARY

Haddam Neck Station

NRC Inspection Report No. 50-213/96-11

This integrated inspection included aspects of licensee operations, engineering,

maintenance, and plant support. The report covers a seven-week period of resident

inspection; in addition, it includes the results of announced inspections by regional

specialists.

Plant Operations:

Licensee corrective actions were ineffective in preventing a reactor dilution on September

26,'1996. Operations personnel did not properly monitor the transfer of water to the

refueling water storage tank, did not investigate potential dilution of the emergency

boration flowpath, and did not follow normal operating procedure (NOP) 2.6-3. No

preventive maintenance program existed for valve (BA-V-367) that was suspected of

leaking-by. This was an apparent violation of 10 CFR 50 Appendix B Criterion XVI.

The upgrade of various operating procedures was appropriate. The quality and detailin the

procedures improved when compared to the procedures prior to September 1,1996. A

violation of technical specification (TS) 6.8.1 was identified whereas the licensee did not

have a procedure for a fuel handling accident. The emergency operator procedure (EOP)

exercise on a postulated cavity sealleak was successfully implemented by the refueling

crane operators. The training for operators appropriately focused on the details and

purpose for the significant changes to operations shutdown procedures.

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The reactor drain down and actions to evaluate cavity sealleakage were acceptable.

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Actions to prepare the plant for defueling were thorough. The defueling operations were

safely conducted utilizing good teamwork and communications. The refueling senior

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reactor operators (SROs) maintained good management oversight and professional

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demeanor. Training records and the content of refueling-related training material were

acceptable. The licensee did not have a training program description and implementing

procedure for conducting refueling operations and fuel movements that outlined

management's expectations for the training of licensed operators and contractor personnel.

Maintenance:

The licensee addressed several significant material deficiencies prior to entry into the

refueling mode and completing core offload. The residual heat removal (RHR) pump failed

due to the rotation of the baffle, which was caused by the inadequate sizing and spacing

of the oil baffle seal. A contributor to the inadequate corrective actions to resolve the

problem was the lack of the pump vendor drawings. Actions were completed to modify

and significantly upgrade the preventive maintenance checks performed on the refueling

equipment. New tools were used to facilitate fuel movement in the spent fuel pool. The

plant mechanics were not provided specific guidance on the maximum torque for fasteners

on threaded cast iron flanges in the fire protection system.

The surveillance test to verify operability of the spent fuel building ventilation system was

not adequate to ensure that acceptable air flow is achieved. This surveillance inadequacy

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resulted in a historical violatior' of the technical specificetions to maintain adequate

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ventilation flow during fuel movement. Additional calibration program and surveillance test

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deficiencies resulted in apparent violations regarding the heat trace circuits for the boric

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acid system, and the testing of a containment penetration.

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The licensee addressed several significant deficiancies in the spent fuel cooling system.

The licensee identified flaw indications in the spent fuel pool (SFP) service water system

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(SWS) supply lines during the Inservice Inspection (ISI) of five welded pipe supports. NRC

review included the location of the reported indications, the description and nondestructive

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techniques used to characterize the indications, the evaluation of the SWS supply line

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operability, and the corrective action taken to preclude failure of other SFP SWS supply line

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piping. The safety significance of the findings of " pipe lap" defects in the supply pipe was

satisfactorily evaluated. The expanded inspection of all SFP SWS supply pipe at the

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support hangers, the metallurgical characterization of the defects, the NDE examinations of

the defects, the analytic evaluation of the defects, and the corrective action taken was

consistent with good engineering practice.

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Engineering support for plant operations showed mixed performance. The initial decision

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regarding operational readiness of the spent fuel pool cooling system for defueling

operations was non-conservative with respect tc the technical specifications and the

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implementing surveillance procedure. A planned modification to correct a long standing

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deficiency changed a check valve design and location was completed prior to defueling

activities. This modification was implemented to improve the cooling system

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configuration. The temporary modification to supply cooling water to the spent fuel pool

was performed satisfactorily, with appropriate contingency planning and monitoring of pool

temperatures,

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The inspector noted a lack of engineering rigor for a past modification to protect safety

equipment from an internal flood scenario. The modification did not require flood barrier

installation for approximately thirty-five (35) penetrations. This failure resulted in a non-

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conservative flood analysis regarding operator response time to mitigate the event. This

condition is considered an apparent violation of 10 CFR 50 Appendix B, Criterion Ill,

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Inadequate engineering support was identified regarding the safety-related instrumentation

setpoint calculations and calibration procedures. Two apparent violations were identified

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regarding the calculation of instrument setpoint allowances, and for the corrective actions

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taken for failed instrument calibrations. The inspection also identified weaknesses in the

independent verification process. These weaknesses were evident in the setpoint reviews

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and also in a technical specification clarification that was issued for the reactor vessel level

indicating system.

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The licensee f ailed to implement two commitments in response to a violation and a

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deviation due to less than adequate internal assignment development and inexperienced

personnel in the licensing organization. Although actions were completed to address

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deficiencies in the procedure used to assess control room habitability, the bases for the use

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of portable breathing apparatus was found to be inadequately supported by engineering

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calculations. Further NRC review is warranted to determine whether the licensing basis for

the spent fuel pool cooling system is adequately defined relative to single failures. The

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failure to make a prompt report regarding plant operation outside the design basis due to

an inoperable B residual heat removal pump was a violation of 10 CFR 50.72.

Plant Support:

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The licensee maintained an effective security program. Management support is ongoing as

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evidenced by the timely completion of the vehicle barrier system and the installation of the

biometrics hand geometry system for more positive plant access control. Alarm station

operators were knowledgeable of their duties and responsibilities, security training was

being performed in accordance with the NRC-approved training and qualification plan and

the training was well documented. Management controls for identifying, resolving, and

preventing programmatic problems were effective and noted as a programmatic strength.

Protected area detection equipment satisfy the NRC-approved physical security plan (the

Plan) commitments, and security equipment testing was being performed as required in the

Plan Maintenance of security equipment was being performed in a timely manner as

evidenced by minimal compensatory posting associated with non-functioning security

equipment, and documentation weaknesses noted during the previous inspection had

improved. As an addition to the inspection, Section 6.8 of the Plan, titled Keys, Locks,

Combinations and Related Equipment was reviewed. The inspector determined, based on

discussions with security supervision, procedural reviews, and by performing an inventory

of the key storage cabinets, using the licensee's lock and key accountability

documentation, that the locks and keys were being controlled and maintained as described

in the Plan.

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TABLE OF CONTENTS

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EX EC'UTIVE S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . ii

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TA B LE O F C O NT E NTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

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R E PO RT D ETA I L S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

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Sum m a ry of Pla nt St at u s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . 1

l . O p e r a t i o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . 2

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Co nduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

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01.1 Draining to the Refueling Reference Level

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01.2 Re actor Cavity Seal Leak . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

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01.3 Def ueling Activitie s . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . 4

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Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . . . 7

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O 2.1 Operational Readiness for Defueling (Mode 6) and Core Offload . . . . . . . 7

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Operations Procedures and Documentation

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03.1 Revision of Procedures for Shutdown Operations (eel 9 6-1 1 -01 ) . . . . . ' 12

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Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

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04.1 Reactor Coolant System inventory Diversion (eel 96-11-02)

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04.2 Response to Low Cavity Level Alarm . . . . . . . . . . . . . . . . . . . . . . . . . 15

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Operator Training and Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

05.1 Cavity Seal Lea k Training . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

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05.2 Operator Training on Procedural Revisions . . . . . . . . . . . . . . . . . . . . . 17

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Miscellaneous M atters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

08.1 19 9 6 1N PO Evalu ation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

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11. M a i nt e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

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Conduct of Maintenance

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M1.1. General Comments

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M1.2 Observation of Surveillance Activities (eel 96-11-03)

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Maintenance and Material Condition of Facilities and Equipment

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"B" Residual Heat Removal Pump Repairs Following Overhaul

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M2.2 SFP Service Water System (SWS) Supply Line inspection . . . . . . . . . . 24

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Previous Open items

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M8.1 (Closed) IFl 95-02-03, Followup Refuel Equipment Failures . . . . . . . . . 26

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M8.2 (Closed) URI 96-04-01, Investigation of May 23 Spent Fuel Event . . . . 27

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Table of Contents (cont'd)

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Ill. Engineering

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Conduct of Engineering

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E1.1

Instrumentation Setpoint Control (eel 96-11-04)

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Instrumentation Calibrations (eel 96-11-05) .

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E2

Engineering Support of Facilities and Equipment . . . . . . . . . .

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E2.1

Temporary Spent Fuel Pool Heat Exchanger Cooling . . . . . . . . .

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E2.2 Spent Fuel Pool Cooling Check Valve Replacement . . . .

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E2.3 Inadequate Auxiliary Building Flood Protection (eel 96-11 -06) . . . . . .

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E2.4 Porous Concrete Sub-Foundation

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E2.5 Spent Fuel Pool Cooling System Single Failures (URI 96-11 -07) . . . . . . 40

E2.6 Refueling Boron Concentration

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Quality Assurance in Engineering o .tivities

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Missed Commitments . . . . . .

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Miscellaneous Engineering issues (92902) . . . . .

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(Open) URI 96-01-03: RVLIS Design Basis . .

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E8.2 (Open) URI 96-02-03: Control Room Habitability

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E8.3 (Closed) VIO 94-22-02: AFW Support Loading . . . .

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E8.4 Review of LERs (VIO 96-11-08, eel 96-11-09, eel 96-11-10)

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IV. Plant Support

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Conduct of Security and Safeguards Activities .

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Status of Security Facilities and Equipment

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Protected Area Detection Aids

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Security and Safeguards Staff Training and Qualification

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Security Organization and Administration .

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Quality Assurance in Security and Safeguards Activities . . .

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67.1 Effectiveness of Management Controls

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S7.2 Audits

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Status of Fire Protection Facilities and Equipment . . . . . .

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Fire Protection System Valve Flange Cracks

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V. Management Meetings . . . . .

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Exit Meeting Summary . . . . . . . . . . . . .

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Review of Updated Final Safety Analysis Report (UFSAR)

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REPORT DETAILS

Summarv of Plant Status

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At the start of the inspection period, the plant was in cold shutdown (Mode 5) with the

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reactor and pressurizer vented. The plant was in a recovery mode with activities in

progress to repair or address degraded RHR system deficiencies and thereby restore

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redundancy to the shutdown cooling function prior to proceeding with the vessel

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disassembly and core offload. The reactor operated in Mode 5 and 6, and then entered

operational Mode O when the core was completely offloaded during the period. The

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licensee ceased most outage activities during the September 1,1996 nitrogen intrusion

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event, which were not recommenced.

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The major operational and outage milestones achieved included: repair and restoration to

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service of the B RHR pump on September 25; evaluation of a pin hole leak in the RHR heat-

exchanger inlet valve RHR-V-791 A and obtaining code relief from the Nuclear Regulatory

Commission (NRC) on October 7; completion of items to remove a stop work order placed

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on the plant by the Nuclear Safety Organization (NSO) group and needed to correct

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deficiencies identified by the licensee independent Review Teams root cause evaluation for

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the September 1 nitrogen intrusion event; drained reactor water to the refueling reference

level on October 28; the completion of actions needed to assure readiness to begin

refueling - Mode 6 was entered on October 31; lifting the reactor head on November 6;

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filling the reactor vessel and refueling cavity to 23 feet on November 7; the removal of the

reactor internals on November 11; the completion of actions to address material

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deficiencies in the spent fuel cooling system to assure the spent fuel pool was ready to

receive the fuel from the reactor; the completion of actions needed to assure readiness to

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begin core offload, which began on November 13; and, the removal of all fuel from the

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reactor - the core offload was completed on November 15,1996.

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Oraanizational Chanaes

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Significant organizational changes and developments occurred. A new President and Chief

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Executive Officer for Northeast Utilities was appointed in September and further

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management changes were announced as part of a Recovery Organization for the five NU

nuclear plants. A new Operations Manager was selected, and the plant staff was

reorganized in October to place three Directors at the site in the ares of engineering, work

services and unit operations. The board of directors for the Haddam Neck joint owners

met on October 9 to review the results of the economic analysis, which was not favorable

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for continued plant operation. The owners announced that the permanent shutdown of

Haddam Neck was likely. The licensee essentially halted outage activities except as

necessary to support the core offload. On November 18, the licensee announced plans for

staffing reductions and organizational changes needed to support plant decommissioning.

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The licensee initiated plans to reduce site staffing in stages starting in April 1997 and to

achieve a final decommissioning organization by December 1997. Further decisions

regarding future operations were deferred pending a vote by the board of directors, which

was scheduled for early December 1996.

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On October 23, the NRC announced the creation of the Office of Special Projects that was

effective on November 4. The new organization was established for the oversight of

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activities at Millstone and Haddam Neck. The Director of the Special Projects, Dr. William

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Travers, toured the site on November 5 and met with the senior site management. Dr

Travers was accompanied by Mr. Jacque Durr during the tour.

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Table of Contents (cont'd)

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I. Ooerations

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Conduct of Operations'

Using Inspection Procedure 71707, the inspectors conducted periodic reviews of

plant status and ongoing operations. Operator actions were reviewed during

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periodic plant tours to determine whether operating activities were consistent with

the procedures in effect, including the alarm response procedures.

01.1 Drainina to the Refuelina Reference Level

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Inspection Scoce (71707)

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The purpose of this inspection was to review licensee procedures and observe

licensee controls and management oversight for the draining of the reactor vessel in

preparation for removing the head,

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Observations and Findinas

The licensee prepared a new procedure NOP 2.6-12, Draining the RCS in Mode 5

and 6, for this evolution. The inspector reviewed the procedure for content and

technical adequacy. The procedure provided the operator guidance on the flow

paths to use for draining to the refueling reference level, the required valve lineups,

the limitations on the rate of draining and the use of diverse level indications to

confirm actuallevel, and guidance on monitoring the evolution for unanticipated

conditions.

The inspector observed on October 28 the conduct of the drain down to a level of

about 10 inches below the vessel flange. The crew conducting the evolution had

previously reviewed and practiced the evolution. The pre-job brief was thorough.

The evolution was monitored by the shift mentors and a licensee management

representative. The drain down was completed initially by opening valve PU-V-275

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to divert water to the refueling water storage tank; the evolution was completed by

draining to the waste disposal tank via valve WD-V-210. The operators were very

attentive to the controls and indications during the evolution, and monitored

pressurizer level and the cavity level indication system.

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Conclusions

The drain down was completed without incident, and in a well controlled manner.

Topical headings such as 01, M8, etc., are used in accordance with the NRC

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standardized reactor inspection report outline. Individual reports are not expected to

address all outline topics.

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01.2 Reactor Cavity Seal Leak

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Insoection Scope

The inspecticn scope was to review the licensee's response to a leak in the reactor

cavity seal.

b.

Observations and Findinas

Backaround

in 1988, the licensee installed a new, permanent refuehng cavity seal ring as part of

PDCR 85-781. The seat is a solid ring that bridges the space from the cavity floor

to the reactor vessel flange. The seal ring incorporates a flexible metal membrane

which is part of the annulus seal, and provides for relative displacement of the

reactor vessel and the reactor cavity during plant operations. The primary seal is

attached at both the reactor and cavity ends by all welded joints. A secondary type

sealis installed as a backup to the flexible membrane, which limits the possible flow

area should the primary barrier fail. The seat ring also has four hinged hatches,

which are open during normal operations, and closed for refueling. The hatches are

the only non-welded gasketed joints in the seal. Each hatch is sealed by a set of

double gaskets made of an elastomer material; each gasket is mounted in a separate

groove on the edge of the hatchway. The hatches have provisions for leak testing

with air and were tested to assure proper seal at the start of this refueling. Finally,

a catch basin with tell-tale drain is mounted below the entire seal arrangement to

allow monitoring from the welded and gasketed joints. The leak detection system

collects leakage from the north (loop 1/2) and south (loop 3/4) halves of the seal

plate.

Rak Event

The licensee finished preparations to fill the reactor cavity as part of the core

offload sequence. The reactor head was lifted and stored at about 3:00 a.m. on

November 5, and the licensee began to transfer water from the refueling water

storage tank starting at 4:43 a.m. The intention was to fill the cavity to the

refueling level with at least 23 feet of water above the top of the core,

corresponding to a level of about 560 inches on the cavity level indication system

(CLIS).

The operators stopped the cavity fill with the level at 479 inches at 9:50 a.m. on

November 6 when excessive leakage was identified from the cavity sealleakoff tell

tale drain. The acceptable leak rate limit to support fuel movement established by

the Westinghouse refueling procedure was 200 drops per minute, or 16 ml/ min.

The measured leak rate varied slightly, but was about 10' times the allowable limit at

200 to 250 ml/ min (or about 4 gallons per hour). The leakage stabilized at about

160 ml/ min on November 5. The core offload was delayed starting on November 5

as the cavity leak was investigated and evaluated. On November 6, after

concluding that the safety benefits outweighed possible negative safety

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Table of Contents (cont'd)

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implications, the licensee continued the cavity fill to the 23 ft level. The leakage

increased slightly to 180 ml/ min at that time.

The licensee's engineering evaluated the leakage with the assistance from

Westinghouse (the seal designer) and maintenance. Divers were used to complete

an air leak test of the hatches. Although all four hatches showed acceptable

leakage, the results were deemed ambiguous due to the possibility that the

underwater test did not check the entire sealing surface. The licensee completed

and approved technical and safety evaluations, which concluded that the most

probable source of the leak was from the gasketed hatch joints, and that

catastrophic failure was highly improbable. The technical evaluation considered the

ruggedness of the seal ring design, the expected stresses on the welded joints from

refueling and normal operations, as well as from design basis events, such as

earthquake and fuel drop loads. A new leakage limit of 2 liters / min was

established, corresponding to a flow area of 0.004 square inches, which was not

considered significant for weld failure.

Procedure guidance was provided to define operator periodic monitoring of the leak

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rate, as well as expected actions if limits or total leakage or rate of increase were

exceeded. The operators monitored the leakage from the tell tale drain using a

closed circuit television camera with readout in the control room; the leak rate was

trended. The operators also measured leakage as needed depending on leakage

trends. The licensee recommenced the defueling sequence with the removal of the

vessel internal package at 12:22 a.m. on November 11. The cavity seal leak rate

slowly and monotonically decreased and became very small (10 ml/ min) by the time

core offload was completed.

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Conclusions

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Licensee actions to evaluate the cavity sealleakage were acceptable, with good

support provided by engineering and maintenance.

01.3 Defuelina Activities

a.

Inspection Scope

During the week of November 11,1996, the residera inspector staff with the

assistance of one region based NRC inspector, conducted a performance-based

inspection of the Haddam Neck's defueling operations using NRC Inspection

Procedure 60710, " Refueling Activities."

The purpose of this inspection was to evaluate the effectiveness of the licensee's

defueling activities. The inspection consisted of observations of defueling activities

in containment, in the spent fuel pool, and in the control room, and to independently

verify adherence to various procedural and technical specification requirements.

The inspectors reviewed the training material and content provided to licensee

operators and contractors hired to perform defueling activities.

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b.

Observations and Findinas

The inspectors observed approximately 60% of the fuel transfer activities between

November 11 through November 15,1996. The inspectors noted good

communications between the control room, opender operator in containment,

upender operator in the spent fuel pool, and manipulator crane operator in

containment. The upender operator in containment conscientiously performed his

)

duties using good communication skills and maintained the refueling log up-to-date.

'

The refueling senior reactor operators (SROs) maintained good management

oversight and professional demeanor.

,

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The inspectors obe mad personnel operate the manipulator crane safely and used

good communications throughout the operations. They were observed to

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communicate well with the refueling SRO, the refueling engineer and the health

'

physics technicians. For example, late Wednesday (November 13,1996) day shift

i

problems were experienced grappling the second fuel cell on the west side of the

vessel, Apparently, the cell was slightly bowed and didn't allow grappling using the

ncrmal indexing methods. The bridge operators proceeded cautiously to manually

position the bridge several times. The refueling engineer and the bridge supervisor

were present and deliberated with the refueling SRO on various alternatives. The

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dayshift bridge personnel suggested rotating the refueling mast to achieve alignment

i

but the refueling procedures did not specifically allow or prohibit this action

j

although the contractors considered this an acceptable practice. The evening bridge

crew arrived within a half an hour after the problem occurred and suggested moving

the mast cable to achieve alignment with the fuel cell. This was allowed in the

refueling vendor procedure (VP)-798, FP-CYW-R19 Refueling Procedure. Operators

moved the mast cable and successfully grappled the fuel cell.

On November 12,1996, the inspectors observed appropriate control by the

refueling SRO as the manipulator crane operator bypassed crane limit switches. The

limits switches were bypassed during the refueling equipment checks and during the

emergency procedure exercise. Both activities were accomplished with the

manipulator mast grappled to the " dummy" fuel assembly. The inspectors observed

that no other request to bypass any of the trolley, bridge, or hoist limit switches

occurred during fuel movement.

The licensee adhered to various procedural and technical specification requirements,

based on direct inspector observations in the control room, the spent fuel building

,

and in the containment. The inspectors verified the following requirements;

minimum reactor cavity level, minimum spent fuel pool level, source range nuclear

,

,

!

instrumentation operability and audible count indication, establishment of

communications, residual heat removal operability and minimum flowrate,

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equipment tag-outs for the reactor coolant pumps and the refueling canal drain

i

piping valves. The equipment was in its proper operation and requirements were

adhered to. The health physics coverage and foreign material controls were

effective. The foreign material control was maintained as specified in WCM 2.2-5

and the log was maintained up-to-date. The refueling prerequisites, precautions and

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6

surveillance requirements were completed as specified in NOP 2.3-5, Refueling

i

Operations.

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On November 13,1996, the inspectors walked down the containment purge system

using licensee normal operating procedure (NOP) 2.13-2, " Reactor Containment

'

Atmospheric Control System, attachment 7.1." The inspector's walkdown of the

ventilation alignment concluded that the dampers were correctly aligned for

containment purge, radiation monitors were operable to measure release rates, and

that the flowrate from the purge fans were within the release permit. The inspector

walked down the spent fuel cooling system to verify it was aligned as specified in

NOP 2.10-1.

On November 14,1996 the inspectors compared NOP 2.13-5A, " Tracking and

Establishing Modified Containm.-it Integrity and Containment Closure," with tag

clearance 96-1004. The purpose of the comparison was to validate containment

closure was established during core alterations. The inspector noted no

discrepancies between the completed NOP 2.13-5A and tag clearance 96-1004.

The inspector verified approximately 40% of the tags were properly hung on the

'

components identified in tag clearance 96-1004.

The training records were reviewed for the training conducted to licensed operators

and contractors who were hired by the licensee to perform refueling activities. The.

inspector reviewed the lesson plans, attendance records, and the job performance

1

measures used in the training. The inspector concluded that the records and

training material content were acceptable. The inspector noted that the licensee did

not have a training program description and implementing procedure for conducting

j

refueling operations and fuel movements that outlined management's expectations

for the training of licensed operators and contractor personnel.

Throughout the core offload, the inspector verified that fuel movement was

completed in accordance with the sequence specified in the Fuel Handling Data

Sheets of FP-CYW-R19. The inspector confirmed that the fuel stored in the pool

met the burnup requirements of Technical Specification 4.9.14, based on the

completion of SUR 5.3-54 and the independent confirmation of fuel assembly

burnup data. The licensee maintained the fuel movement status boards during the

core offload. The inspector verified by a sampling review that the status board was

accurate and reflected the finallocation of special nuclear materialin the spent fuel

pool.

c.

Conclusions

The defueling operations observed were safely conducted utilizing good teamwyk

and communications between allinvolved. The refueling SROs maintained gooo

management oversight and professional demeanor. Technical specification

requirements and procedural controls reviewed were acceptably implemented and

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adhered to. The training records and training material content were acceptable.

i

The inspector noted that licensee did not have a training program descriptio1 and

i

implementing procedure for conducting refueling operations and fuel movements

.

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Table of Contents (cont'd)

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that outlined management's expectations for the training of licensed operators and

,

contractor personnel.

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02

Operational Status of Facilities and Equipment

O2.1 Operational Readiness for Defuelino (Mode 6) and Core Offload

a.

Insoection Scope

!

The inspection scope was to review the licensee actions to recover from the

j

nitrogen intrusion event and to assure the plant was ready to complete the core

'

offload,

b.

Observations and Findinos

,

'f

Following a nitrogen intrusion event in September,1996, the licensee initiated a'

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series of broad actions to recover from the event and to assure the plant was ready

l

to enter Mode 6 and to begin core offload. The licensee action plan established the

l

following criteria which had to be satisfied prior to proceeding to core offload: (i)

l

both RHR trains were available for service, including the securing of regulatory relief

as needed; (ii) the completion of an independent review team (IRT) to investigate

and determine the root cause of the major events that challenged reactor safety

!

,

margins; and, (iii) the completion of appropriate corrective actions identified from

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the IRT as related to the initiation of core offload. The action plan was

!

subsequently expanded to include the findings and weaknesses noted in NRC

!

Inspection 50-213/96-80, and the recommendations from the Nuclear Safety and

!

Oversight (NSO) group, as described below. The licensee requested the NU Safety

Analysis Branch to complete an analysis of the nitrogen intrusion event to assess

!

the adequacy of the available compensatory measures and the potential plant

vulnerabilities.

>

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The NSO provided recommendations to line management regarding actions that

i

should be taken to address performance issues prior to proceeding to reactor

disassembly and core offload. The recommendations were included in memoranda

,

dated September 20 (CT-NCO-96-004) and September 25 (CY-NSO-96-004 Rev 1),

1

and included the results of the Independent Review Team investigation and the

common cause analyses. The recommendations covered the following ',tems:

restore both RHR trains to an operable status; review plant systems r.eeded for core

j

offload to provide confidence that systems will function as intended; review the

l

systems needed for Mode 6 to verify that deficiencies are resolved or will not

!

degrade system performance; continue the stop work order in effect to protect key

safety functions as the RHR deficiencies were addressed; improve the quality of pre-

.

job briefs; improve the control of outage activities to reduce shutdown risk; increase

{

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management coverage of key activities; review and improve operating and

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maintenance procedures associated with reactor disassembly and core offload;

i

assure the level of controls for reduced inventory conditions are appropriate and

i

increase operator sensitivity to single barrier configurations; address deficiencies in

!

reactor vessel vent and levelindications for Mode 5 operations; and address

i

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Table of Contents (cont'd)

8

management expectations for operators to seek outside assistance when

unexpected results are encountered.

The inspector reviewed the activities by the line and NSO organizations to develop

,

and implement the action plans to address the issues summarized above. The

-

licensee divided the corrective actions into a Mode 6 and Core Offload Checklists,

and assigned responsibility to the operations, maintenance, work control, and

engineering groups as needed to implement the plan. The inspector monitored the

completion of the activities and selected certain actions for independent review and

followup. The inspector also attended meetings by the plant operations review

committee convened on September 30, October 7,18,24,28,31 and November 7

'

to review the status and completion the actions needed proceed with the offload.

The licensee plan addressed the items discussed above as well as other actions

necessary to assure operational readiness for refueling. The inspector reviewed the

completion of the action plan on a sampling basis. The actions are described

below, and were summarized (in part) in a letter to the NRC dated October 23,

1996 (B15938).

(1)

Safety Analvsis Assessment

The NUSCo Safety Analysis Branch provided the results of its assessment of the

September 1 nitrogen intrusion event in a memorandum dated September 25,1996

(NE-96-SAB-240). The assessment included three aspects of the event: the

adequacy of procedure Abnormal Operating Procedure (AOP) 3.2-12, the potential

scenarios that could have occurred had other barriers to adequate core cooling

failed; and, a simulation of the event using the RELAP5/ MOD 3 computer model to

provide a best estimate of the lowest level reached in the reactor.

Based on an estimated nitrogen in leakage rate of 4 cubic feet per minute, the

licensee calculated that about 5000 to 6300 gallons of RCS water was displaced

during the nitrogen intrusion event, and the minimum reactor vessel water level was

between 31 and 62 inches above the top of the hot leg. The guidance provided to

the operators in AOP 3.2-12 would have allowed the operators to successfully

mitigate the event had the level decrease continued. This outcome was assured

even if the RHR and charging pumps had become air bound. Although core boiling

would have occurred, the core would have remained cool through reflux boiling, or

natural circulation cooling, until the operators restored forced cooling using an RHR

or charging pump. The licensee concluded that the margins to core safety were

significantly reduced during the event, and a number of potential conditions which

could have lead to core damage were identified had additional degradations

occurred. The probability of those outcomes were not quantified due to the

absence of the conditions during the event, the lack of quantitative data, and the

!

operator awareness of degraded conditions starting on September 1,1996.

Although the safety significance of the nitrogen intrusion event was high, there

were no actual adverse safety consequences for the plant, plant personnel or the

public health and safety.

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9

(2)

fare Coolina System Redundancy

The licensee completed repairs to the "B" RHR pump on September 25,1996 and

characterized the defect in the "A" RHR heat exchanger inlet valve, RHR-V791 A.

The "B" pump failed due to a combination of original manufacturing defects and a

marginal design in the tolerances of internal components in the rotating element.

Licensee actions this period addressed those deficiencies on the "B" pump, as well

as leakage from the stationary oil baffle ring on September 23. Since some of the

same tolerance deficiencies had been corrected on the "A" RHR pump, the licensee

concluded that the "A" RHR pump was reliable for core offload and deferred

additional work identified as lessons learned from the "B" pump f ailure until after

core offload. The RHR system had two operable pumps as of September 25.

Non-destructive examination of the defect on valve RHR-V791 A was completed on

September 20 after a radiographic source was lowered into the RHR pit. The

licensee's engineering evaluation was that the structural integrity of the valve was

not affected by the highly localized through-wall defect, there was no gross wall

thinning, and large flaws exceeding the structural limits of ASME Section XI IWC-

3000 were likely not present. The licensee submitted a request for relief from the

requirements of ASME code Section XI IWC-3000 to allow declaring the valve

operable, but degraded with the through-wall defect. The NRC granted the code

relief on October 7,1996. The licensee continued to monitor leakage from the

valve using the operators during normal rounds to the RHR pit, as supplemented by

the installation of video equipment with continuous readout in the control room,

i

The licensee established criteria to reclose the valve should leakage exceed set

limits. RHR-V791 A was opened and both trains of RHR were fully operable on

October 7,1996.

(3)

Refuelina Seouence

Based on an analysis of the September 1 nitrogen bubble event, the licensee

recognized that the refueling sequence defined in Refueling Procedure FP-CYW-R19

J

contained windows of vulnerability where indications of core temperature and

vessel level were reduced for periods that were unnecessarily long. The refueling

sequences was reviewed and revised to optimize availability of levelindication for

operators. Specifically, as described in Temporary Procedure Change TPC 96-648,

Section 7.1.2 was changed to move the action of disconnecting the temporary core

thermocouple and reactor vessellevelinstrumentation closer to just before the head

lift sequence, so as to keep vessel level information available to the operators as

long a possible.

(4)

Procedure Uoarade and Operator Trainina

in response to the September 1 event, the licensee established an operation's

procedure grotp to address deficiencies within infrequently used shutdown

procedures. The group consisted of four senior reactor operators, two reactors.

operators, support from system engineers, and one outside contractor. The licensee

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Table of Contents (cont'd)

10

revised in excess of twenty-four (24) procedures concerning shutdown operations.

I

The type of procedures involved included operations department instructions,

normal operating procedures, annunciator procedures, abnormal operating

procedures, and work control manual procedures. Attachment A of this report lists

the revised procedures that were reviewed by the inspector Major changes

included: operator logging of all reactor coolant system inventory changes, guidance

'

on when pre-evolution briefings should occur, various methods to make-up to the

reactor coolant system, awareness of shutdown risk, annunciator actions in

response to high/ low cavity level alarms, methods of adding make-up to the reactor

coolant system during a postulated cavity leak or reactor coolant leak, and

additional requirements for operator log entries. The above procedures were

prepared in October,1996. The level of detail and quality of the procedures

improved from prior to September 1,1996. Operator training on the revised

procedures was observed by the inspector, as documented in report detail 05.2.

(5)

System Readiness Reviews

The system engineers conducted reviews of systems needed to support operation in

Mode 6 to assure the plant was ready for core offload. The reviews included a

walkdown of the systems and a review of outstanding trouble and deficiency

reports to assure items impacting system operation were addressed. The purpose

of the review was to assure that no significant material conditions existed that

'would affect the safe conduct of core offload.

The licensee identified and corrected several items in the spent fuel pool cooling

system, as described in section (6) below. Several other significant deficiencies

were identified and corrected, including problems in the boric acid heat trace system

)

(see LER 96-27 and Section E8.4 below) and inadequate spent fuel building

)

ventilation (see LER 96-25 and Section M1.2 below). The licensee also addressed

l

the uncertainty calculation for instrument loops needed in Mode 6 and the condition

of the refueling equipment. Several material condition deficiencies were identified

regarding leaky valves in the CVCS system. The licensee elected to continue to use

administrative means to address the valve leakage, and to defer maintenance to

address valve leakage until after the core was offloaded. The deferral of the valve

work was deemed necessary to minimize the time in a higher risk condition (by

offloading the core), and then conduct the valve work with the reactor defueled.

(6)

Spent Fuel Pool Material Deficiencies

Several actions were taken to address deficient material conditions in the spent fuel

pool (SFP) cooling system. The areas addressed by the licensee prior to core

offload included: replacement of the check valves on the discharge of the SFP

cooling pumps; replacement of both SFP cooling pump motor breakers due to

potential hot spots; identification and repair of a linear indication on the service

water (SW) supply piping to the SFP heat exchangers; the inspection and repair as

necessary of pipe support attachments welded to the SW pipes, starting from the

intake structure up to the SFP heat exchangers; inspection and repair of degraded

welds on the SW supply and return piping at the SFP heat exchangers; inspection

.

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Table of Contents (cont'd)

11

and cleaning of valve SW-MOV-837A to assure it was leak tight; and, the

replacement of valve SW-239 on the Adams filter supply to the SFP heat

exchanger, after the valve disc was found separated from the stem. See Section

M2.2 for further NRC review of this area.

(7)

Operations Performance

The licensee took several actions to correct deficiencies in operations performance,

as characterized by low stanurds in procedure use and adequacy, a lack of a

questioning attitude ano inadequate pre-j( . briefs. The action included: the

appointment of a new Operatio,s Manager; the issuance of several new and or

revised procedures; and, the promulgation of an increased emphasis on

management standards and expectation:, through revised procedures and

management meetings with plant workers. A new department instruction was

prepared for pre-evolution briefings, which provided a detailed checkoff of the items

to be covered during a briefing. The department instruction for " conduct of

'

operations (ODI-1)" was revised to emphasize expectations regarding the need for a

questioning attitude, and the expectation that assistance from outside the duty shift

crew be obtained when offnormal conditions exist.

The licensee also issued revised department instructions for monitoring RCS

inventory in Modes 5 and 6 (ODI 190). Finally, the licensee increased management

oversight and control of outage activities by revising WCM 1.2-9 to require that

significant delays and work stoppages be processed as an outage schedule change.

The schedule changes would be reviewed for impact on shutdown risk and would

be approved by the Unit Director.

(8)

Manaaement Oversiaht

f

The licensee took steps to better define management expectations to the work force

in a series of memoranda and meetings. In particular, management expectations

regarding several station activities were defined in a memorandum form the Unit

Director dated October 7,1996, covering the following topics: the conduct of

physical work, work planning, pre-job briefs, supervisory oversight, job

completeness, feedback of lessons learned, and stopping work when help is

needed. The licensee increased the presence of upper management onsite during

back shift hours and for the following key activities: drain down to the refueling

reference level, lift of the reactor head, filling the reactor cavity, removing the upper

internals, and starting core offload. The back shift coverage was provided by the

Operationa Manager, the Work Services Director and the Unit Director. The licensee

also assigned mentors to each operating shift to monitor for compliance with the

new standard for the conduct of operations. The shift mentors were experienced

operations personnel from other nuclear plants. The mentors were on shift from the

start of the vessel drain down to the completion of the core offload.

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(9)

Awareness of Shutdown Risk

The licensee issued a revised department instructions for monitoring shutdown risk

(ODI 191). The purpose of ODI 191 was to promulgate expectations and to

increase operator awareness of five key safety functions, procedural controls and

operational philosophies designed to minimize shutdown risk.

The inspector noted that the implementation of the above measures had mixed

success. Despite the renewed emphasis on monitoring key functions and shutdown

risk, an event occurred on November 2 while the vessel was drained to the refueling

reference levelin which work on the critical path for defueling was interrupted for

about 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> following a personnel contarnination event inside the containment.

The delays occurred at the time of high shutdown risk, and were not fully

appreciated nor investigated by plant personnel, and were not communicated to

upper management in a timely manner. Plant operators and other outage personnel

demonstrated a poor sensitivity to the time spent in a high risk condition. This

matter is addressed further in Inspection 96-12.

c.

Conclusions

Licensee actions were generally thorough to recover from the nitrogen intrusion

event, restore redundar.cy to core cooling functions and to assure the facility and

a'

plant staff were ready to enter Mode 6 and complete the core offload sequence.

Corrective actions to address plant material conditions and plant staff performance

deficiencies were appropriate. Subsequent routine inspections will review the

adequacy of licensee actions to improve worker performance and minimize

shutdown risk.

O3

Operations Procedures and Documentation

O 3.1 Revision of Procedures fo Shutdown Operations (eel 96-11-01)

a.

Inspection Scope

The inspection scope was to evaluate the completeness of procedure changes that

addressed deficiencies in procedures used for shutdown operations. The

deficiencies involved:

improper use of an administrative control procedure (ACP) 1.2-5.3,

Evaluations of Activities / Evolutions Not Controlled by Procedure, to vent the

charging system and drain the reactor coolant system

lack of guidance on preserving reactor coolant loop overpressure protection

when isolated

identification of station nitrogen usage

Additionally, the inspector reviewed the quality of procedural changes.

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13

b.

Observations and Findinas

in response to the events in early September,1996, the licensee established an

operation's procedure group to address deficiencies with infrequently used

shutdown procedures. The group consisted of four senior reactor operators, two

reactors operators, support from system engineers, and one outside contractor.

The inspector verified that the licensee deleted the use of ACP 1.2-5.3 on October

23,1996. The licensee developed and approved two NOPs that were previously

developed using the guidance of ACP 1,2-5.3. The two procedures were NOP 2.6-

12, " Draining the Reactor Coolant System in Modes 5 and 6" and NOP 2.6-98,

" Recirculation of 18 Charging Pump on the Refueling Water Storage Tank." The

procedures provided adequate detail and guidance to accomplish their intended

objective.

The licensee implemented procedural enhancement in NOP 2.6-12, " Draining the

Reactor Coolant System (RCS) in Modes 5 and 6" and NOP 2.4-7, " Return of a

Loop to Service with the Plant Shutdown," to provided guidance during a draindown

to preserve loop overpressure protection (isolated RCS loop) with the drain header

aligned to the loop and placing the drain header relief valve in-service.

Operations Department instruction (ODI)-190, RCS Inventory in Modes 5 and 6,

required operators to log on a shiftly basis station nitrogen use, and to make

management aware of an unexpected change in its trend. The licensee revised an

additional twenty-four (24) procedures concerning shutdown operations. The type

of procedures involved included operations department instructions, normal

operating procedures, annunciator procedures, abnormal operating procedures, and

work control manual procedures. Attachment A to this report lists the procedures

that were reviewed by the inspector.

The licensee identified during the procedural upgrades that no procedural guidance

existed for a fuel handling accident. On October 24,1996, the licensee approved

AOP 3.2-63, " Fuel Handling Accident." Failure to ha've a procedure providing

guidance during a postulated fuel handling accident is a violation of technical specification (TS) 6.8.1. TS 6.8.1 requires that written procedures shall be

established and maintained covering the applicable procedures recommended in

Appendix A of Regulatory Guide 1.33, Revision 2, (February,1978). Regulatory

Guide 1.33 Appendix A item 6.X lists procedures for irradiated fuel damage while

refueling. This is an apparent violation (eel 96 11-01). The lack of procedural

guidance is significant in that this event is analyzed in the Updated Final Safety

Analysis Report, and emergency declarations are based upon a dropped assembly.

The inspector noted that the licensee experienced a dropped fuel assembly on

February 26,1986. The licensee corrective actions were to improve the foreign

material exclusion procedures since the apparent cause was a foreign object.

Specifically, a foreign object caused the fuel alignment pin to be bent resulting in

the fuel assernbly coming up with the vessel's upper internal package. No

corrective actions addressed procedural guidance to mitigate a dropped fuel

assembly.

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c.

Conclusions

The upgrade of various operating procedures was appropriate. The inspector noted

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improved detail and quality in the procedures revised when compared to the quality

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of procedures prior to September 1,1996. A v'sation of TS 6.8.1 was identified

'

whereas the licensee did not have a procedure for fuel handlinC accident as

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recommended in Regulatory Guide 1.33.

!

04

Operator Knowledge and Performance

04.1 Reactor Coolant System Inventorv Diversion (eel 96-11-02)

i

a.

Insoection Scone

The inspector evaluated operator performance during a makeup to the refueling

water storage tank (RWST) on September 26,1996. Operators initiated a makeup

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of approximately 15,020 gallons to the RWST using the guidance in NOP 2.6-3,

" Blended Makeup to RWST." The purpose of the RWST makeup was to prepare to

l

fill the reactor cavity. The RWST is the primary source of borated water for the

reactor cavity.

b.

Observations and Findinas

On September 26,1996, during a makeup to the RWST, operators noted a

diversion of approximately 600 gallons or 4% of the total makeup inadvertently sent

into the rsector coolant system (RCS). The apparent cause was leak-by through a

shut manual valve (BA-V-367). Valve BA-V-367 is a 2 inch manual globe valve in

the piping system between the recycled pure water storage tank (RPWST) and the

suction of the charging pumps. In order to have the makeup water enter into the

RCS, BA-V-367 and charging flow control valve CH-FCV-110 needed to leak by.

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Procedure NOP 2.6-3 6.1.1 required a valve lineup be performed if the dilution

!

water supply is aligned from the RPWST. The operators did not perform this step,

yet the dilution water supply was from the RPWST. This valve alignment would

have verified that BA-V-367 was closed.

The operators did not aggressively pursue a decrease in RCS boron from 2305 part

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per million (ppm) to 2288 ppm after the makeup to the RWST. Operators requested

l

a second boron sample from chemistry; however, they did not identify the source of

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the diverted water. The potential existed for pure water to be in the charging

system that was credited as the emergency boration flowpath. On October 1,

1996, the licensee sampled the flow paths. The boron concentration was between

1817 and 1825 ppm less that the RCS, which confirmed the existence of a dilution

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into the RCS. The boron concentration was still greater than the required shutdown

,

margin concentration of approximately 850 ppm.

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The inspector reviewed the maintenance history for valve BA-V-367. The valve

3

was not subjected to any routine preventive maintenance activity, and the only

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recorded corrective maintenance activity was performed in 1989 (Authorized Work

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Order 89-10487) to adjust the valve packing due to leakage,

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Prior to this event, five adverse condition reports (ACRs) were prepared in

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September,1996, identifying various chemical and volume control system valve

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leakage. On September 3,1996, a similar event occurred whereas operators

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suspected that a boric acid flow control valve (BA FCV-112C) was leaking through

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to the charging header during a makeup to the RWST. The difference between the

4

two events was the makeup flowpath, and that operators secured from the makeup

,

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on September 3,1996, when they noted an unexpected rise in pressurizer level of

1 %. Additionally, on September 18,1996 the licensee documented in ACR 96-

.

1062 that boric acid and pure water valves were not designed as zero leakage thus

!

creating the possibility of dilutions into the RCS. The inspector concluded that

]

based upon the recent events, licensee corrective actions to preclude the event on

<

September 26,1996 were ineffective in that compensatory measures to preclude

.

unintended leakage into the RCS were not taken. Each of the corrective actions

proposed from the five related ACRs were to trouble report the suspected leaking

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valve, and schedule future repairs. This is considered a violation of 10 CFR 50

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Appendix B criterion XVI (eel 96-11-02).

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c.

Lonclusions

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The Q:ensee corrective actions in response to recent valves that leak-by in the boric

,

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acid at:d pure water systems were ineffective in preventing the event on September

!

i

26,1959. Operations personnel did not aggressively respond to either terminating

l

j

the make up to the RWST with known RCS inventory changes, or the potential of

,

having diluted water in the credited emergency boration flowpath. Operators did

j

,

l

not adhere to the NOP 2.6-3 that would have required a valve alignment check of

'

valve BA-V-367. No preventive maintenance program existed for the valve (BA-V-

<

.

367) that was suspected of leaking-by.

04.2 Resoonse to Low Cavity Level Alarm

-

)

!

1

a.

Inspection Scoce

i

,

t

The inspection scope was to observe and evaluate operator actions in response to a

low cavity level alarm on October 24,1996.

,

!

f

b.

Observations and Findinas

{

On October 24,1996, the inspector observed operator actions in response to a

j

slow decrease in RCS inventory (pressurizer level decrease of 1 %) over

j

approximately 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The inventory reduction was confirmed by a reactor

cavity low level alarm. The operator quantified the rate of inventory decrease at

,

approximately 0.44 gallons per minute (gpm), and implemented the applicable

procedures; AOP 3.2-31 A," Reactor Coolant Systern/ Refueling Cavity Leak (Modes

5 and 6)," and Annunciator Procedure (ANN) 4.24-2, " Cavity Low Level." The

operators did not identify any leakage from the RCS, or the RHR system. At the

---

-

.-.

- -

--

-

- . - - . . - - - . - - - - - - - - -

-- - -

.

_~.

.

- - -

j

,

.

.

.

e

,

,

l

'

l

j

Table of Contents (cont'd)

16

~

'

time of RCS inventory reduction, the operators noted an increase in the aerated

drains tank level. Conversations between operations personnel and the on-shift

chemistry technician concluded that two RHR boron samples were drawn at the

start and the end of the RCS inventory reduction. The first sample at approximately

'

8:00 a.m., equated to the start of the decrease in reactor coolant system inventory.

A second sample taken at approximately 11:30 a.m., at the end of the reduction in

j

RCS inventory. The operators attributed the decrease to a RHR sample valve that

'

was leaking by from the RHR system into the aerated drains tank. The valve was

trouble reported.

l

c.

Conclusions

i

!

On October 24,1996, the operator.s noted RCS inventory changes and implemented

]

the applicable procedures,

j

05

Operator Training and Qualification

>

!

05.0 Cavity Seal Leak Trainina

i

I

1

a.

inSDection Scope

,

,

On November 12,1996, the inspector observed the refueling crane operators

perform exercises involving emergency operating procedure (EOP) 3.1-48, " Loss of

'

Refueling Cavity Inventory." The inspection scope was to evaluate cperator

adherence to the EOP action steps, and to verify that the actions were

accomplished within the acceptance criteria,

b.

Observations and Findinas

i

The contractor refueling crane operators displayed adequate knowledge of the

procedure and its implementation. The operators adhered to the applicable steps

within EOP 3.1-48 Attachments A and B for both the manipulator crane operator

and the upender operator. The scenario was to take a mock fuel assembly from

above the core to its safe location within the fuel transfer canal, place the transfer

cart into containment, close the spent fuel pool sluice gate, and simulate closing the-

manual transfer canal valve inside containment.

The evolution was timed to verify that the required actions could be taken in less

time than assumed in the analysis for the time it would take to drain the cavity in

the event of a seal failure. The licensee had shown that the cavity could drain in

about 20 minutes based on past operating events at Haddam Neck, with a seal

design more vulnerable than the existing seal. The acceptance criteria for EOP 3.1-

48 was established at half that time, or 10 minutes.

During establishment of initial conditions, the inspector observed that one of the

manipulator crane operators lowered the mock fuel assembly on top of the core,

whereas the initial condition for the exercise stated within two feet from the top of

the core, in discussions with the operator, the inspector learned that he was not

,

-

.

_.

-

-

-

__

.

-_

- _ -

_ _

. -

_ _ _ _

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

_ _ _ _ _

. ,

.

.

.

-

t

.

f

f

!

1

Table of Contents (cont'd)

17

!

i

familiar with the top of core location on the Z-Z tape (vertical orientation). The

i

refueling SRO was notified by the inspector and the manipulator crane operator

raised the assembly above the core. The inspector confirmed that the Z-Z tape was

l

appropriately marked for the top of core as part of the final manipulator crane

!

checkouts. The final crane checkouts occurred after the training exercise. No

l

adverse consequence was observed during this evolution.

}

l

The completion of the training was verified as being appropriately documented in

l

vendor procedure (VP)-798, FP-CYW-R19 Refueling Procedure.

'

c.

Conclusions

l

The EOP exercise on a postulated cavity sealleak was successfully implemented by

l

'

the refueling crane operators.

i

05.2 Operator Trainina on Procedural Revisions

!

r

a.

Inspection Scope

j

The scope of the inspection was to observe and evaluate the quality of classroom

i

training provided to operators. The training was on the procedural changes used

,

.

during a shutdown condition.

>

'

l

b.

Observations and Findinas

i

The inspector attended operator training on September 27,1996 for the rt.3:: tor

l

cavity level indication system (CLIS), and on October 22,1996 for the significant

l

changes to the operations procedures for shutdown operations.

l

The training provided to the operators on the CLIS focused on indicator limitations

and system errors in response to excessive RCS gas flowrates. The training also

identified the purpose of vacuum compensation, and the lesson-learned during the

ingress of nitrogen into the RCS in late August,1996.

The training on October 22,1996 provided an overview of sixteen (16) new or

j

significantly revised procedures, accomplished an "in-plant" job performance

measure to align the purification system for RCS makeup, and simulated a pre-

l

evolution briefing on RCS draindown. At the closure of the training, a written exam

j

was provided to operators. The training duration was approximately eight hours.

The trainer provided a copy of each procedure, went over the basis for each of the

'

prerequicites and precautions for the new procedures, and provided the basis for

each procedure step change. During the classroom instruction, exercises were

l

performed to classify the emergency level for a dropped fuel assembly, and to

calculate the expected volumes of inventory during either draindown or makeup to

the RCS.

The operations manager and training instructor provided a critique on the operations

4

crew pre-evolution briefing for a RCS draindown from 50% pressurizer level to

j

,

(

.,

.--

-

-

- -

-__ - - . - . -

- - _-_.

..

.- .-

. _ . . -- -

-

-

.

.

.

.

l

Table of Contents (cont'd)

18

eleven inches below the reactor vessel flange. The critique of the bricfing focused

on the need for communication repeat backs, improvements for the unit supervisor

(US) to state all procedure prerequisite steps, and the need to request engineering

support for contingency actions.

c.

' Conclusions

.

The training to operators appropriately focused on the details and purpose for the

significant changes to operations shutdown procedures.

08

Miscellaneous Matters

08.1 1996 INPO Evaluation

l

The last evaluation by the Institute of Nuclear Power Operations (INPO) was

performed in May,1996, and the report was issued in September and made

available for NRC review on October 3,1996. In overview, the assessment found

several notable practices and accomplishments, including a high level of pride in the

plant, strong plant focus of the station work groups that resulted in good teamwork,

effective valve maintenance, a concerted effort to upgrade equipment in the areas

of control rod position indication and radiation monitoring, the use of nonintrusive

acoustic testing.

i

Several areas for improvement were also noted, such as: precursors to reactivity

control events, maintenance conducted outside the AWO job scope, engineering

evaluations that are not thorough, a need to be more aggressive in ALARA, and,

ineffective use of operating experience, work observations, self-assessments and

risk assessment tools. The inspector noted that the INPO findings did not identify

any safety significant findings not already known to the NRC.

II. Maintenance

M1

Conduct of Maintenance

,

i

1

M1.1 General Comments

a.

inspection Scone (62703)

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

e

AWO 96-7718

Cavity Seal Hatch Leak Test

e

AWO 96-6787

RHR-V791 A Nondestructive Examination

e

AWO 96-7552

B RHR Pump Thrust End Stationary Oil Baffle

i

e

AWO 96-8734

Ultrasonic Service Water Flow Measurements on the

I

i

Spent Fuel Pool Return Header

!

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.

<

.

l

19

l

AWO 96-8540

SFP Cooling Piping Repair

AWO 96-9229

Reactor Cavity Seal Leak

b.

Observations and Findinas

The above maintenance activities were adequately implemented. Except as

discussed in Section M2 below, the inspector had no further comments in this area.

M 1.2 Observation of Surveillance Activities (eel 96-11-03)

a.

Inspection Scope

The inspectors observed the following surveillance activities:

,

1

1

SUR 5.1-159B

Boron Injection Flowpath Verification and

Metering Pump Test

SUR 5.7-162

In-Place Testing of the Spent Fuel Building Filters

Special Test 11.7-200

Underwater Reactor Cavity Hatch Seal

Troubleshooting

SUR 5.3-54

Burnup Requirements for Spent Fuel Pool

Storage

SUR 5.1-104A

Boric Acid Flowpath Operability Test

ENG 1.7-102

SFPC Heat Exchanger and Pump Test

Except as noted below, the inspector had no further comments in this area,

b.

Observations and Findinas

Ventilation Testina

On September 27,1996, the system engineer documented a failed air flow while

performing surveillance procedure (SUR) 5.7-162. SUR 5.7-162 implements

technical specification (TS) surveillance 4.9.12.a.3. The minimum TS spent fuel

'

building air flow through the charcoal filters is 3,600 cubic feet per minute (cfm)

and the measured air flow on September 27,1996 was 1,990 cfm. The spent fuel

building ventilation system is required to be operable during movement of fuelin the

spent fuel building. The ventilation system ensures that all radioactive material

released from an irradiated fuel assembly will be filtered through the charcoal

absorber prior to discharge to the atmosphere.

..

-

o

.

.

20

The licensee learned through troubleshooting efforts between September 28 -

October 2,1996 that the flowrate through the spent fuel building ventilation system

was dependent on the configuration of the primary auxiliary building (PAB)

ventilation system. Specifically, spent fuel building ventilation system airflow

changes from acceptable to unacceptable depending on the number of PAB exhaust

fans in operation, amount of supply air in the PAB system, and if containment purge

is in service or not. The primary reason for interaction of the two ventilation

systems is that both are connected to the exhaust ducting prior to reaching the

main stack. The proper flow was obtained by adjusting the fan Jischarge damper.

The surveillance procedure did not require a verification of the PAB exhaust

ventilation system alignment. The inspector reviewed historical surveillance results

and concluded that the last three tests were performed within the acceptance

,

criteria of the TS, however they were performed during power operation with no

containment purge in service. Specifically, the surveillance was performed on

January 14,1993 (refueling outage was between May,1993 - July 20,1993), and

on July 13,1994 (refueling outage began January 28,1995 - April 19,1995), and

February 13,1996 (outage began on July 22,1996). During refueling conditions,

containment purge supply and exhaust valves must be operable in accordance with

TS 3.9.9. and one of the two PAB exhaust fans are in operation for containment

purge. The failure to have an adequate procedure to verify that the spent fuel

building ventilation system was able to perform its intended function is considered a

violation of TS 6.8.1 (eel 96-11-03). Even though the testing performed in

September,1996 was prior to the system being required to be operable, the results

indicate that the airflow was less than required based upon the affects of PAB

ventilation, and when the historical surveillance were performed.

,

i

On October 4,1996 the licensee determined that this surveillance failure was a

condition prohibited by technical specifications. Licensee event report (LER)96-025

dated October 24,1996 documented this event. An apparent cause of the

surveillance failure was inadequate knowledge of testing and engineering personnel

j

regarding the PAB ventilation alignment changes between power operation and

refueling operations, and the affects on the flowrates through the spent fuel pool

j

building ventilation system.

The design basis of the spent fuel pool ventilation system was evaluated in

systematic evaluation program (SEP) Topic XV-20 and referenced in Updated Final

Safety Analyris Report (UFSAR) section 15.5.2.2. The licensee concluded in SEP

Topic XV-20 that spent fuel building ventilation was not required to be in operation

during a fuel hindling accident to maintain offsite doses less than 10 CFR 100

limits; however, it was recognized that the normal operating procedure requires that

it be in service with the exhaust aligned to the charcoal filter when fuelis being

l

moved. Notwithstanding, the analysis in SEP Topic XV-20, technical specification 3.9.12 requires the system to be operable during movement of fuel within the spent

l

fuel building at an airflow of 4,000 cfm +/-10%.

UFSAR section 15.5.2.2 states

that the fuel be4 ding ventilation system and its associated charcoal filters will be in

operation durir g fuel handling.

1

>

.

,

,

21

Licensee corrective actions were to administratively control the position of the PAB

ventilation damper (specifically dilution damper setting), and control the SFB

exhaust fan discharge damper position. The surveillance was re-performed

successfully with containment purge in-service prior to fuel movement.

The inspector verified that SUR 5.7-162 appropriately implemented ASME/ ANSI

N510-1980, Testing of Nuclear Air-Cleaning Systems, Section 8, Airflow Capacity

and Distribution Tests guidance. The industry standard was reference in technical specification basis 3.9.12.

Boron Flow Path

On October 18,1996 the inspector observed a nuclear system operator (NSO)

implement SUR 5.1-1598, Boron injection Path Valve Lineup and Metering Pump

Test (Shutdown Modes 5 and 6). The activity on October 18,1996 was performed

with appropriate procedural compliance and a good pre-evolution briefing.

Seal Hatch Leak Test

On November 8,1996, the inspector observed licensee personnel implement special

test (ST) 11.7-200. The procedure was to confirm the o-ring integrity on the cavity

seal hatches. An air pressure test between the two o-rings on the hatches was

performed prior to flooding of the reactor cavity. It was performed satisfactorily on

October 2,1996; however, due to leakage from the cavity tell-tail drains on

November 5,1996, the licensee opted to re-verify the hatch integrity with the

refueling cavity full of water. ST 11.7-200 was developed to accomplish this diving

evolution.

The pre-evolution briefing was led by the system engineer with operations

management, maintenance personnel, contractor divers, health physics, and

radwaste technicians in attendance. The briefing was detailed. The health physics

technicians led a briefing wi:h the divers on the radiological controls during the dive

l

using radiation protectio., manual (RPM) 2.5-7, Diving Evolutions, for guidance. The

j

health physics briefing focused on low dose areas, importance of controls of cavity

i

entrance and exits, and the process for tool removal. The inspector noted that dose

to the divers was remotely displayed and during the performance of ST 11.7-200

and continuously monitored by health physics technicians. The inspector observed

the reactor operator at the cavity tell tail drains record the cavity sealleak rates

prior to, during, and after each of the pressure tests on the cavity hatches. No

change in cavity sealleak rates was observed. The inspector noted that the

i

operator displayed good knowledge of radiological conditions by remaining in the

designated low dose areas when leak rates were not requested.

The performance of ST 11.7-200 did not identify that the cavity seal hatches as the

source of leakage. Notwithstanding, the inspector noted appropriate health physics

support and good control by the system engineer during implementation of the

procedure.

_. ._ _ _

__

_

_ _ _ _ _ _

. .

. _ _ _

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C

.

i

22

c.

Conclusions

.

The surveillance test to verify operability of the spent fuel building ventilation

system had inadequate controls to ensure that acceptable airflow results were

obtained. This surveillance inadequacy resulted in a historical violation of the

technical specifications. The licensee reported this event as a condition prohibited

by technical specifications. The method of air flow testing was consistent with

industry standard ASME/ ANSI N510-1980 as depicted in the technical specification

basis and surveillance requirements. The inspector noted appropriate health physics

support during the implementation of ST 11.7-200.

M2

Maintenance and Material Condition of Facilities and Equipment

M 2.1

"B" Residual Heat Removal Pump Repairs Followina Overhaul

a.

I Joection Scope

l

On Saturday September 15,1996, while running the "B" Residual Heat Removal

(RHR) pump for 43 hours4.976852e-4 days <br />0.0119 hours <br />7.109788e-5 weeks <br />1.63615e-5 months <br /> following pump repairs discussed previously, operators

noticed oil leaking from the stationary oil baffle seal on the motor end of the pump.

Following investigation the oil baffle seal was replaced with a new seal. However,

once the pump was started, within seconds operators observed smoke and

unexpected noise. Once the pump was secured, inspection revealed the oil baffle

i

'

was damaged and had welded to the pump shaft. The inspectors reviewed

maintenance procedures, safety evaluations, root cause determination and test

l

procedures, and interviewed maintenance, test and operations personnel to

l

determine causes and the adequacy of corrective actions.

b.

Observations and Findinas

l

Following the "B" RHR pump shaft seizure on September 1,1996, Connecticut

l

Yankee (CY), determined the cause of the failure and performed repairs to the

pump. As a retest, the pump was started and run for approximately 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. At

,

that time, operators noticed oil leaking from the stationary oil baffle seal, which is

l

located on the motor side of the pump housing. The pump was secured and

l

inspected. It was determined that the oil baffle seal had rotated, either because of

vibration e ontact with the pump shaft. As a result of the baffle seal rotation, the

j

drain hole, t .ich directs the oil back into the casing also rotated out of the "6

,

o' clock" position. With the drain hole out of the required position, oil traveled down

the shaft and was observed by the operator.

The oil baffle seal was designed to be secured into the bearing housing cover with

an interference fit. As a result, the measurements and manufacturing tolerances of

the baffle are critical to ensure an adequate fit so that the baffle does not come in

contact with the pump shaft.

'

l

l

,

.

- - -

- -- .. .-

.

_ - . _ - - . .

_ - . - . _ .

. _

_ - -

C

.

.

!

!

23

I

A new beffle was ordered and received onsite. However, when installed it was also

loose and did not have the required interference fit. With the vendor, Ingersol

l

Dressor Puraps (lDP) approval, the baffle seal was " punch pricked" and locktite was

,

!

l

used to secure it to the pump housing cover. Because of the tight clearance

!

!

requirements, the clearance between the baffle seal and the shaft was also

questioned by CY personnel. On September 21,1996, during a telephone

conversat;on, the vendor told CY that the clearance should be between 4 and 11

l

mils total diametrical clearance. That is 2 to 5.5 mils radial clearance between the

i

shaft and the baffle seal.

!

1

As a result, CY determined to use a 3.5 mil radial clearance (7 mil diagonal) and

milled the baffle to this specification prior to installation. The runout, or flex, of the

'

shaft was measured to be approximately 2 mils total. This should have given the

baffle approximately 5 mils of diametrical clearance or 2.5 mil radial clearance.

i

When the pump was started on September 21,1996, operators immediately

'

observed smoke and noise coming from the area of the oil baffle seal. The pump

!

was secured and operators observed that the baffle had welded itself to the shaft

l

and rotated with the shaft.

,

!

.

'

I

l

Following partial disassembly and inspection of the pump shaft, oil baffle seal and

l

thrust housing, CY determined that the clearances specified by IDP during the

,

l

September 21,1996 telephone conversation had been inaccurate and that the

l

baffle had made contact with the shaft. As a result of the combined tolerances

,

,

l

allowed on components of the pump, the clearance specified between the baffle

'

l

and the shaft was too small to ensure adequate clearance.

{

l

As a result of the failure the vendor performed a more detailed review of the

specifications for the oil baffle seal. This review indicated that the nominal

j

clearance required between the baffle and the housing should be a diametrical total

of 18 mils. The 4-11 mils specified earlier was in error and was based on a review

of the tolerances stocking up on the pump components. At the time of the

,

September 21,1996 call, IDP had been reluctant to give CY the actual pump

i

'

drawings because they included proprietary information. Tho lack of ability to

)

review the actual drawing specifications resulted in CY reiving completely on IDP

for technical information regarding pump measurement specifications.

Because of problems with ordering the correct sized baffle seal, CY decided to

l

f abricate a baffle seal onsite using actual drawings obtained from the pump vendor

[

representative and measurements of the previous baffles. The new baffle was

'

f abricated such that an interference fit was used and the baffle was shrunk fit into

l

the housing.

i

On September 24,1996, the Plant Operating Review Committee (PORC) reviewed

and approved of the repair and retesting procedures. On September 24,1996, the

,

"B" RHR pump was started. However, low discharge pressures and low running

amps indicated that the pump was air bound. Difficulty in venting the RHR pumps

j

has been experienced in the past. As a result of the pump piping arrangement, air

!

_

_

i

, - -

- .

.

. - - -.-

- -- - - . - --- .--.

-- -

.

e

.

,

.

o

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l

i

i

!

24

,

becomes trapped in the discharge and suction piping of the pump. Once the pump

I

was started with air in the piping, and the "A" RHR pump running, the "B" RHR

pump was not able to generate a high enough discharge pressure to open the

'

downstream check valve, which was at RHR header pressure of over 118 psig.

Once "B" RHR pump discharge pressure exceeds the RHR header pressure, the

!

che,ck valve can open and sweep any remaining air out of the pump.

l

l

As a result of the test failure, CY developed a second test. This test opened a heat

l

l

exchanger bypass valve which raised header flow and lowered header pressure.

l'

The procedure "B" RHR Pump Startup & Troubleshooting test, ST11.7-199 Rev.1,

also allowed the pump to be vented during the run and allowed repeating the run

three times to ensure that the pump was adequately vented. At approximately-

l

9:00 p.m. on September 25,1996, the pump was run satisfactorily and declared

- '

operable.

c.

Conclusions

j

!

The RHR pump failures due to rotation of the baffle were caused by inadequate

sizing and spacing of the oil baffle seal. The lack of vendor drawings was a

contributor to the inadequate corrective actions to resolve the problem.

l

!

M2.2 SFP Service Water System (SWS) Supolv Line Inspection

!

i

a.

Inspection Scope

The inspector reviewed the reported findings by the licensee of spent fuel pool

)

(SFP) SWS supply line indications during the Inservice inspection (ISI) of five welded

i

pipe supports. The review included the location of the reported indications, tha

'

description and nondestructive techniques used to characterize the indications, the

evaluation of the SWS supply line operability, and the corrective action taken to

I

preclude failure of the SFP SWS supply line piping.

i

b.

Observations and Findinas

Acoarent Pine Crack

As part of the 10-year ISI visual inspection (VT) of hanger-to-pipe welds of the

SWS, a Level ll licensee inspector noted cracked paint in the region adjacent to the

hanger support WS 2028 pipe plate weld. The licensee inspector performed

magnetic particle testing (MT) of the pipe surface and found an indication running in

an axial direction for 29.75 inches into the Plant Auxiliaries Building (PAB) South

Wall through which the pipe passed. The licensee further performed ultrasonic tests

(UT) of the crack and reported radial depths of .206 to .235 inches at intervals of 2

inches. Since the nominal thickness of the 6-inch pipe was .253 inches, the

indication bode a serious effect on pipe structural integrity. Because of the

characteristics of the UT reading, the licensee believed that the indication depth

reading may have been affected by an irregular inner pipe surface. Two Level 111

1

.

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.

25

NDE technicians re-e'xamined the UT test results and found depths no greater than

.065 inches. The Level til technicians believed the defect was typical of a shallow

" pipe lap" present in the manufactured pipe material. The indication extended

through the wall and ended at a pipe elbow circumferential weld on the other side

of the wall.

A 52-inch sample of the SFP SWS supply line containing the defect was sent to the

Materials Testing Laboratory of Northeast Nuclear Energy for flaw characterization.

An area 40 inches in length revealed a linear, but intermittent indication. Two

significant indications were located 2.25 inches from the WS-2028 pipe support

!

'

pad weld, and a third was located 1 inch from the circumferential pipe weld at the

pipe elbow beyond the PAB South Wall. The NRC inspector examined etched

photomicrographs (100X and 150X) from a sample slice containing the defect. The

photomicrographs revealed defects 7 mits and 4 mits in depth. The etched

microstructure of the unaffected pipe was typical of A53 carbon steel, with an

equal mixture of ferrite and pearlite. The indication opening of .003 inches was

l

filled with a decarburized matrix with oxide inclusions. The defect morphology

indicated that the defects were " pipe laps"probably existing after manufacture.

These were believed by the licensee not to be caused by any service-induced

loading.

,

in order to ascertain the qualification of the inspector reporting the initial defect

depth, the inspector reviewed the NDE inspector's qualifications and found them to

be consistent with requirements of Level ll for VT, MT, and UT, The UT inspectors

.

re-interpreting the defect depth UT tests were both Levellliin UT.

The licensee evaluated the pipe lap defect to determine the possible effect on

>

operability of the pipe under the anticipated operating conditions, including design,

thermal, and seismic loading. For the initially large depths (exceeding .200 inches)

the licensee determined that the pipe was inoperable. Subsequently, the pipe was

replaced. Subsequent evaluation of the operability of the pipe with " pipe laps"

shows that the depth, directionality, and morphology of the flaw detracts negligibly

from the ability of the pipe to sustain such loading. The wall thickness reduction,

and increased stress resulting therefrom, was negligible. The engineering evaluation

was provided in memorandum dated October 22,1996 (CES-96-325).

Following the initial pipe lap indication finding, the licensee performed MT

examinations of the pipe at all 32 SFP SWS pipe supports. At these locations, five

non-conformance reports (NCRs) were written. The defects at these locations were

found to be shallow " pipe lap" indications and were removed using light buffing, or

" flapping" tools.

The inspector requested the original material certifications for review. The licensee

could not produce them for examination. There was much of this Class 3 piping in

the service water system, and it was believed that any specific piece of pipe

material could be identified only from a certified material test report (CMTR) from a

batch of piping, in lieu of providing the original CMTR, the licensee arranged for an

e

<

26

independent contractor (Dirats Laboratories) to test a sample of the pipe material

containing the defect. The results of the test show that the sample was consistent

with the ASTM Standard Specification for A-53 Type S seamless pipe, Grade B.

The licensee reviewed the indication findings, the results of the expanded inspection

'

of pipes at the supports, the results of VT, MT, and UT, and concluded that the

piping defects resulted from the manufacturing process, and not from any applied

loading to the pipe. The licensee concluded that the indications were not of a

nature to detract from the ability of the pipe to perform its intended function. On

this basis, the licensee believes replacement of any sections of SFP SWS supply line

pipe will be necessary only if discovered defects exceed the magnitude permitted by

Section XI of the American Society of Mechanical Engineers Boiler and Pressure

Vessel Code.

Other Material Deficiencies

The licensee expanded the review of SW piping and evaluation of potential defects

to assure the SFPCS was acceptable for core offload. The licensee identified flaws

in two tee-to-pipe welds in the service water return line from the SFP heat

exchangers. The licensee established a flood watch until repairs were done. The

affected pipe tee was replaced during an outage of the SW supply to the heat

exchangers. Additionally, the licensee rep! aced a tee on the heat exchanger supply

line which had a known defect that was being tracked under the SW corrosion

monitoring program (and had been previously found to be acceptable until the

Spring of 1997). The licensee replaced the supply side tee as well. The SW supply

to the SFPCS was restored to normal on October 30,1996.

c.

Conclusions

The licensee satisfactorily evaluated the safety significance of the findings of " pipe

lap" defects in the SFP SWS supply pipe. The use of expanded inspection of all

SFP SWS supply pipe at the support hangers, the metallurgical characterization of

the defect, the NDE examinations of the defect, the analytic evaluation of the

defect, and the corrective action taken was conservative and consistent with good

engineering practice. Actions to address other material deficiencies in the SFPCS

prior to core offload were appropriate.

M8

Previous Open items

M8.1 (Closed) IFl 95-02-03. Followup Refuel Eauipment Failures

~

This item was last reviewed in Inspection 96-01 and remained open pending NRC

review of licensee actions to upgrade and maintain refueling equipment. The

licensee completed several actions to improve or upgrade the refueling equipment

prior to the final core offload. The actions and plans in this area were summarized

in a engineering memorandum dated September 30,1996 ( CY-TS-96-462), and

included: implementing PDCR 1575 to upgrade the fuel assembly upender; checkout

i

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.

.

.

27

of new fuel handling tools and the transfer cart; replacing the cable on the new fuel

elevator; checkout of the sluice gate operation; performing preventive maintenance

and load testing of the manipulator crane; performing preventive maintenance on

the polar and spent fuel building cranes; and, revising the refueling procedures.

Finally, the licensee identified a new fuel handling accident involving the dropping of

a fuel bundle in the pool from the surface of the water (ACR 96-278). This item

needed to resolved prior to placing the new fuel into the spent fuel pool. However,

this evolution was never completed after the joint owners of Haddam Neck

l

announced on October 9 that the permanent shutdown of the plant was likely. The

listed corrective actions were completed as necessary prior to the core offload.

This item is closed.

M8.2 (Closed) URI 96-04-01, investiaation of Mav 23 Soent Fuel Event

This item concerned the completion of the licensee's review of an event in May,

1996 in which a fuel bundle became suspended on top of the fuel racks. The

licensee identified personnel performance issues regarding the overriding of

interlocks while inserting the bundle on May 23, and the need for a tool to guide

insertion of fuel bundles in the new racks. A funnel type guide tool was

successfully used for the core offload in November,1996. The inspector reviewed

personnel performance and actions to operate the fuel handling equipment during

the November 1996 defueling. No inadequacies were identified. This item is

closed.

M8.3 (Ocen) IFl 93-01-01: Safety Instrument Calibrations

This item was open pending the completion of licensee actions to assure

instruments used to satisfy technical specification surveillances are periodically

calibrated. Section E8.2 of this report (see LER 96-27) describes additional

discrepancies regarding the failure to calibrate temperature instruments used on the

safety related boric acid heat trace circuits. This item remains open pending further

i

NRC review of licensee corrective actions.

Ill. Enaineerina

E1

Conduct of Engineering

E1.1

Instrumentation Setooint Control (eel 96-11-04)

a.

Insoection Scope (92903)

The scope of this inspection included a review of the licensee instrumentation

setpoint calculation program associated with the reactor protection system,

engineered safeguards features systems and a sample of other instrumentation

included in the plant technical specifications. The inspectors also reviewed the

engineering procedures utilized to perform instrument uncertainty and setpoint

_

,

-

.

_ _ _

.

.

_ ~ _ . _ . _ ~ _

_ _ . . _ _ - . _-_ .

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28

i

calculations. A sample of setpoint calculations were reviewed to assess the

,

methods utilized in the calculation and the overall quality of the engineering work.

b.

Observations and Findinas

6

Setooint Calculation Proaram Development

[

_

i

The inspector reviewed factors and events associated with the development of

,

instrument uncertainty and setpoint calculations. The initial technical specification

!

trip setpoints and allowable values were provided by the nuc! ear steam supply

i

system (NSSS) vendor during the initial plant construction and licensing. The plant

,

modification to replace the reactor protection system identified the need to perform

!'

setpoint calculations as part of the modification process in 1983.

'

Licensee Event Report (LER)90-022 reported a miscalibration of auxiliary feedwater

flow transmitters. At that time, a long term corrective action was identified that

!

consisted of the systematic evaluation of critical safety-significant setpoints and

developing uncertainty calculations to support the selected hardware setpoints. In

1991, Project Authorization (PA)91-064 initiated a Setpoint Verification Program

for the reactor protection system, engineered safeguards features systems and

i

primary containment isolation system instruments. This PA was to address the long

term actions identified in LER 90-022.

i

Responsibility for the setpoint verification program was transferred from the

I

corporate engineering organization to the site in 1994 following the reorganization

of the engineering departments. The setpoint verification program effort was

combined with the project to revise the technical specifications to support a 24-

)

month fuel cycle. The calculations required for the 24-month fuel cycle technical

j

specification change were completed in 1995 and the proposed technical

specification revision was submitted to the NRC on December 20,1995.

Enaineerina Procedures

The inspector reviewed procedures SP-ST-EE-286, Rev. 6, " Guidelines for

Calculating Instrument Uncertainties," and SP-ST-EE-320, Rev.1, " Guidelines for

Calculating Instrumentatio-n Setpoints for Safety Systems." The procedures were

'

,

initially issued in 1989 and 1993 respectively, and both procedures utilize methods

!

described in the instrument Society of America (ISA) Standard ISA-S67.04,

j

"Setpoints for Nuclear Safety-Related Instrumentation." The NRC endorsed the use

'

of the ISA methods in USNRC Regulatory Guide 1.105, Revision 2, " Instrument

Setpoints for Safety Related Systems."

The inspector found the procedures to be generally of good quality. However, the

inspector did note that SP-ST-EE-320 did not include an allowance for seismic

effects (SE) when calculating the setpoint allowable values. The inspector noted

that, although not included in the procedure, the calculations performed to support

-

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.

.

.

.-

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.

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29

the 24 month fuel cycle did include the SE and the licensee acknowledged that a

procedure correction was necessary.

Calculations that were performed prior to 1989 appear to have used the ISA 67.04

and R.G.105 guidance directly since there were no engineering department

procedures that provided specific guidance on performing instrumentation

uncertainty and setpoint calculations.

Calculation Proaram Findinas

The licensee approach for calculating allowable values and trip setpoints for

instruments is summarized as follows:

(1)

The analytic limit for the parameter monitored by the instrument is obtained

from the safety analysis engineer and is the value assumed in the safety

analysis that supports the design basis of the safety system.

(2)

The errors that contribute to the totalinstrument loop uncertainty are

calculated and categorized as either errors that are not observable during

i

routine testing and calibration and those that are observable. Those errors

that are not observable are combined to calculate a term designated as

Allowance No.1. Observable errors are combined and designated as

Allowance No. 2.

(3)

The allowable value, defined in procedure SP-ST-EE-320 as a " limiting value

that the trip setpoint may have when tested periodically beyond which

appropriate action shall be taken," is then calculated as follows:

Allowable value = analytical limit

Allowance No.1.

(Allowance No.1 and Allowance No. 2, discussed below, are added or

subtracted depending on whether the trip occurs on an increasing or

decreasing value.)

(4)

The trip setpoint, which is defined in procedure EE-320 as a predetermined

value for actuation of the final actuation device to initiate protective actions,

is calculated as follows:

Trip setpoint = allowable value i Allowance No. 2.

For example, with an instrument trip that occurs on an increasing value the

relative values would be established as follo.vs:

.

.-

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= . - . ~ . _ .

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Analytical Limit

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Allowance #1

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,

Allowable Value

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Allowance #2

4

Trip Setpoint

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Operating Margin

,

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Normal Operating Point

.

Where Allowance No.1 includes the following terms, as applicable:

Process Measurement Accuracy (PMA)

Primary Element Accuracy (PEA)

'

Sensor Temperature Effects (STE)

Sensor Pressure Effects (SPE)

Rack Temperature Effects (RTE)

Harsh Environment Effects-Radiation Allowance (RA)

Insulation Resistance Effect (IRE)

LOCA/HELB Effects (DLH)

1

Additional Margin (AM)

And Allowance No. 2 is the resultant of the following terms:

Sensor Calibration Accuracy (SCA)

Sensor Drift (SD)

Rack Calibration Accuracy (RCA)

Rack Drift (RD)

l

Measurement and Test Equipment Accuracy (MTE)

Procedure SP-ST-EE-320 permits the inclusion of additional margin in the Allowance

l

No.1 term to reduce the probability of exceeding the analytical limit.

p

.

The inspector also noted that the plant technical specification (TS) bases for

!

TS 2.2.1, " Reactor Trip System Instrumentation Setpoints," provides information

relative to trip setpoints and allowable values. Specifically, the bases states that

!

" Operation with ( trip set less conservative that its Trip Setpoint but within its

i

specified Allowat le Value is acceptable on the basis that the difference between

'

each Trip Setpolit and the Allowable value is equal to or less than a drift allowance

accounted for in the design basis analysis."

'

.

,

'

.

.

.

+

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.

31

The inspector identified the following issues with the setpoint control program:

(a)

During the performance of the calculations for the 24 month fuel cycle the

value of Allowance No. 2 was increased by the inclusion of an " additional

margin (AM)" term when combining the uncertainty effects that are

observable during testing and calibrations. Including the AM term in

Allowance No. 2 resulted in additional rnargin between the analytical value

and the trip setpoint. However, the difference between the trip setpoint and

the allowable value was no longer less than or equal to the drift allowance

that should be accounted for according to the setpoint calculation procedure,

SF-ST-EE-320 and as discussed in the TS bases. As a result, excessive

ir.strumer3 drift could occur before the condition would be identified and

evaluated fcr operabiiity and the need for corrective action. In some cases

the amount of AM included in Allowance No. 2 was very significant. For

example, in calculation PA 90-013-321 EY, Revision 1, " Uncertainty

Calculation For Steam Flow Loops F-1201-1 B,-1 C,-28,-2C,-3B,-3D,-4B,-4D

and Setpoint Calculation For Steam Flow /Feedwater Flow Mismatch," the

calculated uncertainty for Allowance No. 2 was 25,250 lbm/hr and the AM

added was 33,430 lbm/hr. This resulted in the difference between the trip

setpoint and the allowable value being more than twice the allowance that

should have been included based on SP-ST-EE-320 and the plant technical

specification bases. Similarly, in calculation PA 90-013-341 EY, Revision 1,

" Uncertainty and Setpoint Calculation For Steam Line Break Flow F-1202-1,-

2,-3,-4," Allowance No. 2 was calculated to be 0.99% flow and an

additional 1.01 % flow was added as AM. The inspector concluded that the

addition of AM in the Allowance No. 2 term was not appropriate and

defeated the purpose of establishing allowable values.

(b)

In addition to reducing the effectiveness of the allowable values by the

addition of AM in Allowance No. 2, the inspector noted that sensor drift

effect and sensor calibration accuracy values in the uncertainty calculations

were arbitrarily increased to provide added " conservatism." The inspectors

agreed that this practice would add conservatism between the analytical

value and the trip setpoint. However, the difference between the trip

setpoint and allowable value again would not be equal to or less than the

expected component drift. For example, calculation 95-01262EY,

Revision 0, " Uncertainties and Setpoints for RCS Flow Loops F-401 A,C,D;

402A,C,D; 403A,C,D; 404A,C,D," determined that the sensor calibration

accuracy for the Foxboro transmitters in the loop were 10.52% of span and

the sensor drift was i3.81 % of span. However, one transmitter (FT-402D)

is a Model 1164 Rosemount transmitter that has a manufacturer-specified

sensor calibration accuracy of

0.25% of span and an expected drift of

10.28% of span based on a licensee drift analysis. In the setpoint

calculation the sensor drift and sensor calibration accuracies for the Foxboro

transmitters were used for all transmitters for conservatism. The inspector

concluded that the use of these values for the Rosemount transmitter could

again allow excessive drift to go undetected.

___

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. _-

.

.

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32

l

The failure to assure that the allowable values were determined in accordance with

the design basis is a violation of 10 CFR 50 Appendix B, Criteria 111, Design Control.

,

(eel 96-11-04) This is the first of two examples of a design control violation.

I

1

l

(c)

The inspector reviewed the instrument testing and calibrat'on process to

determine how testing or calibration f ailures were evaluated to determine if

1

the instrument as-found data was within the technical specification allowable

value and to evaluate instrument operability. The inspector noted that the

instrument loop components are generally tested or calibrated on a

component level bases versus an integrated loop calibration. The licensee

initially stated that the acceptance criteria for each of the loop components

j

was conservative relative to the potential errors determined in the

uncertainty calculations. As such, test and calibration data that met the

procedure specifications would ensure that the loop was performing within

the technical specification allowable values. The inspector reviewed several

l

surveillance procedures and found that the acceptance criteria was not

consistent for similar components in different instrument loops, and in some

cases, the acceptance criteria specified in the tests was not conservative

,

relative to the instrument uncertainties determined in the calculations. For

example:

)

Procedure SUR 5.2-6.1, " Steam Generator #1 Narrow Range Level Channel

e

,

Calibration," specifies an acceptance criteria of * 1.0% of span for Model

l

1154 Rosemount transmitter LT-1301-1 A,-1C and -1D. Calculation PA 90-

i

013-262EY, Rev. 2, " Uncertainties and Setpoints for Steam Generator

Narrow Range Level L-1301-1 A/C/D, 2A/C/D, 3A/C/D ,4A/C/D," specifies a

sensor calibration accuracy (SCA) of iO.25% of span for the transmitter.

4

'

-This value (iO.25% span) is applied as a sensor calibration tolerance for

another Model 1154 Rosemount transmitter for instrument PT-1201-2B in

surveillance procedure SUR 5.2-11.2, " Steam Generator #2 Train A Steam

Flow, Feedwater Flow, Steam Generator Pressure Channel Calibration." The

inspector concluded that the use of i1.0% span acceptance criteria was

inappropriate since even when all factors associated with the sensor

calibration (i.e. sensor calibration accuracy, sensor drift and measurement

and test equipment accuracy) are considered, the total probable error would

be iO.6% of span. Therefore, the use of i1.0% would allow a sensor with

excessive drift to be found acceptable during the calibration. The inspectors

reviewed the results of surveillance procedure 5.2-6.1 that was completed

on March 6,1995, and found that the as found calibration data for

,

transmitter LT-1301-1 A would have failed a

0.6% acceptance criteria.

i

The failure to ensure that the results of the engineering calculations were translated

j

into plant procedures is an apparent violation of 10 CFR 50 Appendix B, Criteria 111,

!

Design Control. (eel 96-11-04) This is the second of two examples of a design

control violation.

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'

!

Specific Calculation Errors

in addition to the programmatic issues identified above, the inspectors noted the

following specific errors in setpoint calculations:

In calculation 95-01262EY, Revision 0, " Uncertainties and Setpoints for RCS

i

Flow Loops F-401 A,C,D; 402A,C,D; 403A,C,D; 404A,C,D," the instrument

i

span is -0.5 to 30 psid and Allowance No.1 and Allowance No. 2 were

i

calculated as a percent of the instrument span. The useable span is 0.0 to

30 psid which correlates to O to 100% of rated reactor coolant system (RCS)

,

flow. When the allowable value and trip setpoints were calculated, the

l

percent span errors were added to the percent RCS flow values without first

adjusting percent span errors to a corresponding percent flow.

{

In calculation 93-ENG-552EY, Revision 0, " Uncertainty and Setpoint

l

Calculation for Pressurizer Level L-401-1,-2,-3,-4," the rack temperature

effect (RTE) term was not included in the calculation of Allowance No.1.

The inspector did note that there was additional margin included in the

Allowance No.1 term that was greater than the omitted term and therefore

'

there was adequate margin between the analytical value and the trip

setpoint.

i

i

e

in calculation IC-CY-1451EY, Revision 0, " Uncertainties and Setpoints for

the Wide Range Nuclear Flux Monitoring System Startup Rate Reactor Trip

Channels WR1, WR2, WR3, and WR4," the allowable value was incorrect

due to a transposition error. The inspector noted that the licensee had also

)

identified and corrected this error when the calculation was subsequently

l

revised for other reasons.

Calculation IC-CALC-90-026, "RCS Low Flow Channel Accuracy / Safety

Setpoint Calculation," improperly concluded that the technical specification

allowable value was adequate although the margin between the trip setpoint

and allowable value was excessive and therefore not consistent with the

technical specification bases. Also, the calculation assumed that rack drift

was zero without providing any justification for the assumption and the

calculation did not consider sensor drift and sensor calibration accuracy

when assessing the adequacy of the existing allowable value.

Effects on Analvtical Limits and Accident Analyses

The inspector discussed the impact of the 24 month fuel cycle calculations with a

member of the accident analysis group. The results of the 24 month cycle

calculations supported the existing analytical limits and no additional accident

analyses was required. The previously established setpoints provided sufficient

margin to the analytical limits to ensure safe operation. However, as discussed

above the allowable values were not set sufficiently conservative to ensure

detection of excessive instrument drift.

F

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_ . _ . . . ,

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34

l

The licensee acknowledged the issues identified by the inspector and documented

these concerns and other related issues in an adverse condition report.

!

-

c.

Conclusions

.

E

The inspector concluded that there were weaknesses in the setpoint control

!

program that resulted in incorrect calculation results and inappropriate calibration

i

procedure acceptance criteria. The licensee did not establish clear engineering

procedures on how to perform setpoint calculations until 1993. The errors

.l

identified indicate that a review and assessment of the accuracy of the information

i

submitted in the technical specification change request is warranted. The

{

inspectors also concluded that the independent review process was not effective in

!

identifying programmatic or specific calculation errors. The potential safety

l

consequences of the identified deficiencies were minor because appropriate

!

conservatisms were included in the uncertainty factors that make up Allowance

!

No.1 and the additional margins that were included in the Allowance No. 2

I

uncertainty f actors combined to increase the margin between the analytical limits

l

and the trip setpoints. The detrimental effects of the problems were that the

!

inflated difference between the allowable values and the trip setpoints impaired the

l

ability to detect components that had excessive drift or may have been degraded

j

and trending towards f ailure.

E1.2 Instrumentation Calibrations (eel 96-11-05)

'

a.

Insoection Scope (92903)

The inspectors reviewed the licensee procedure for evaluating and dispositioning

instrumentation calibration results that do not meet the established acceptance

criteria.

.

t

b.

Observations and Findinas

i

!

The licensee procedure for performing instrumentation calibration reviews is

l

WCM 2.3-7, Revision 2, " Instrument Calibration Review." This procedure requires

that an Instrumentation Calibration Review (ICR) Form be processed for each

instance when a surveillance procedure is performed and the as-found calibration

data is outside of the acceptance criteria. The ICR form is utilized to document

whether or not the drift was in the conservative or non-conservative direction and

to document whether or not the calibration was within the technical specification

limits The procedure also provides directions to assess whether the failure is

reportable in accordance with the requirements of 10 CFR 50.72 and 10 CFR 50.73

and to implement corrective action to prevent recurrence based on instrument

performance and history.

'

The inspectors reviewed several completed ICRs and found the following:

.

'

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-

_

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_ . , _

,

_

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,

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.

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.

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35

(1)

ICRs95-009 and 95-011 documented calibration failures for two identical

I

model Rosemount transmitters. The only corrective action was for the

'

failure to be tracked by the system engineer. The reviews did not question

the adequacy of the acceptance criteria even though there was different

!

criteria for identical components. The procedure associated with ICR 95-009

specified an acceptance criteria of i1.0% of span and the other specified

l

0.25% of span. Also, when the as-found data was evaluated to determine

!

if the technical specification allowable values were exceeded, only the

'

affected components were evaluated and the combined. effects of all of the

loop components were not assessed.

,

i

I

(2)

ICRs 95-23 and 95-24 documented the cause of the failures as drift and the

only corrective actions were to recalibrate.

)

1

(3)

ICR 95-025 documented a failure of a Foxboro rack component and the-

l

cause of the failure was documented as unknown, the component was

'

adjusted and no additional corrective action was taken.

c.

Conclusions

1

i

The inspectors concluded that the licensee did not adequately determine the root

[

causes of instrument calibration failures nor were adequate corrective actions taken

-i

to prevent recurrence. None of the ICR evaluations considered potential corrective .

actions such as adjustment of testing frequency, setpoint revision, reevaluation of

the trip setpoint or allowable value, evaluation of equipment installation and

environment, evaluation of calibration equipment and technique or repair or

,

replacement of the component. The failure to implement adequate corrective

I

actions for instrumentation failures is an apparent violation of 10 CFR 50 Appendix

B, Criteria XVI. (eel 96-11-05)

E2

Engineering Support of Facilities and Equipment

E2.1

Temocrarv Soent Fuel Pool Heat Exchanaer Coolina

a.

Insoection Scoce

The inspection scope was to evaluate the implementation and controls for

temporary cooling supply of service water to the spent fuel pool heat exchangers.

The temporary cooling was required to affect repairs to the service water supply

pipe to the spent fuel pool heat exchangers,

b.

Observations and Findinas

On October 11,1996, the licensee isolated service water to the "A" spent fuel pool

heat exchanger. The reason for the isolation was to prepare for installing a

temporary modification to supply cooling to the heat exchanger. The temporary

_

.

. _ _ _ . _ _ _ _ _ _ _ _ _ . - _ . _ _ . _ . _ _ - . . _ . - _ ._

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36

1

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modification was required to make repairs to the permanent service water supply

piping that had indication of severe pipe degradation.

The service water was isolated to the spent fuel pool cooling heat exchanger for

approximately 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> between October 11 and October 12,1996. The spent fuel

pool temperature increased approximately 13 degrees fahrenheit (F) to a maximum

of 86 F. The design basis temperature for the pool is 150 degrees F.

The temporary modification installed two three (3) inch fire hoses from the service

water filter drain connection to the supply of the "A" spent fuel pool heat

exchanger. The connection to the inlet of the "A" spent fuel pool heat exchanger

,

required the removal of the permanently installed piping and the connection of a

'

spool piece with fire hose connections.

The licensee concluded that the temporary modification was not an unreviewed

safety question as defined in 10 CFR 50.59. The postulated malfunctions evaluated

included the rupture of the fire hose and affects on internal flooding in the primary

auxiliary building, inadequate flow to the spent fuel pool heat exchangers, loss of

service water, and response of the fire hoses during a seismic event. A prerequisite

for installation was that flow through the hoses was in excess of 100 gallons per

!

minute (gpm) to maintain the pool temperature in the normal operating bands. The

i

licensee confirmed this by measurement. Redundant fire hoses were staged as an

'

additional contingency if one of the two hoses burst. UFSAR accidents evaluated

L

were the loss of spent fuel pool cooling, loss of normal power event, boron dilution

l

event, and fuel handling accident inside containment. The installation and removal

l

of the temporary modification occurred prior to fuel movement.

The installation of temporary cooling was supported by procedure changes to NOP

2.24-3, Filtered Service Water System and Adams Filter Operation, and SUR 5.1-

OA, Steady State Operational Surveillance (Modes 5 and 6). The procedure

i

changes provided guidance on installation of the jumper, control of flowrate to the

i

spent fuel pool (SFP) heat exchanger, response to a failed hose, and actions

necessary to remove the temporary modification. The change to SUR 5.1-0A was

to add a check by the NSO every eight hours to verify no leakage, and to walkdown

the entire length of hose.

The inspector walked down the installation of the temporary modification on

October 13,1996. The installation appeared to be appropriately supported at

various locations and was installed in accordance with the documentation of the

- modification. In addition to the installation walkdown, the inspector independently

verified that tag clearance 96-1006 was adequate to isolate the service water

system from the temporary installation. The temporary modification was removed

on October 30,1996.

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37

c.

Conclusions

The temporary modification to supply cooling water to the spent fuel pool was

performed satisfactorily, with appropriate contingency planning and monitoring of

pool temperatures.

,

E2.2 Soent Fuel Pool Coolina Check Valve Replacement

a.

Inspection Scone

The inspection scope evaluated the operability of the spent fuel pool cooling system

with one of the two spent fuel pool cooling pump discharge check valve internals

removed.

,

b.

Observations and Findinas

On September 28,1996, the spent fuel pool system engineer documented to

licensee management that there was no condition that could adversely affect

availability of spent fuel pool cooling in Mode 6 operation. The system engineer

initially concluded that the "B" spent fuel cooling pump was operable with the

internal parts of the discharge check valve (SF-CV-866) removed under temporary

modification 96-12.

The inspector questioned this decision since technical specification (TS) 3.9.15

states that spent fuel pool cooling shall be operable with both pumps operable and

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at least one cooling pump and plate heat exchanger in operation. Additionally,

surveillance procedure SUR 5.3-51, Refueling Operations, step 1.3.6, requires prior

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to movement of irradiated fuel to the spent fuel pool, that the licensee verify that

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both spent fuel cooling pumps are lined up to provide flow to the plate heat

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exchanger. With the valves internals removed from SF-CV-866 the manual

'

discharge isolation valve for the "B" spent fuel pool cooling pump would be closed

to assure operability of the A pump. Thus, the B pump could not be lined up as

required, but would require manual operator action to be placed in service. The

licensee acknowledged the inspector's concern.

The licensee implemented a previously planned plant modification to replace both

spent fuel pool discharge check valves and relocate the "B" check valve further

away from the pump, and in conformance with industry guidelines on locations of

check valves from bends in piping systems. The modification was completed prior

to refueling activities on November 11,1996,

i

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The inspector noted the following regarding this condition. First, the "B" SFP

discharge check valves internals have been removed since March,1996 without

timely corrective actions. Second, the licensee overcame the component deficiency

by implementing a procedure change to NOP 2.10-1, Spent Fuel Pit Cooling System

Operation by requiring the manual discharge valve on the "B" SFP cooling pump

when not operating to be closed. Third, when the internals were removed from SF-

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CV-866 in March,1996, the licenseo concluded that no affect on operability

existed; however, TS 3.9.15 was not applicable at that time.

c.

Conclusions

The licensee's initial decision-making on operational readiness of the spent fuel pool

cooling system for defueling operations was non-conservative with respect to the

technical specifications and the implementing surveillance procedure. A planned

modification was completed prior to defueling activities to restore the cooling

system to an improved configuration. Initial corrective actions were not timely to

address deficient material conditions.

E2.3 Inadeauste Auxiliary Buildina Flood Protection (eel 96-11-06)

a.

inspection Scope

The inspection scope was to evaluate licensee actions in response to a plant

configuration deficiency as it related to internal flood protection in the PAB.

b.

Observations and Findinas

On October 23,1996, the licensee identified various floor penetrations in the PAB

that did not provide assurances that the response times assumed in the licensing

basis was conservative for the worst-case internal flood scenario. Approximately,

thirty-five (35) penetrations did not have a 24 inch high carbon steel barrier.

In 1973, the licensee implemented plant modification (PDCR 156, Flooding

Protection of Safeguards Equipment) in response to an Atomic Energy Commission

(AEC) letter to the licensee in August,1972. The AEC letter requested the licensee

to review the facility design and determine if equipment that does not meet criteria

of Class I seismic construction could cause flooding sufficient to adversely affect

the performance of engineered safety systems. Additionally, the licensee was

asked to consider if the failure of any equipment could cause flooding such that

common mode failure of redundant safety related equipment would result. The

modification installed steel barriers around piping penetrations on both elevations of

the primary auxiliary building and around the engineered safety features pumps. At

the time, the licensee did not install pipe barriers for penetrations in areas connected

to the pipe chase since no credit was taken in the flood analysis for the additional

delay time to flood the RHR pumps (i.e. taking into account the delay of flood water

flow through the pipe chase and ultimately to the RHR pumps). This was

documented to the NRC is a letter dated August 1,1975.

The NRC's safety evaluation in support of technical specification amendment 27

(July 20,1978) concluded that it was appropriate to add area flood annunciators

and operability requirements to the technical specification to provide adequate

operator response time to determine the source of leakage and to take corrective

action. In the safety evaluation, the licensee concluded that approximately 12

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minutes were available for operator action to terminate flooding in the PAB for the

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worst case break of the service water return piping from the component cooling

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water heat exchangers. The NRC position as documented in the safety evaluation

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was that credit for operator action is not assumed during the first ten minutes of a

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postulated event. Since the worst-case analysis calculated a 12 minute response

3

for operator action, no automatic trip of the service watar pumps was required.

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The licensee performed further reviews of PAB flooding, as described in LER 96-08

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' (reference Inspection 96-06, Section E3.1). Licensee calculation 96-PABFLOOD-

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01497 (November 7,1996) concluded that the RHR pumps would be inoperable in

7 minutes without operator action to mitigate or isolate the leak, and approximately

,

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6 minutes after receiving the flood alarm in the RHR pit. This revised calculation

contributed to the identification en October 23,1996 that various piping

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penetrations (accumulated two square foot opening) did not have flood barriers

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installed.

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Licensee corrective actions upon identification were to establish a flood watch in

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the PAB to provide for early detection and isolation of the worst-case scenario pipe

{

failure. This watch was established 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day until November 15,1996 when

!

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all of the reactor fuel was removed from the reactor vessel, and RHR operability

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was not required.

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This condition represents a violation of 10 CFR 50 Appendix B, Criterion lli (eel 96-

,

11-06)in that measures to assure applicable regulatory requirements and design

basis for structures were not correctly translated into specifications. Specifically,

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the lack of flood barriers around the piping penetrations invalidated the basis for

operator response time to mitigate an internal flood scenario. An apparent cause for

i

this violation was lack of engineering rigor in a past plant modification.

4

c.

C_qnclusioni

The inspector noted a lack of engineering rigor for a past modification to protect

safety equipment from an internal flood scenario. The modification did not require

flood barrier installation for approximately thirty-five (35) penetrations. This failure

<

resulted in a non-conservative flood analysis regarding operator response time to

{

mitigate the event. This condition is considered a violation of 10 CFR 50 Appendix

B, Criterion Ill.

E2.4 Porous Concrete Sub-Foundation

4

a.

Insoection Scoce

The scope of this inspection was to determine whether the concrete beneath the

containment base mat was eroding.

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b.

Observations and Findinas

The NRC issued a request for information by letter dated October 18,1996, to

evaluate the potential generic implications of the erosion of cement from underneath

l

the containment foundation basement. As shown on plant design drawing 16103-

56024, a six inch thick layer of porous (" popcorn") concrete was installed during

plant construction beneath the containment foundation mat.

By letar dated October 21,1996, the licensee reported that there has been no

evidence to date of cement erosion from under the basemat. The licensee reported

that: (i) water from the basemat leaching out into the external containment sump

has been monitored monthly for ten years and there has been no evidence of slurry

in the effluents; (ii) although there have been no program in place to systematically

monitor the settlement of the containment building, the recent inspections

performed under procedure ENG 1.7-147 (as part of the Maintenance Rule) found

no evidence regarding concrete settlement nor any indications of degradation of the

concrete slab.

c.

Conclusions

,

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The inspector confirmed during routine inspection tours of plant areas and

structures that there were no obvious signs of slurry in the discharged from the

j

external sump, or of settlement in the containment structure. No inadequacies were

'

identified.

E2.5 Soent Fuel Pool Coolina System Sinale Failures (URI 96-11-07)

a.

Inspection Scope (37551)

On October 22,1996, the licensee issued ACR 96-1239 to describe an

inconsistency in the licensing basis for the spent fuel pool cooling system (SFPCC).

The ACR noted that the current design of the SFP cooling pump pown supplies

'

does not support the bases for Technical Specification 3/4.9.15, which states that

" single failure considerations require that both spent fuel pool cooling pumps are

OPERABLE." Both SFP pumps are powered from a Train A electrical sturce. The

ACR was written to evaluate the condition prior to the mode of applicat,ility for TS

3/4.9.15 (Mode 6 during transNr of fuel to the spent fuel pool for a full core

offload).

.

The inspector completed a walkdown of the spent fuel cooling system and

associated power supplies, and reviewed the design basis and licensing basis as

described in PDCR 1592, UFSAR Section 9.1, the safety evaluations and licensing

1

submittals in support of Amendment No. 7 (June 8,1976) and Amendment No.

188 (January 22,1996), SEP Topic IX-1 for spent fuel storage and, the CMP

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position paper " Spent Fuel Pool Cooling System Redundancy / Single Failure

Capability (draft). The inspector reviewed normal operating and emergency

procedures for spent fuel pool cooling.

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b.

Observations and Findinas

SFPCS Desian Details

The SFPCS consists of two non-safety related pumps which provide forced cooling

through two heat exchangers. The A pump has a 40 hp motor and a capacity of

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610 gpm; the B pump has a 60 hp motor and a capacity of 620 gpm. The A (shell

and tube) heat exchanger has a heat capacity of 6.2 MBtu/hr; the B (plate) heat

exchanger has a heat capacity of 20 Mbtu/hr.

l

The SFPCS alignment for normal operation (NOP 2.10-1) is to use one SFP cooling

]

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pump with the A SFP heat exchanger, and for refueling operations (full core offload)

is to allow one or both SFP pumps operating with the B heat exchanger. Both the A

and B SFP pumps are powered from 480 V MCC-2, which is a non-class 1E power

]

supply. MCC-2 has two subsections which are physically located adjacent to each

!

other, but are electrically separate. SFP pump P21-1 A is connected to subsection

MCC2-4, which is powered from Bus 4; pump P21-1B is connected to MCC2-5,

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which is powered from Bus 5. Both 480 volt Bus 4 and Bus 5 are part of the A

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train electrical division.

The A electrical division receives normal power from the 115 KV electrical

distribution system via line 1772, transformer T389 and Bus 1-2. During a LNP

condition, the SFP cooling pumps would be load shed on loss of power, and manual

operator action is required to restart a pump to restore cooling. The A train

emergency diesel generator, EG-2A, can be used to provide emergency power to

Bus 4/5 and MCC2. The licensee recently installed a non-class 1E, air cooled

diesel, EG-7, to meet SEP concerns for tornados; this power supply can be operated

I

manually and connected to 4160 volt Bus 1-2, and thereby power the A electrical

division.

Oriainal and Modified Licensina Basis

The SFPCS design when the plant was first licensed included one SFP pump and

one heat exchanger. Thus, no considerations for single failures were included in the

original design. The SFPCS design was modified in support of Amendment 7 to add

the second pump (P21-1B) and heat exchanger (E10-1B). Although redundancy

was added for the pumps (active components in the SFPCS), the design relied on a

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single heat exchanger (plate) to remove the heat of a full core offload. While the

thermal analysis for both Amendment 7 and 188 demonstrated the cooling system

was adequate for a worst case heat load and assuming a loss of one SFP pump,

there was no change to the electrical distribution system or to the single electrical

,

train dependency.

UFSAR Section 9.1 (March 1996) describes the SFPCS but does not provide design

!,

details on the electrical supplies. UFSAR Figure 9.1-1 does show that both SFPC

pumps are powered from MCC2. The licensee submittals in support of Amendment

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1. 188 do not describe the electrical system details. The licensee stated that 1996

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rerack project did not change the electrical design or the design basis of the SFPCS,

and thus there was no reason to address this detailin support of Amendment #188.

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The licensing basis provided clear references that equate single failure

!

considerations to the loss of one of the SFP cooling pumps. Examples from the

licensee's March 31,1995 letter (B15136) in support of Amendment #188 include:

(i) page 9, third paragraph "The analysis determined that the cooling system has

sufficient capacity to maintain bulk pool temperature at or below 150F for any

postulated discharge scenario including the single active failure of the most efficient

pool cooling pump"; (ii) page 17, third paragraph "The pool will not exceed 150F

during the worst single failure of a cooling pump"; and, (iii) safety evaluation page

5-5 and Figures 5.4.2,59.2 through 5.8.4 " sing le active failure: one SFP cooling

pump left running."

Desian Calculations - Thermal Analyses

The licensee analyzed the SFPCS capability by calculating decay heat loads per the

NRC's standard review plan (SRP) BTP ASB9-2 and evaluating three discharge

scenarios, allinvolving a full core offload at the end of the final cycle of plant

operations. Decay heat load calculations were conducted for Amendmerts 7 and

188 to assess the adequacy of the spent fuel pool cooling system to handle the

heat with the racks fully loaded to the maximum capacity (1172 and 1480.

respectively). The calculations were performed using conservative assumptions that

would minimize heat removal capabilities, and discharge scenarios that would

maximize the heat input to the pool. The Amendment #188 analyses were

performed for three scenarios: Scenario 1 - normal EOC full core offload with two

pumps aligned to the plate heat exchanger; Scenario 2 - EOC full core offload, with

i

a single active f ailure; and, Scenario 3 - BOC emergency full core offload after the

last plant operating cycle (this case evaluates more fuel assemblies than can be

stored in the pool) with two pumps aligned to the plate heat exchanger. The river

temperature assumed for the Amendment #188 analyses was 90 F.

For scenario 2, the analysis started with a SFPCS configuration of one pump aligned

to the plate heat exchanger, assuming the failure of the redundant pump. The

maximum SFP temperature was limited to 150F, and the analysis determined what

incore decay Vme was required on tne discharged fuel to assure this limit would be

met. The requi ed minimum in-core hold times were calculated for different service

water temperatures - 90F, 85F, 80F, and 75F. The analyses showed that the

SFPCS capacP.y with one pump and the plate heat exchanger in operation was

sufficient to limit pool temperatures to 150F for the assumed in-core hold times

4

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prior to discharge. The only single failure assumed in any of the licensing basis

analyses was one of the two SFPCS pumps.

The licensee also analyzed the time to boil under emergency conditions in which the

heat exchanger assisted forced pool cooling becomes unavailable for any reason.

This analysis was also conservative and assumed the pool was at the maximum

allowed temperature of 150F when cooling was lost and the maximum heat load

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was present. The calculated minimum time from loss of cocMg to pool boiling was

just over 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> (7.09) with a maximum boil-off (required mak."p) rate of 47 gpm.

The analysis showed that if no action were taken to replenish the pool inventory,

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the time to fuel uncovery was about three days (68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br />).

The licensee has the capability to make up to the SFP from either the RWST or the

fire water Eystem powered by a diesel fire water pump. In the S3icty Evabation

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dated 1/22/93, the NRC found that the contingency plan of cooling the pool by

allowing the poo! to boil and adding makeup water in the event of a complete loss

of cooling met the guidance of SRP 9.1.3, and was therefore acceptable.

Desian Versus Actual Heat Loads

The inspector compared the actual maximum heat loads against the conservative

l

assumptions used in the licensing basis thermal analyses. For Amendment #188,

,

the licensee demonstrated that the SFPCS was sufficient to handle a worst case

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heat load of 22.4 X 10+ 6 Btu /hr, which assumed a full core offload at the end of

plant life in 2007 with all 1480 storage locations filled. The present pool plus core

{

inventory is (862 + 157 =) 1019 spent fuel assemblies. This numb.tr when placed

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in the tool is less than the previous analyzed (licensed) limit of 11. 72; thus, the past

licensing basis thermal analysis is still bounding.

Howevor, using the Amendment 188 analyses, the assumed rever temperature was

90F; the actual temperature in October 1996 is about 55F, and the river is cooling

.

down. The minimum core residency time in the analysis was assumed to be about

7 days prior to discharge to the pool. The reactor was shut down on July 22,

1996, and as of November 1 the fuel has decayed for 116 days. The estimated

i

combined heat load of the core and the old fuelin the SFP is now less than 5.6 X

10+ 6 Btu /hr, which is within the capacity of either the plate or the shell heat

exchanger operating with a single SFP pump. The time to boilin the spent fuel pool

prior to core offload was 252 hours0.00292 days <br />0.07 hours <br />4.166667e-4 weeks <br />9.5886e-5 months <br />, which decreased to about 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> with all

'

1019 fuel assemblies in the pool.

Abnormal Operatina Procedures

The licensee has contingency plans to mitigate a loss of SFP cooling. Blind flanges

are installed in the SFPCS piping at the inlet and outlet of the heat exchangers that

could be used with diesel powered pumps to provide continued forced cooling;

however, this method is no longer credited. AOP 3.2-59 provides several methods

for supplying alternate cooling and providing makeup to the pool. The licensee has

recently demonstrated the capability to implement compensatory measures to

provide alternate service water cooling to the SFPCS heat exchangers. Emergercy

procedure 3.1-10 provides direction for the operator to power MCC2 from B

electrical train Bus 7. This would be accomplished by manipulating 480 volt

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breakers in the A switchgear room. The inspector estimated through interviews and

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a walk through of the procedure that the contingency could be implemented in less

than 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The licensee has used this lineup in the past during plant outages.

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The existing instructions in EOP 3.1-10 (revision 17) would provide B train power to

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P21-1 A. The EOP further directs the operator to request technical support to

process a bypass jumper to power P21-1B from the P21-1 A breaker with jumper

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cables. A bypass could be used to provide A or B train power to P21-1B either

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locally at MCC2, or at the pump. Finally, the licensee prepared a change to the

EOPs to provide a method to provide B train power to P21-1B without the use of

2

jumpers (by using 480 volt breaker manipulations to bring Bus 7 power to Bus 5 via

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MCCS).

The inspector concluded that, despite the single train vulnerabilities inherent in the

as-built SFPCS design, there were multiple power supplies for the A train electrical

system, as well as several viable methods to provide alternative power feeds to the

SFPCS from the B electrical distribution system.

Clarified Licensina Basis - Sinale Failure Criteria

l

The licensee issued a change to the bases of TS 3/4.9.15 under 10 CFR 50.59

(reviewed by PORC), that clarified the intent of the licensing basis. The revised

bases (TS Clarification Sheet C-TSC-072 dated 10/23/96) defined that the

requirement to have both SFP cooling pumps operable provides backup capability in

l

the event that an operating pump fails. This action was completed to address ACR

96-1239 prior to entry into Mode 6.

l

The NRC Safety Evaluation dated January 22,1996 issued in support of

Amendment #188 contains wording that tends to broaden the single failure features

,

intended by the design or the licensee submittals. In particular, in Section 2.2 on

page 5, second paragraph, the SER states..."Three scenarios were evaluated: end-

,

of-cycle with full core offload, end of cycle and single active failure in the SFPCS,

i

and an emergency core offload..." Again, in Section 2.2 on pages 5-6, last

paragraph states..."Results of the revised analysis also indicate that in order for the

SFPCS to maintain the pool water temperature at or below 150F during refueling

with a full core offload and a single f ailure in the SFPCS, it is necessary to impose a

fuel handling delay time after shutdown..." Further, the bases for TS 3/4.9.15

suggests that redundant pump operability would require redundant power supplies.

c.

Conclusions

The SFPCS was not designed to perform its functier under any postulated single

f ailure, and relied on a single electrical distribution system (Train A). The SFPCS

was designed to provided adequate cooling for a full core offload, assuming the loss

of one of the two spent fuel pool cooling pumps. The licensing basis did not

represent that the SFPCS was single failure proof in support of license Amendments

1. 7 and #188; however, the licensing basis lacks details regarding the electrical

power supply for the SFPCS, and it is not clear that the electrical system

vulnerabilities were recognized during the licensing reviews for Amer.cn.ents #7 and

1. 188.

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The licensee has emergency procedures in place that provide alternate methods to

provide power to the SFPC pumps from the train B electrical system; further

procedures were changed to provide additional alternate methods. The licensee has

evaluated the complete loss of spent fuel cooling and has shown that event can be

successfully mitigated. This matter is considered unresolved pending further review

of this issue by NRR and NRC management to determine whether any new

information is present that warrants further licensing action (UNR 96-11-07).

E2.6 Refuelina Boron Concentration

a.

Inspection Scone (37551)

The inspector reviewed licensee evaluations of the minimum reactor coolant system

boron concentration needed to assure the minimum shutdown requirements of

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Technical Specification 3.9.1 were met.

'

b.

Observations and Findinas

The Core 20 design analyses to support the use of higher enriched reactor fuelin

operating cycle 20 required the refueling boron concentration be 2400 ppm in the

reactor coolant system. The licensee determined that a lower boron concentration

was needed to meet shutdown margin requirements for end of operating cycle 19

.

conditions, taking credit for fuel burnup. The licensee left the new higher enriched

fuel for cycle 20 stored in the new fuel storage vault due to the pending decision

,

regarding the permanent shutdown of Haddam Neck. The results of the engineering

j

evaluation were documented in a memorandum dated October 8,1996 (NE-F-339).

j

The licensee determined that a boron concentration of 1370 ppm would ensure the

Mode 6 core multiplication factor would be less than 0.94 under all rods out

conditions, and less than 0.89 with all rods inserted. The analysis also assured

acceptable results were obtained for a postulated boron dilution event.

.

c.

Conclusions

The licensee established an acceptable administrative limit on RCS minimum boron

concentration of 1400 ppm. No inadequacies were identified.

E7

Quality Assurance in Engineering Activities

E7.1

Missed Commitments

a.

Insoection Scoce

The inspection scope evaluated the apparent causes and potential safety impact of

missed commitments to a previous NRC violation and deviation.

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b.

Observations and Findinas

in early November,1996, the licensee informed the inspector that two of four

commitments in response to a violation and deviation in inspection report 50-

213/96-04 were not completed within the time frame documented to the NRC. The

licensee's commitments were identified in a letter to the NRC on August 21,1996.

The two commitments that were not completed:

1)

A comprehensive review of the inadequate safety evaluation that allowed for

a sling attachment to the fuel handling tool in the spent fuel pool to be

completed by October 31,1996

2)

A maintenance department revision to a on-the-job (OJT) training guide to

require verification of physical qualification of crane operators by September

30,1996.

The cause for missing the commitments was that no internal assignment was made

to complete these actions, and the licensing person assigned to initiate the

assignments was inexperienced. Notwithstanding these apparent causes, two of

the four commitments were completed by the licensee's responsible departments

initiation of an internal assignment.

For the first commitment, the licensee has subsequently initiated a safety evaluation

and proposed UFSAR change to allow fuel handling activities in the spent fuel pool

without the use of a sling.

The inspector confirmed that part of the second commitment had been completed

by revising procedure work u qtrol manual (WCM) 2.2-9 on August 28,1996,

however one OJT guide for the containmert polar crane had yet to be completed.

,

The inspector verified that the OJT guides for the turbine building, RCA yard crane

had been completed by September 30,1996. The inspector also confirmed that

containment polar crane operators during the current shutdown met the physical

requirements of ANSI B 30.2.

At the end of the inspection, the licensee was completing actions to complete the

corrective actions associated with the notice of violation in inspection report 50-

213/96-04 with the initiation of an adverse condition report. The failure to

implement two commitments within the time frame provided did not constitute

additional violations of NRC requirements, but were examples of ineffective actions

to avoid future violations or deviations. The inspector will evaluate licensee actions

during review of open items 96-004-02 and 96-004-03.

c.

Conclusions

Licensee failed to implement two commitments in response to a violation and a

deviation due to less than adequate internal assignment development and

inexperience personnel in the licensing organization.

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E8

Miscellaneous Engineering issues (92902)

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E8.1

(Open) URI 96-01-03: RVLIS Desian Basis

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Previous inspection

in NRC Inspection 96-01 the inspectors reviewed the methods used by the licensee

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to bypass a sensor in the RVLIS system and also reviewed the technical and safety

!

evaluations to justify the continued use of the affected RVLIS channel.

I

During operating cycles 18 and 19 sensors #6 and #8 on the"A" RVLIS probe had

]

become inoperable and were bypassed, in December 1995 sensor #7 on the same

,

probe showed erratic indication. At that point it was the last operable sensor in the

)

area between the top of the fuel and the top of the hot leg nozzle. Subsequent

investigations and repairs resulted in the restoration of all but sensor #6 to

operation prior to plant restart.

However, the licensee noted during a review for a potential bypass for sensor #7

that although the RVLIS train would remain operable within the technical

specification requirements, the lack of any RVLIS indication in the lower plenum

area at the area of the inlet and outlet nozzles would degrade technical assessment

capabilities following postulated accident conditions. The inspectors concluded that

the matter required further licensee review to determine whether the technical

specifications as written were adequate.

The inspectors found that the affected channel was operable in accordance with the

plant technical specification requirements and that the modifications were

adequately addressed in the emergency operating procedures. However, the issue

was unresolved pending further licensee review to: (i) assure the methods to

bypass inoperable RVLIS sensors provides a conservative level indication; and, (ii)

assure the present licensing basis is adequate to maintain RVLIS fully functional for

intended uses under design basis conditions.

Current inspection

During the current inspection the inspectors reviewed the status of the RVLIS

system and licensee actions regarding inoperable sensors.

The inspectors reviewed the operating experience associated with the system and

the process for addressing sensor failures. The period reviewed was from 1992 to

'

the present. The inspector found that the system had a significant number of

sensor failures up to the time that the probes were replaced in 1993. The initial

probes had individual cables for each of the 8 sensors and some of the failures

resulted with cable and/or connector problems. The model probes that were

installed in 1993 have a single cable and connector design and there is currently

only one failed sensor (sensor #6 in the "A" probe).

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48

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Operation with failed sensors was controlled primarily through the use of bypass

'

jumpers. The bypass jumper process provides controls for the performance of

technical and safety evaluations to support the bypassing of failed sensors. The

'

.

inspectors reviewed safety evaluations associated with several bypass jumpers and

l

found that the safety evaluations were detailed and included an evaluation of

'

specific emergency operating procedure (EOP) changes that would be implemented

i

as a result of the failed sensors. The bypass jumper, the safety evaluation and

'

procedure changes are reviewed by the Plant Operations Review Committee

i

(PORC). The licensee personnel interviewed indicated that normally all of the

documents are presented to PORC at the same meeting and that there is not a

'

significant delay in implementing the necessary procedure changes. The inspector

'

noted that on February 5,1992, bypass jumper 92-010 was written to address the

failure of sensors 1 A,6A,6B,7B, and 8B. The safety evaluation was completed by

engineering on February 10,1995. The bypass jumper and associated safety

>

evaluation were approved for implementation by PORC on February 11,1992. The

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refueling was completed and critical operations resumed in March 1992.

i

On June 14,1996, a technical specification clarification for the RVLIS system was

'

approved by the PORC. The TS requires that at least three of the lower six sensors

(plenum region) be operable and one of the two upper sensors (upper head) be

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operable to consider the RVLIS channel to be operable. The clarification specified

i

that of the six lower sensors at least one of sensors 6,7, or 8 be operable for the

'

channel to be considered operable. The verticallocation of sensors 6,7 and 8 are at

the centerline of the hot leg nozzle, at the bottom of the hot leg nozzle and just

above the top of the fuel, respectively. The inspector noted that if sensors 7 and 8

i

were inoperable and sensor 6 was operable the RVLIS channel may not provide any

useful indication of core coverage depending on where the postulated pipe break

'

was located. For example, if the break was in the hot leg piping, water injected by

the safety injection systems could be lost through the break and level may never

recover to the centerline of the hot leg (i.e. location of sensor 6). The licensee

agreed with this assessment and subsequently revised the TS clarification on

,

September 20,1996, to require that either sensor 7 or 8 be operable to consider a

RVLIS train operable. The inspectors noted that prior to issuance of the TS

clarification, the procedure changes were evaluated on a case-by-case basis

depending on which sensors were inoperable and these evaluations reflected the

approach delineated in the TS clarification.

The licensee indicated that the TS clarification will be considered for incorporation

into TSs if the licensee converts to the improved standard technical specification

format.

The inspector concluded that the licensee had implemented appropriate procedure

changes in response to sensor failures and that the replacement of the RVLIS

probes had improved the reliability of the system. The inspector also noted the

failure of the licensee to identify the inadequacy of the technical specification to be

another example of a weakness in the independent review process. This item

.

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remains open pending final licensee disposition, and NRC review, of the original

issues in unresolved item 50-213/96-01-03 as summarized above.

j

E8.2 (Open) URI 96-02-03: Control Room Habitability

This item was open pending the completion of licensee actions to validate the

i

procedure used to assess control room habitability under degraded plant conditions.

Licensee action on this matter was summarized in a memorandum dated May 14,

,

1996 (HP-96-070). The licensee provided an integrated review of procedure RPM

i

2.3-3, which included participation by health physics, operations, engineering,

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licensing, radiological assessment, and emergency planning groups. Several

i

deficiencies were identified and addressed: a determination that procedure EPlP 15-

31 was the appropriate reference for guidance to monitor the control room

,

radiological environment under degraded plant conditions; improving protective

action guidelines to better protect control room personnel; adding instructions to

evacuate non-essential personnel in order to assure sujficient breathing apparatus

for essential control room personnel; upgrading the scgtt air packs from the current

,

j

Scott lla to the newer 4.5 versions; and, a plan to include.in a subsequent operator

training cycle to have operators wear respiratory equipment during training at the

simulator to demonstrate the ability to safely operate the plant under degraded

conditions.

On September 18,1996, the licensee identified additional discrepancies in the

,

'

assessment of control room habitability, as documented in ACR 96-1063. The

deficiency was identified by the configuration management group during reviews to

upgrade the licensing and design basis for the plant. The licensee found that no

f

calculations existed for the control room dose with the existing as-built ventilation

system, and no calculation existed to support the adequacy of the use of self-

contained breathing supplies to ensure control room habitability during design a

basis accident. This finding highlighted a deficiency in the licensee actions to close

NUREG-0737 Item lli.D.3.4 on Control Room Habitability for both,Haddam Neck and

Millstone 1. This item remains open pending further review by the NRC.

E8.3 (Closed) VIO 94-22-02: AFW Support Loadina

This issue concerned inadequate corrective action that allowed a loss of control of

the seismic qualification of a Auxiliary Feedwater Pump (AFW) piping restraint.

During the installation of a new non-safety grade AFW system and associated

piping CY, engineering personnel identified that the seismic restraint separating the

j

safety grade and non-safety grade AFW piping was in an unanalyzed condition due

i

to omission of two valves in the load analysis. The unanalyzed condition had

existed for about seven days.

Once the condition was identified, immediate action was taken to break the tie

between the operable and the new systems, eliminating the seismic interaction

concerns. The deficiency occurred because the discipline engineer was not involved

in the pre-construction walkdown review of the rnodification. Several previous

,

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Plant Information Reports (PIRs) had identified similar conditions adverse to quality

that involved piping supports that affected the seismic qualification of operable

i

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portions of safety related equipment.

i

CY attributed the cause of the event to a weakness in work controls that did not

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prevent the coupling of non seismically qualified modifications into existing qualified

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piping. The inspector reviewed the root cause evaluation for the event and

!

corrective actions taken which included: procedural changes which included

j

enhancements for performing pre-construction walkdown checklists, and pre-job

briefings. The PIR process was replaced with the Adverse Condition Resolution

'

Program, which promotes increased reporting of events, and conditions adverse to

l

quality to increase the effectiveness of investigation and corrective actions and

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allows screening of past events to reveal similarities and past corrective actions

I

taken. Based on the review of the completed actions, this item is closed.

!

E8.4 Review of LERs MO 96-11-08, eel 96-11-09 eel 96-11-10)

!

a.

inspection Scope (92700,90712)

i

The purpose of this inspection was to review licensee event reports (LERs) to verify

the requirements of 10 CFR 50.72 and 50.73 were met.

i

b.

Observations and Findinas

l

LER 96-13, CAR Fan Piping Susceptible to Water Hammer

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This LER concerned the operation of the plant with inoperable containment air

i

recirculation fans. This issue was previously reviewed in inspection 96-08. This

l

item is closed.

LER 96-14, Containment Sump Screens Not Sized as Expected

,

'

This LER concerned the operation of the plant with an inoperable ECCS flow path.

i

This issue was previously reviewed in inspection 96-08. This item is closed.

l

LER 96-16, inadequate RHR Pump NPSH

l

This LER concerned the operation of the plant with an inoperable ECCS flow path

j

and the inadequate assurance that the RHR pumps would perform their design

,

i

function under design basis bccident conditions. This issue was previously

reviewed in inspection 96-08. This item is closed.

LER 96-19, Pin Hole Leak on RHR Heat Exchanger. Valve

i

This LER concerned the discovery of degraded conditions in the RHR system. The

issue was previously reviewed in inspections 96-10 and 96-80, and in Section 02.1

above. This item is closed.

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LER 96-20, Fuel Transfer Tube Bellows Not Tested

!

This LER concerned the discovery that a containment piping penetration had not

i

been tested as required, as was previously reviewed in Inspection 96-08. This

.

event is similar to another deficiency identified in the containment leakage rate

l

program, as describe in LER 96-28 below. This item is closed.

LER 96-21, Valve Leakage Results in Nitrogen Intrusion

This LER concerned plant operation in Mode 5 with a nitrogen bubble in the reactor

head, as was described in inspections 96-80 and 96-10. This item is closed.

LER 96-22, RCS Loop Stop Valves Opened Without Timely Sample

,

This LER concerned the failure to obtain a timely boron sample of the reactor

coolant system prior to unisolating the loops, as described in Inspection 96-80.

This LER is closed.

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LER 96-24, B RHR Pump inoperable

This event involved the discovery on September 1,1996 that the B RHR pump was

i

in operable. The licersee root cause evaluation was completed on September 23,

which concluded that the pump had been inoperable since it was last run on August

19, and failed on shutdown at that time. The pump f ailed due to a combination of

original manufacturing defects and a maginal design in the tolerances of internal

components in the rotating element. NRC review of the purnp failure and the NRC

findings relative to the event are provided in Inspection reports 96-80 and 96-10.

The inspector had no further questions regarding the response actions for the event.

The licensee determined on September 24 that the event was reportable per

50.72(a)(2)(i)(B) as operation in a condition prohibited by Technical Specification 3.4.1.4.2, since immediate action to return the pump to service was not taken

during the period from August 19 to September 1. The inspector noted that the

licensee did not know that the B RHR pump was inoperable prior to September 1.

Nonetheless, the event was also reportable to the NRC under another 50.73

reporting criteria.

The B RHR pump was operated intermittently as needed for decay heat removal

'

following the plant shutdown on July 22,1996 until the pump failed when

shutdown on August 19. The design basis for the pump following a design basis

event is to operate for an indefinite period (generally greater than 30 days) in the

long term recirculation mode following a postu;sted loss of coolant accident. Due to

!

the inherent manuf acturing defects and marginal design, the pump was in capable

l.

of performing its design function had the plant experienced a design basis event

,

l

prior to the shutdown on July 22. Thus, the event was reportable under

l

50.73(a)(2)(ii)(B) as a condition that resulted in the plant being operated outside the

j

design basis. The NRC reporting guidance in NUREG 1022, Revision 1 for

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50.73(a)(2)(ii) states (on page 37) that an example of a condition that is reportable

is the discovery that one train of a required two train safety system has been

incapable performing its design function for an extended period of time during

operation. This would be considered operation outside the design basis because for

an extended period of time, the system did not have suitable redundancy.

As such, the failure of the B RHR pump was also reportable to the NRC under 10 CFR 50.72(b)(1)(ii) and a one (1) hour noti'ication to the NRC Operations Center

should have been made when the root cause analysis and reportability reviews were

completed on September 24,1996. The failure to make the required notification

was a violation of 10 CFR 50.72 (VIO 96-11-08).

l

LER 96-26, Weld Flaws in SFP SW Piping

This LER concerned the discovery of degraded pipe and pipe welds in the service

j

water piping supplying cooling to the spent fuel cooling system, as described in

section M.2.2 above. The preliminary root cause evaluation was that a lack of root

weld penetration and poor weld fitup contributed to the weld flaws. A failure

analysis was planned to determine the cause of the weld degradation, and the

results reported in a supplemental LER. The licensee's safety assessment of all

defects concluded that the spent fuel pool cooling function was not compromised.

This LER is closed.

e

LER 96-27, Boron injection Flow Path Below Minimum Temperature

j

During reviews on October 8 to assure plant system readiness to enter Mode 6, a

system engineer identified discrepancies with the temperature instruments (in panel

HT-BA-PNL-A&B) used to perform surveillances per Technical Specification

4.1.2.1.a on the heat traced portion of the baron injection flow path. The

'

instruments are used per TS 4.1.2.1.a to verify that the heat traced portion of the

flow path was above 140 degrees F when a flow path from the boric acid path was

used. The discrepancy was that the temperature instruments had not been subject

to periodic calibration.

The licensee used portable instruments to verify the accuracy of the instruments.

On October 10, the licensee identified certain locations in the boron injection flow

path in which the temperatures were below the TS required minimum of 140

degrees F, which rendered the associated portions of the boration system

inoperable. The licensee measured temperatures as low as 120 F in the gravity

feed line to the metering pump, and 90 F at the suction of the charging pumps at

the junction of the discharge from the boric acid pumps. This adverse condition

was addressed in ACR 96-1196. The licensee reported this event as plant

operation outside the licensing basis, and past plant operations in a condition

contrary to the technical specifications.

The cause of this event was inadequate desion of control circuits used to monitor

flow path temperatures and energize heat trace circuits as necessary to maintain

..

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minimum temperature. The licensee also failed to provide an adequate surveillance

'

program to assure the instruments relied upon to meet TS requirements were

accurate. The design used heat trace circuits with 9 watts per foot and 6 watts per

foot cable. Temperature detectors used to energize the heat trace circuits were

located near the high power heat trace cable, which also controlled the low power

circuits. Further, the licensee found that the temperature detectors were not placed

in the optimum locations that would assure the coolest portions of the circuit

remained above the 140 F limit. Finally, the event indicated ineffective corrective

action in response to inspection item 93-01-01, in that the licensee took action to

assure that instruments used to satisfy TS surveillance requirements were

periodically calibrated. The actions at that time failed to identify the present

deficiencies.

The purpose of the heat trace circuits was to assure the fluid in the boron injection

flow path remained above the solubility temperature and thus preclude precipitation

of the high concentration (as high as 22,500 ppm) boric acid. Despite the

i

deficiencies in the heat trace circuit design and calibration, the affected flow paths

l

remained operable as demonstrated by a recent test (SUR 5.1-146 in August 1996)

l

and operations that passed water through the associated piping. This discrepancy

I

had no impact on analyzed accidents. UFSAR Section 15.2.3 describes the

licensee's analysis of the inadvertent boron dilution event. The accident analyses

only credits the use of alarms and monitors to detect the dilution and then manual

operator action to terminate the event prior to the loss of shutdown margin. Thus,

the safety consequences of the boric acid heat trace discrepancy was low.

The licensee took actions to: (i) assure a boration flow path was operable per TS 3.1.2.1 for operation in Mode 5 and 6 (the flow path from the refueling water

storage tank was used); (ii) restore the gravity feed flow path to an operable status

prior to core offload operations by replacing the higher wattage cables with low

wattage cable; and (iii) revise procedures to enhance the periodic monitoring of heat

trace circuits with hand held digital probes.

Plant operation with heat trace circuits in the boron injection flow path less than

140 degrees F was contrary to Technical Specification 3.1.2.1 and 3.1.2.2. (eel

96-11-09).

LER 96-28, Containment Air Lock Hydraulics Not Leak Rate Tested

During a review of a proposed modification of the containment personnel air lock

!

hydraulic system, the licensee identified on October 16 that penetration CN-2 did

j

not meet the requirements of 10 CFR 50 Appendix J and had never been Type B

'

'

leak rate tested. The licensee reported this event as a condition that would have

j

resulted in the plant operating in an unanalyzed condition, and as a condition that

j

alone could have prevented the fulfillment of a safety function needed to mitigate an

l

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accident.

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The hydraulic system penetrates the primary containment boundary as a non-

!

seismic, non-QA system with no isolation provision for penetration CN-2. Although

the hydraulic hoses and seals are tested as part of the air lock Type B test and the

containment Type A test, the oil reservoir was not vented to atmosphere during

those tests and therefore, the past leak rate tests would not have verified the

,

pressure integrity of the hydraulic system. During a postulated design basis LOCA,

i

'

the containment atmosphere pressure would displace the hydraulic fluid through the

inner hydraulic seals and fittings, through the tubing inside the airlock, and then

escape from the containment through the outer mechanical seals and fittings. This

pathway would allow an untreated leakage path of containment atmosphere to the

environment. The licensee's assessment was that this condition had low safety

significance because, although the potential leak path existed, the amount of

leakage would be greatly reduced by the restrictions provided by the components in

the system, the tortuous path for release, and the resistance provided by the

hydraulic fluid.

Section ll.G of 10 CFR 50, Appendix J defines Type B tests as tests intended to

,

measure leakage across leakage limiting boundary for primary reactor containment

penetrations, including piping penetrations. Technical Specification 4.6.1.2

implements the requirements of 10 CFR 50, Appendix J. Technical Specification 4.6.1.2.d states that containment leakage rates shall be demonstrated in

conformance with the criteria in Appendix J of 10 CFR 50, and that Type B tests

shall be conducted at intervals to greater than 24 months and at a pressure not less

that Pa,39.6 psig. The f ailure to test the containment penetration CN-2 using a

Type B test to measure the leakage is an apparent violation of 10 CFR 50, Appendix

J, and Technical Specification 4.6.1.2.d (eel 96-11-10). The inspector noted that

this violation was similar to the failure to test penetration P-50 (reference inspection

item 96-08-08 and LER 96-20),

c.

Conclusions

The events reported by the licensee provided additional examples of discrepancies

in the design and licensing basis, deficiencies in translating the licensing basis into

practice, in reduced margins for shutdown operations and SFP cooling, inadequate

reporting of plant events, and ineffective corrective actions.

1

i

IV. Plant Support

i

S1

Conduct of Security and Safeguards Activities

a.

inspection Scope

The inspector reviewed the security program during the period of

September 23-26,1996. Areas inspected included: effectiveness of management

control; management support and audits; protected area detection equipment; alarm

.

.

.

55

stations and communication; testing, maintenance and compensatory measures;

and training and qualification. The purpose of this inspection was to determine

whether the licensee's security program, as implemented, met the licensee's

commitments and NRC regulatory requirements.

b.

Observations and Findinas

Management support is ongoing as evidenced by the timely completion of the

vehicle barrier system and the installation of the biometrics hand geometry system

to provide more positive plant access control. Alarm station operators were

knowledgeable of their duties and responsibilities, security training was being

performed in accordance with the NRC-approved training and qualification plan and

. the training were well documented and available for review. Management controls

for identifying, resolving, and preventing programmatic problems were effective and

noted as a programmatic strength.

Protected area (PA) detection equipment satisfy the NRC-approved physical security

plan (the Plan) commitments and security equipment testing was being performed

as required in the Plan. Maintenance of security equipment was being performed in

a timely manner as evidenced by minimal compensatory posting associated with

non-functioning security equipment, and maintenance documentation weaknesses

noted during the previous inspection had improved.

c.

Conclusions

The inspector determined that the licensee was implementing a security program

that effectively protects public health and safety. Weaknesses noted during the

previous inspection, conducted in October 1995,in the area of training and

maintenance documentation, had been corrected.

S2

Status of Security Facilities and Equipment

S2.1

Protected Area Detection Aids

a.

Inspection Scope

The inspector conducted a physical inspection of the PA intrusion detection systems

(IDSs) to verify that the systems were functional, effective, and met licensee

commitments.

b.

Observations and Fir'd;nac and Conclusions

On September 23,1996, the inspector determined by observation that the IDSs

were functional and effective, and were installed and maintained as described in the

Plan.

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56

S2.2 Alarm Stations and Communications

a.

inspection Scoce

Determination whether the Central Alarm Station (CAS) and Secondary Alarm

.

Station (SAS) are: (1) equipped with appropriate alarm, surveillance and

'

communication capability, (2) continuously manned by operators, and that (3) the

systems are independent and diverse so that no single act can remove the capability

,

of detecting a threat and calling for assistance, or otherwise responding to the

threat.

l

b.

Observations. Findinas and Conclusions

Observation of CAS and SAS operations verified that the alarm stations were

equipped with the appropriate alarm, surveillance, and communication capabilities.

Interviews with CAS and SAS operators found them knowledgeable of their duties

and responsibilities. The inspector also verified through observation and interviews

that the CAS and SAS operators were not required to engage in activities that

would interfere with the assessment and response functions, and that the licensee

had exercised communications methods with the locallaw enforcement agencies as

committed to in the Plan.

S2.3 Testina, Maintenance and Compensatorv Measures

a.

Insoection Scope

Determination whether programs were implemented that will ensure the reliability of

security related equipment, including proper installation, testing and maintenance to

replace defective or marginally effective equipment. Additionally, determination

whether security related equipment failed, the compensatory measures put in place

was comparable to the effectiveness of the security system that existed prior to the

j

failure.

)

b.

Observations and Findinas

Review of testing and maintenance records for security-related equipment confirmed

that the records were on file, and that the licensee was testing and maintaining

systems and equipment as committed to in the Plan. During the previous inspection

conducted October 2-6,1995, severalinstances were identified where equipment

had been repaired for months, but the maintenance documentation needed to close

out the work request had not been completed. The inspector determined based on

a review of security equipment maintenance records, including open work requests,

and discussions with security mandgement, that actions taken to address the

'

problem were effective. A priority status was assigned to each work request and

repairs were normally being completed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from the time a work

request, necessitating compensatory measures, was generated.

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@

c.

Conclusions

{

Security equipment repairs were being completed in a timely manner and

!

maintenance documentation problems were corrected. The use of compensatory

I

measures was found to be appropriate and minimal.

S5

Security and Safeguards Staff Training and Qualification

l

a.

Insoection Scope

!

Determination whether members of the security organization were trained and

I

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qualified to perform each assigned security related job task or duty in accordance

I

with the NRC-approved training and qualification (T&O) plan.

i

b.

Observations and Findinas

.i

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The inspector selected at random and reviewed the training, physica., and firearms

'

qualification /requalification records of ten security force members (SFMs).

l

During the previous inspection, conducted October 2-6,1995, the inspector noted

i

several training records which had anomalies, involving lapses in SFM certification,

!

for which there were no clear explanations recorded. Some files contained an

I

,

explanatory memorandum indicating that the lapse was due to an extended period

l

of leave, but few were dated, or contained details. To address the concern, the

!

training department reviewed the documentation process and took appropriate

4

action. No unexplained anomalies were identified during the inspector's review of

'

the randomly selected training records. Additionally, the inspector interviewed a

number of SFMs to determine if they possessed the requisite knowledge and ability

<

to carry out their assigned duties.

t

j

c.

Conclusions

j

4

The inspector determined that the training had been conducted in accordance with

the T&O plan, and that it was prop.erly documented. Based on the SFMs responses

to the inspectors' questions, the training provided by the security training staff was

,

effective.

S6

Security Organization and Administration

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a.

Inspection Scope

I

A review of the level of management support for the licensee's physical security

j

program was conducted.

'

,

b.

Observations and Findinas

The inspector reviewed various program enhancements made since the last

'

inspection, which was conducted in October 1995, with security management.

,

These enhancements included the timely completion of the vehicle barrier system

installation, procurement and installation of the hand geometry /biometrics system to

r-

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provide more positive plant access, installation of new closed circuit monitors in the

CAS/SAS to improve observation of PA barrier, and the allocation of monetary

j

resources for additional training initiatives and improvements. Additionally, the

{

inspector reviewed shift rosters, organizational charts, and payroll records to

,

determine if the security force was adequately staffed and if SFM's were working

excessive hours due to low manning. The inspector determined based on the

results of the document reviews and discussions with licensee and contractor

]

supervision, and SFMs that manning levels were adequate and overtime was being

properly controlled.

i

c.

Conclusions

Management support for the physical security program was determined to be

]

excellent.

j

.

S7

Quality Assurance in Security and Safeguards Activities

I

S7.1 Effectiveness of Manaaement Controls

a.

Insoection Scope

A review of the licensee's controls for identifying, resolving and preventing -

programmatic problems was conducted,

b.

Observations and Findinas

The inspector determined that the licensee had controls for identifying, resolving,

and preventing security program problems. These controls included the

performance of the required annual quality assurance (QA) audits, a formalized self-

assessment program, and ongoing shift oversight by supervisors. The licensee also

utilized industry data, such as violations of regulatory requirements identified by the

NRC at other facilities, as a criterion for self-assessment.

,

c.

Conclusions

A review of documentation applicable to the programs indicated that initiatives to

minimize security performance errors and identify and resolve potential weaknesses

were being implemented and were effective.

I

i

S7.2 Audits

!

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a.

Inspection Scope

i

The inspector reviewed the licensee's audit of the security program to determine if

the licensee's commitments as contained in the NRC-approved physical security

plan were being satisfied,

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b.

Observations and Findinas

i

The inspector reviewed the 1995 QA audit of the security program conducted

l

between September 6 - November 1,1995, (Audit No. A25109). The inspector

l

determined that the audit was conducted in accordance with the Plan and that the

'

I

results were distributed to appropriate levels of management. The audit identified

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three findings, two unresolved items and one recommendation. The audit findings

addressed potential weaknesses in record retention, lock and key control and key

card record accountability. The inspector determined that the noted findings were

not indicative of programmatic weaknesses or noncompliance with regulatory

requirements, but would enhance program effectiveness. The inspector also

determined, based on discussions with security management and a review of the

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responses to the findings, that the corrective actions were effective.

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c.

. Conclusions

The review concluded that the audit was comprehensive in scope and depth, that

the findings were approp iately distributed and that the programs were being

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properly administered.

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F2

Status of Fire Protection Facilities and Equipment

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F2.1

Fire Protection Svstem Valve Flanae Cracks

a.

Inspection Scoce

The inspection scope was to evaluate licensee compensatory actions in response to

fire suppression system corrective maintenance.

b.

Observations and Findinas

On October 18,1996, maintenance mechanics were replacing fire system valve FP-

V-123. During the torquing of the fasteners for the threaded cast iron flange, the

flange cracked. The licensee replaced the cast iron flange and restored the fire

header back to service on October 22,1996. The inspector noted that the

mechanics were not provided any specific guidance on the maximum torque

specification for the cast iron flange.

On October 21, the inspector confirmed tag clearance 96-1011 provided adequate

isolation and protection to the workers in the fire protection system. Additionally,

the inspector confirmed that the licensee was appropriately implementing

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compensatory measures in the technical requirements manual sections ll.1.C.3.1.a,

and ll.1.g.3.1.

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c.

Conclusions

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The inspector noted that mechanics were not provided. specific guidance on the

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maximum torque for fasteners on a threaded cast iron flange. Appropriate technical

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requirements manual compensatory actions were taken.

V. Manaaement Meetinas

X1

Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management

at the conclusion of the inspect lon on November 27,1996. The licensee

acknowledged the findings presented.

The inspectors asked the licensee whether any materials examined during the

inspection should be considered proprietary. No proprietary information was

identified.

X4

Review of Updated Final Safety Analysis Report (UFSAR)

A recent discovery of a licensee operating its facility in a manner contrary to the

UFSAR description highlighted the need for a special focused review that compares

plant practices, procedures, and parameters to the UFSAR description. The

inspector reviewed licensee activities for conformance with the UFSAR as described

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in Sections 15.5.2.2 (detail M1.2) and Section 9.1 (detail E2.5). Discrepancies in

meeting Section 15.5.2.2. are described in detail M1.2 above.

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Since the UFSAR does not specifically include security program requirements, the

inspector compared licensee activities to the NRC-approved physical security plan,

which is the applicable document. While performing the inspection discussed in this

report, the inspector reviewed Section 6.8 of the Plan, Revision 30, dated February

29,1996, titled, " Keys, Locks, Combinations, and Related Equipment" and

performed an inventory of the key storage cabinets using the licensee's lock and

key control procedure. The review disclosed that security keys and locks were

being maintained and controlled in accordance with the Plan and security program

procedures.

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PARTIAL LIST OF PERSONS CONTACTED

Licensee

Jere LaPlatney, Unit Director

Gerry Waig, Maintenance Manager

Jack Stanford, Operations Manager

James Pandolfo, Security Manager

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Ron Sachatello, Radiation Protection Manager

Tom Cleary, Sr. Licensing Representative

George Townsend, Engineering

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Robert McCarthy, Engineering

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David Bazinet, Instrumentation and Controls

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D. Parker, Safety Analysis

M. Kai, Safety Analysis

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Madison Long, Technical Support

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NRC

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Stephen Dembek, Haddam Neck Project Manager

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INSPECTION PROCEDURES USED

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IP 40500:

Effectiveness of Licensee Controls in Identifying, Resolving, and Proventing

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Problems

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iP 60710:

Refueling Activities

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IP 62703:

Maintenance Observation

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IP 64704:

Fire Protection Program

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IP 71707:

Plant Operations

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IP 73051:

Inservice inspection - Review of Program

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IP 73753:

Inservice inspection

IP 83729:

Occupational Exposure During Extended Outages

IP 83750:

Occupational Exposure

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IP 92700:

Onsite Followup of Written Reports of Nonroutine Events at Power Reactor

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Facilities

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IP 92902:

Followup - Engineering

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IP 92903:

Followup - Maintenance

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IP 93702:

Prompt Onsite Response to Events at Operating Power Reactors

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ITEMS OPEN, CLOSED, AND DISCUSSED

Open

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96 11 01

eel

Failure to Have EOP for Fuel Drop Accident

96 11-02

eel

ineffective Corrective Actions for Inventory Control

96-11-03

eel

Inoperable SFB Ventilation System

96-11-04

eel

Inadequate instrument Setpoint Calculations

96-11-05

eel

inadequate Conective Actions for Instrument Failures

96-11-06

eel

inadequate PAB flood Protection

96-11-07

URI

SFPCS Single Failures

96-11-08

VIO

Inadequate Reporting of RHR Pump Failure

96 11-09

eel

Inoperable Boric Acid Heat Trace Instruments

96-11-10

eel

Containment Penetration Not Type B Tested

Closed

96-04-01

URI

May 23 Spent Fuel Event

95-02-03

IFl

Refueling Equipment Failures

94-22-02

VIO

AFW Supports

Discussed

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96-02-03

URI

Control Room Habitability

96-01-03

URI

RVL!S Design Basis

93-01-01

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Instrument Calibrations

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ATTACHMENT A

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Procedures Revised

'ODI 190, RCS Inventory in Modes 5 and 6

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'ODI-193, Pre-Evolution Briefings

'NOP 2.611, Makeup to RCS During Modes 5 and 6

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ODI-191, Shutdown Risk Awareness

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ANN 4.24-1, Cavity High Level

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ANN 4.24-2, Cavity Low Level

ANN 4.24-3, Reduced Inventory Low Level

ANN 4.24-4, Ultrasonic Low Level

• NOP 2.6-12, Draining the RCS in Modes 5 and 6

NOP 2.6-1 A, Mode 5 or Mode 6 RCP Seal Water Supply

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'NOP 2.6-98, Recirculation of 1B Charging Pump on the RWST

AOP 3.2 31 A, Reactor Coolant / Refueling Cavity Leak

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NOP 2.3-5, Refueling Operations

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NOP 26-2, Chemical and Volume Control System Operation

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WCM 1,2-9, Outage Planning, Scheduling, and Implementation

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WCM 2.2-8, Control of Heavy Loads

WCM 2.2-7, PAB/ Pipe Trench Floor Block Lifting Procedure

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NOP 2.0-1, Shift Relief and Turnover

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NOP 2.0-2, Shift Supervisors Operating Log

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NOP 2.3-4, Shutdown from Hot Standby to Colo Shutdown

NOP 2.9-3, Refueling Cavity Filling

NOP 2.13 5A, Tracking / Establishing Modified Containment Integrity / Containment Closure

' AOP 3.2-63, Fuel Handling Accident

AOP 3.2-31 A, Reactor Coolant System Leak / Refueling Cavity Leak (Mode 5 and 6)

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-indicates new procedures

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1

LIST OF ACRONYMS USED

ACP

Administrative Control Procedure

ACR

Adverse Condition Report

AEC

Atomic Energy Commission

AEOD

Office for Analysis and Evaluation of Operational Data

ALARA

As Low As is Reasonably Achievable

ANN

Annunciator Response Procedure

ANSI

American National Standards Institute

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AOP

Abnormal Operating Procedure

ASME

American Society of Mechanical Engineers

AWO

Authorized Work Order

CAR

Containment Air Recirculation

CAS

Central Alarm Station

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- cfm

cubic feet per minute

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CFR

Code of Federal Regulations

CLIS

Cavity Level Indication System

CMP

Corrective Maintenance Procedure

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CVCS

Chemical and Volume Control System

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CY

Connecticut Yankee

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CYAPCo

Connecticut Yankee Atomic Power Company

EA

Escalated Action

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EDG

Emergency Diesel Generator

ENG

Engineering Procedure

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EOP

Emergency Operating Procedure

f

EP

Emergency Preparedness

EPIP

Emergency Plan Implementing Procedure

ESF

Engineered Safety Feature

F

fahrenheit

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gpm

gallons per minute

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HECA

High Efficiency Charcoal Air

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HEPA

High Efficiency Particulate Air

I&C

Instrument & Control

,

IDP

Ingersol Dresser Pump

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IDS

Intrusion Detection Systems

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IPAP

Integrated Performance Assessment Process

IR

Inspection Report

IRT

Independent Review Team

ISI

in-Service Inspection

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LER

Licensee Event Report

LLRT

Local Leak Rate Testing

MOV

Motor Operated Valve

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MTE

Measuring & Test Equipment

NOP

Normal Operating Procedure

NCV

Non-Cited Violation

NOV

Notice of Violation

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NRC

Nuclear Regulatory Commission

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NSO

Nuclear Side Operator

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ODI

Operations Department instruction

OJT

On the Job Training

PA

Protected Area

PAB

Primary Auxiliary Building

PIR

Plant Inspection Report

PMP

Preventive Maintenance Procedure

PORC

Plant Operations Review Committee

PORV

Power Operated Relief Valve

ppm

parts per million

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PPR

Plant Performance Review

psig

pounds per s quare inch

QA

Quality Assurance

RCS

Reactor Coolant System

RHR

Residual Heat Removal

{

RFO

Refueling Outage

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RPWST

Recycle Primary Water Storage Tank

RWST

Refueling Water Storage Tank

SAS

Secondary Alarm Station

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SFB

Spent Fuel Building

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SFM

Security Force Members

SFP

Spent Fuel Pool

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SRO

Senior Reactor Operator

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ST

Special Test Procedure

SUR

Surveillance Procedure

SW

Service Water

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T&Q

Training and Qualification

TPC

Temporary Procedure Change

TRM

Technical Requirement Manual

TS

Technical Specification

UFSAR

Updated Final Safety Analysis Report

VIO

Violation

VP

Vendor Procedure

WCC

Work Control Center

WCM

Work Control Manual

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