IR 05000220/1993018

Insp Repts 50-220/93-18 & 50-410/93-18 on 930808-0918. Violation Noted.Major Areas Inspected:Plant Operations, Maint & Surveillance Activities,Engineering & Plant Support, W/Regard to Radiological & Chemistry Controls & Security

ML20057G330
Person / Time
Site:	Nine Mile Point
Issue date:	10/01/1993
From:	Larry Nicholson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20057G326	List: IR 05000220/1993018 ML20057G325 ML20057G327
References
50-220-93-18, 50-410-93-18, NUDOCS 9310210313
Download: ML20057G330 (21)

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U.S. NUCLEAR REGULATORY COMMISSION-

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REGION I

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LJ ni Report Nos.:-

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93-18"

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/Dbeket Nos.:

50 220

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50-410-

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Licensee:

. Niagara Mohawk Power Corporation

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-301 Plainfield Road

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Syracuse, New' York ' 13212 l

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Nine Mile Point, Units 1 and 2

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i Location:

. Scriba, New York

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August 8 through September 18,1993 l

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B. S. No.rris, Ser.ior ~ Resident Inspector

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R." A. Plasse, Actir 3 Senior Resident inspector

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-W F.lMattingly, Resident inspector i

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1 Approved by:

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T2rryf/. Nici otson, Chief D

Reac#r Projects Section No.1 A

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Division of Reactor Projects

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9310210313)931012i

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Nine Mile Point Units 1 and 2

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NRC Inspection Report Nos. 50-220/93-18 & 50-410/93-18

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e 08/08/93 - 09/18/93

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PLANT OPERATIONS c

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Both_ units operated essentially at full power throughout the period. Unit 1 operators performed well during a momentary loss _ of offsite power (Section 2.3). ' Also in Unit 1, operators and the

'g fire brigade responded quickly to 'a fire in the auxiliary control room, and maintenance affected repairs and returned the relay cabinet to service within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (Section 2.4). An unresolved

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item was opened pending the inspector's review of the fint.1 root cause analysis (URI 50-210/93-

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'18-01). Unit 2 operations, maintenance, and engineering staff responded well to the loss of the division II emergency switchgear caused by keying a radio. NMPC intends to modify a previous c e

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. LER on a similar event to include this finding (Section 2.2).

MAINTENANCE i

. Maintenance and surveillance activities observed and work packages reviewed by the inspectors

were determined to be satisfactory. Both units were continuing with preparations forinstallation

of a reactor vessd level reference leg backfill system, their actions to address this safety concern i

L appeared appropriate (Section 3.1.1). For Unit 2, an unresolved item was' identified concerning i

a'Icakage path in both standby ps treatment charcoal adsorber beds (URI 50-410/93-18-02).'

ENGINEERING

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NMPC identified four primary containment isolation valves that were inoperable due to improper l-local leak rate testing. Since the licensee identified the problem and took immediate-and

adequate corrective action, the NRC is not citing this violation (Section 4.2).

'w PLANT SUPPORT l

A visiting industry representative accompanied a plant operator into a locked high radiation area without signing on to a radiation work permit. The individual realized the mistake and reported

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'it to radiation protection. Since the licensee took prompt and effective corrective action before i

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allowing the individual back'into the plant, the NRC is not citing this violation (Section 5.1).

- The inspector identified a failure of NMPC to exercise proper escort responsibilities for a visitor

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in the protected area (Section 5.2). This is a violation of the 10 CFR 73 and the site security plan.. NMPr' conducted a thorough determination of the primary and contributing causes of the l

event, and the corrective actions were considered appropriate for the event. Based on the timely

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/and ' complete actions by NMPC, no response is necessary. (VIO 50-410/93-18-03)

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DETAILS

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6, L1.0 SUMMARY OF FACILITY ACTIVITIES j

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1.1 - LNiagara Mohawk Power Corporation Activities -

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- The Niagara Mohawk Power Corporation (NMPC) safely operated Nine Mile Point Unit 1 (Unit

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.1) and Unit 2 (Unit 2) at essentially full power throughout the period.

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- 4 1.2 NRC Activities c

(Resident _ inspectors conducted inspection activities during normal, backshift and weekend hours

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over this period. There were 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> of backshift (evening shift) and 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br /> of deep

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~ backshift (weekend,' holiday, and midnight shift) inspection during this period.

2.0 PLANT OPERATIONS (71707,90712,93702)*

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Operational Safety Verification -

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The inspectors observed overall plant operation and verified that the licensee operated the plant

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F regular tours of the following plant areas:

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' * Reactor Building Control Building

• Control Room '

Access Control Points

• ; Turbine Building 7

• ; Switchgear Rooms

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Diesel Generator Rooms i

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* Service Water Bays

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• -Protected' Area Perimeter -

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p The inspectors observed plant conditions through control room tours to verify proper alignment

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of engineered safety features;.to verify that operator response' to alarm conditions was in

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accordance with plant operating procedures; to verify compliance with Technical Specifications,

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. including implementation of appropriate action statements for equipment out of service; and to l

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review logs and records to' determine if entries were accurate and identify equipment status or j

deficiencies. These records included operating logs, turnover sheets, and system' safety tags.

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The inspectors conducted detailed walkdowns of accessible areas to inspect major components Tand systems for leakage, alignment, lubrication, cooling water supply, and general conditions

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7 hat might preventifulfillmentJof their. safety function.

The. inspector observed ' plant

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housekeeping controls ~ including control and storage of flammable material and other potential safety hazards.

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The NRC. inspection manual' procedure or temporary instruction that was used as

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inspection guidance is listed for each applicable report section.

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i The inspector found that shift turnovers.were comprehensive and aceurate, and adequately

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< reflected plant activities and status.

Control room operators effectively monitored plant

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- operatin'g conditions and made necessary adjustments. Housekeeping was commensurate with ongoing work. The inspector concluded that NMPC conducted overall plant operations in a safe and conservative manner.

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2.2 Loss of Power to Safety-Related Switchgear

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. On August 17, Unit 2 experienced a loss of power to the division II emergency switchgear. At the time of the event, the under and degraded voltage surveillance test, N2-OSP-ENS-M001, was in progress. The emergency diesel generator (EU 3) backup to the bus was not available due L

to previous preplanned maintenance. Unit 2 operators, system engineers, and maintenance F

. personnel responded well to the event. After determining that no fault existed on the bus, the operating crew reenergized the bus from its normal offsite supply.

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- A similar event occurred during the same surveillance test on January 5 (refer to LER 93-01).

NMPC conducted extensive troubleshooting to determine the root cause of the recent' event.

NMPC believes the probable cause of the August trip to be a spurious actuation of the under

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voltage relay 81-2ENSY13 caused by the keying of a radio in clore proximity of the 81 relay.

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NMPC completed the following corrective actions to improve he surveillance testing and prevent reoccurrence.

A procedure change was initiated to require the associated EDG to be available as a

. prerequisite to the monthly under voltage test.

Radios have been quarantined from the switchgear rooms.

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The inspector reviewed LER 50-410/93-01, the recent troubleshooting plan, and NMPC's conclusion.. NMPC considered the recent event not reportable for an engineered safety feature

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actuation because the EDG was out-of-service and the under voltage signal was invalid. The inspector reviewed 10 CFR 50.72 and agreed with NMPC's determir.auon.

NMPC troubleshooting for the January event determined the root cause to be the failure of an optical isolator. Based on the recent troubleshooting findings, it appears NMPC needs to clarify the original root cause for the January event. NMPC agreed with this observation and plans on l

issuing a supplement to LER 93-01.

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2.3 Momentary Loss of Offsite Power at Unit 3 During a severe thunderstorm on August 31,1993, two concurrent lightning strikes caused a

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momentary and simultaneous loss of both Unit 1 115kV offsite power lines (#1 from the South L

- Oswego-station and #4 from the Lighthouse Hill station). This momentary loss of offsite power

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- (LOOP) resulted in the deenergi7ation of safety buses 102 and 103 and the non-safety bus 101.

Emergency diesel generators. (EDGs) 102 and 103 automatically started on the sensed undervoltage and loaded to supply power to their respective safety buses as designed. The

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deenergization of bus 101 resulted in the associated loss of reactor recirculation pump (RRP) 13

(1 of 5,RRPs). The loss of RRP 13 reduced reactor power from 98% to 87%, due to the decrease in recirculation flow and subsequent void formation in the core.

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The Unit I technical support staff's Deviation Event Report (DER) investigation concluded that

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two concurrent lightning strikes on the 115kV offsite power lines initiated the event. A lightning strike between the site and the South Oswego station (12 miles west of the site) tripped breaker RIO, thus isolating line #1 from Unit 1. A separate lightning strike near the Lighthouse Hill station (26 miles east of the site) tripped the feed breaker at Lighthouse Hill, thus isolating Unit l

1 from line #4.

After approximately.12 seconds, the feed breaker at Lighthouse Hill

automatically closed, reenergizing line #4 to Unit 1.

Line #1 to Unit I was reenergized approximately 27 seconds later. - A total of 39 seconds elapsed before Unit I regained both

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offsite power lines, j

i The inspector entered the control room shortly after the LOOP and observed portions of the plant stabilization, entry into the emergency plan, and plant restoration. Throughout the event

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t the operators responded properly to the changing plant conditions, used the proper normal and emergency operating procedures, and demonstrated good command, control, and communications

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skills. Restoration of the plant to a normal configuration was well conducted.

Following the plant recovery, NMPC management initiated a DER to investigate the LOOP, and

conducted a post-event critique with the crew to assess crew performance and the overall plant response. Based on the critique, several operator and emergency plan implementation strengths and areas for improvement were identified. The inspector considered this process constructive

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In summary, the inspector concluded the following: the plant responded to the LOOP as designed, the operations staff responded excellently to the event, and the technical support staff thomaghly reviewed and determined the cause for the event.

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2.4 Fire in the Unit 1 Auxiliary Control Room

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On September 17, the Unit 1 Control Room received a fire alarm for the Auxiliary Control Room. The on-shift operators and the fire brigade responded, and had the fire out in less than

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ten minutes; fire damage was minimal. The fire was in the Peactor Manual Control System (RMCS) cabinet. The Station Shift Supervisor reviewed the Emergency Plan and determined

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that no emergency ac. ion levels were exceeded. The operators deenergized the associated relay cabinet. Three significant functions were lost as a result of deenergizing the cabinet: (1) HCU j

accumulator pressure and level alarms in the control room; (2) " All Rods In" lights at the remote

shutdown panel; and (3) all manual rod control. The Resident Inspector was notified and a

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courtesy' call was made to the NRC Duty Officer.

The accumulator alarms and the "All Rods In" lights are Technical Specification requirements, each with a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LCO (Limiting Condition for Operations) action statement. Two separate

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temporary modifications were developed and approved to provide power until the relay cabinet was returned to service. The loss of manual rod control became the limiting condition. The TS require that all partially or fully withdrawn control rods be exercised at least weekly. The

, weekly sur, :illance was scheduled to be performed on Saturday morning; the 25% grace period allowed by the TS extended the time until Sunday at 7:00 pm. If manual rod control was not

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restored.within the allowed time frame, the licensee would have been forced to shut down Unit 1.

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The Auxiliary Control Room is located directly beneath the Control Room and houses relay

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cabinets for various control and protective systems. The faulty relay, General Electric type CR-120, was part of the rod control selection circuit. This relay is used extensively in the plant.

Senior NMPC management responded to the site, along with electrical and I&C maintenance staff.

Maintenance worked continuously until completing repairs late Saturday afternoon,

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replacing six relays. Post-maintenance testing included functional testing of all relays in the cabinet. In addition, they performed thermography and compared the results to earlier tests.

The cabinet was returned to service late Saturday, the temporary modifications were removed, and the rod exercise surveillance was performed satisfactorily. The inspector monitored portions of the maintenance activity and reviewed the completed repair and testing packages and concluded that the Unit staff responded appropriately and that the maintenance staff performed admirably and completed repairs expeditiously.

The licensee is performing a root cause analysis for this event. The issue is unresolved pending the inspector's review of the final root cause analysis report. (URI 50-220/93-18-01)

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3.0 MAINTENANCE (62703, 61726, 90712)

3.1 Maintenance Observations - Units 1 and 2 The inspectors observed maintenance activities to ascertain if safety related activities were being conducted according to approved procedures, technical specifications, and appropriate industrial codes and standards. Observation of activities and review of records verified that: required administrative authorizations and tag outs were obtained, procedures were adequate, certified i

parts and materials were used, test equipment was calibrated, radiological requirements were implemented, system prints and wire removal documentation were used, and quality control hold points were established. Maintenance activities observed included:

N2-MPM-GEN-V559, inspection and Cleaning of Reactor Building Area Cooler 413A

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N2-EMP-GEN-510, Clean and Regrease RHR A Full Flow Test Return Valve N2-EPM-GEN-V536, Static VOTES Test on 2SWP*MOV74C

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WO 93-02043-00, Inspect and Top Off Charcoal Adsorber Filter Bed 2GTS*FLTIB l

WO 93-4518, Repair Fire Damage to Control Rod Drive System

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The above activities were effective with respect to meeting the safety objectives.

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3.1.1 Reactor Vessel Instrumentation Reference Leg Backfill Recent operating experience at boiling water reactors (BWRs) has shown that non-condensible gases may become dissolved in the reference leg of reactor water level instrumentation. The dissolved gases accumulate over time in the water level instrumentation reference leg. When reactor pressure is reduced, the gases can come out of solution displacing water from the reference leg. This reduces the pressure on the reference leg side of the reactor vessel water level transmitters, and can lead to a false high level indication. The NRC issued Bulletin 93-03 on May 28,1993 which required licensees to implement hardware modifications necessary to ensure the level instrumentation system design is of high functional reliability.

The inspector reviewed NMPC's bulletin response dated July 28, 1993, and resiewed the planned schedule for nodification completion. Unit 2 began pre-outage installation of the

reference leg backfill :,ystem and plans to complete the modification during the refuel outage scheduled for October 1. Unit 1 also began pre-outage installation activities (modification N1-93-010) for a reference leg backfill system. These activities involve the components from the initial filter through the tubing outside the level instrument rooms. The remaining installation:

connection to the control rod drive piping, installation work inside the level instrument rooms, and acceptance testing will be completed during the first available cold shutdown outage of sufficient duration. The inspector concluded that NMPC's actions to address this nfety concern appeared appropriate. The inspector will continue to monitor NMPC's installation activities.

3.1.2 LERs and Special Repods

LER 50-220/93-03, Supplement 2 - Failure of primary containment penetration X-154 to meet local leakrate test (LLRT) leakage limit at Unit 1.

This LER was reviewed during inspection report 93-03/93-02 and documented the condition where reactor water cleanup isolation valves failed to pass their LLRT leakage limit. Subsequent to their initial review, NMPC identified a design deficiency as the cause for the failure of the outboard isolation check valve 33-03.

Based on this additional information NMPC initiated a plant change request to change the design of check valve 33-03. NMPC plans to complete this design change by the end of the next refueling outage scheduled for 1995. This LER is closed.

LER 50-410/93-05 - Failure to perform proper local leak rate test on several primary

containment isolation valves in the hydrogen recombiner system at Unit 2.

l This event was reviewed and discussed in section 4.2 of this inspection report. The inspector assessed that the LER contained the information required by 10 CFR 50.73 and that NMPC implemented good corrective action to prevent recurrence of the event. This

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LER is closed.

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Unit 1 Special Report Dated September 10,1993 - The inspector reviewed s special

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- appendix 10A, Fire Hazards Analysis, section 2.5.2.3, Fire Pumps. The 30-day special report discussed the inoperability of the fire suppression water supply pumps (one motor driven and one diesel driven), either of which is normally capable of meeting the maximum fire demand flow. Two 30 gpm motor driven fire jockey pumps maintain normal fire suppression system water pressure. On August 11, both fire suppression water pumps were removed from service to allow necessary corrective maintenance on the fire jockey pumps. The inspector assessed that the special report contained the information required by the fire hazards analysis and clearly defined the cause of the event and corrective actions to prevent recurrence.

3.2 Surveillance Observations - Units 1 and 2 Through observation of safety-related surveillance activities, interviews, and review of recorde, theinspectors verified: use of proper administrative approve, personnel adherence to procedure

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

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

Surveillhnee activities observed included those listed and discussed below:

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N2-OSP-ENS-M001,4.16 kV Emergency Bus Under and Degraded Voltage Functional Test N2-RSP-GTS-R@001, Testing and Analysis of Unit 2 Standby Gas Treatment System N2-ISP-SVV-R102, Safety Relief Valve Acoustic Monitoring Position Indication Calibration

- The above activities were effective with respect to meeting the safety objectives.

3.2.1 Assessment of Torus Wall Thickness Measurements

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In~ August, NMPC completed ultrasonic thickness measurements at selected torus wall bottom mid-bay _ locations. The inspector reviewed the test data for the nie thinnest bays, and determined the average wall thickness measured for the bays did not exvwd the minimum wall thickness of 0.447 inches. This data appeared consistent with the previous measurements taken in January 1993.

3.2.2 Bypass ' Leakage Path in Both Standby Gas Treatment System Charcoal Adsorbers On September 8,1993, the Unit 2 standby gas treatment (GTS) system charcoal adsorber, 2GTS*FLTIB, failed the TS required surveillance for in-place penetration and bypass leakage.

TS 4.6.5.3.b.1 requires less than 0.05% bypass leakage; however, subsequent evaluation of the

surveillance results indicated that GTS train B adsorber leakage was 1.13% (equivalent to

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adsorber efficiency of 98.87%). This surveillance is performed every 18 months. The

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surveillance measures charcoal adsorber bypass leakage by introducing a known quantity of freon

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test gas at the charcoal adsorber inlet and measuring the outlet test gas concentration using a gas chromatograph. The freon gas is chosen based on its affinity for charcoal and its detectability.

The inlet and outlet concentrations are then ratioed to determine adsorber bypass leakage.

Each charcoal adsorber is comprised of several parallel mesh compartments that contain the activated charcoal and establish a nominal 4" charcoal filter bed through which the GTS system air flow must pass. A common reserve bed of charcoal (normally 6" deep) is maintained on top of the charcoal filter beds to compensate for any settling of the charcoal. NMPC's initial investigation of the surveillance failure revealed that a portion of one charcoal filter bed, and

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an adjacent portion of the charcoal reserve bed, had been displaced to a corner of the reserve

- bed. NMPC subsequently added charcoal to the filter bed, raised the reserve bed charcoal level c

to the vendor recommended height, retested the adsorber satisfactorily, and declared GTS train B operable on September 9.

On September 10, NMPC inspected train A and found similar, but less severe, conditions in one charcoal filter bed. Charcoal was added to the filter bed and reserve bed, the adsorber was

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tested satisfactorily, and the train declared operable.

On September 16, NMPC preliminarily concluded that the same failure mechanism caused the degradation of both GTS charcoal adsorbers and reported the condition to the NRC as required by 10 CFR 50.72. They believed that both adsorbers had inadequate reserve bed levels which allowed a less restrictive air flow path through the reserve bed instead of through the filter bed.

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This condition eventually eroded the charcoal filter beds to the point of unsatisfactory bypass I

leakage. They also concluded that GTS train A would most likely have failed its bypass leakage test even though the previous adsorber bypass leakage tests and monthly GTS train operability checks for both GTS trains were satisfactory.

This issue is unresolved pending completion of NMPC's root cause evaluation, offsite dose assessment, and determination of generic implications for other charcoal adsorbers used on site.

(URI 50-410/93-18-02).

4.0 ENGINEERING (37700, 40500, 71707, 90712)

4.1 Review of Licensee Event Reports and Special Reports The inspector reviewed the following licensee event report (LER) to verify that it conformed to the requirements specified in 10 CFR 50.73 and the Technical Specifications.

These requirements include a proper narrative description of the event, the cause of the event, an assessment of the safety consequences, and corrective actions.

LER 50-410/93-03 - Eleven manual vent, drain, and test valves on Unit 2 primary

containment penetrations of the residual heat removal system and the reactor core isolation cooling system were not verified to be closed at least once per 31 days. An

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inadequate preparation of the original surveillance procedure during the pre-startup phase contributed to this condition; i.e., the eleven valves were not included in the surveillance procedure. This condition was identified by NMPC during a comprehensive review of

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, their 10 CFR 50 Appendix J program. The inspector considered the LER satisfactory.

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4.2 Improper Tewing of Containment Isolation Valves On August 4 at 4:15 p.m., NMPC Unit 2 declared four primary containment isolation valves (PCIVs) inoperable. They discovered that four containment hydrogen recombiner (HCS) inboard isolation valves were local leak rate (LLRT) tested in the direction opposite from which they

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would be expected to perform their safety function. The Technical Specification limiting condition of operation (TS LCO) 3.6.3.a.2, requires the valves to be restored to operable status within four hours or the associated penetrations be isolated by means of a deactivated operable valve. The four inboard valves are located inside primary containment and cannot be leak tested during power operations. In addition, deactivating the outboard operable valves would render the HCS inoperable. Since the penetrations could not be isolated in accordance with the TS,

~ NMPC declared an Unusual Event and commenced a TS required shutdown at 8:15 p.m.

' NMPC 'equested the NRC to consider exercising enforcement discretion from the LCO. To r

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support continued plant operation, NMPC proposed that the outboard valves not be deactivated, but instead be maintained closed by administrative control. The NRC staff granted the

_ enforcement discretion for NMPC to operate in the proposed configuration. At 10:52 p.m., Unit 2 was in compliance with the enforcement discretion; the compensatory actions included tagging closed the HCS outboard isolation valves and briefing the oncoming operations shift of the administrative controls in plare. NMPC terminated the unusual event at that time and the plant was returned to full power.

t NMPC completed safety evaluation 93-073, concluding that the power supply breaker for the outboard HCS isolation valves would be accessible in a post-accident condition, and that the

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resulting radiation dose received by the operators would be within regulatory limits. Based on

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this conclusion, NMPC declared the HCS operable with the outboard PCIVs deactivated. On-August 11 NMPC deactivated th'e power supplies for the four HCS ouscard PCIVs, which brought Unit 2 into compliance with TS 3.6.3.a.2.

The inspectors independently reviewed the issue, including the history and design of the valves.

During the construction phase in 1986, engineering determined that, due to system head losses,.

the four HCS inboard isolation valves needed to be changed from globe valves to flexible disc gate valves. The modification was completed and the valves were properly leak rate tested by

. ressurizing between the valve gates. In September 1987, NMPC issued the LLRT surveillance p

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test for use. The LLRT test method for the four inboard HCS valves required pressurization between the inboard and outboard isolation valves. This test method was appropriate for the

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- original globe valves, but was non-conservative for the installed flexible disc gate valves. This error resulted in the four HCS valves being improperly tested between 1988 and the present.

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- 10 CFR 50, Appendix B, Criterion XI, Test Control, requires that measures be established to assure that applicable test procedures dc;nonstrate that components will perform satisfactory in service. The failure to properly LLRT the four HCS inboard isolation valves is a violation of

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P 10 CFR 50, ' Appendix B, Criterion XI. In that the licensee identified the problem and took

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10 CFR'50, Appendix C, VII.B.2.

5.0 PLANT SUPPORT (71707,90712)

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. Radiological and Chemistry Controls During routine tours of the accessible areas at both units, the inspectors observed the implementation of selected portions of NMPC's radiological controls program to ensure: the utilization and compliance with radiological work permits (RWPs), detailed descriptions of

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radiological conditions, and personnel adherence to RWP requirements. The inspectors observed-adequate controls for access' to various radiologically controlled areas (RCA) and use of personnel monitors and frisking metheds upon exit from these areas. Posting and control of radiation areas, contaminated areas and hot spots, and labelling and control of containers holding rad'eactive materials were verified to be in accordance with NMPC procedures. Radiation

- protection technician control and monitoring of these activities was satisfactory. Overall, the inspector observed an acceptable level of performance and implementatior of the radiological controls program; however, one, issue was identified which is discussed below:

Improper Personnel Entry Into the Radiologically Controlled Area (RCA)

On August 2,1993, a representative from the nuclear industry self-identified an improper personnel entry into the RCA and a locked high radiation area (HRA) without signing into a radiation work permit (RWP). The representative was accompanying a non-licensed equipment operator on rounds in the turbine building for the purpose of becoming familiar with plant equipment and layout. During the course of their rounds an entrance was made into a HRA and

- the representative did not have the required alarming dosimetry for this entry. Upon exiting the

- RCA the representative realized the error and immediately reported it to radiation protection.

Technical Specification 6.12.1 states that entrance into high radiation areas, greater than 100 mrem /hr, shall be barricaded and conspicuously posted as a high radiation area and entrance thereto shall be controlled by use of a RWP. Individuals permitted to enter such areas shall be provided with, or accompanied by, one or more of the following:

A radiation monitoring device which continuously indicates the radiation dose rate in the

area.

A radiation monitoring device which continuously integrates the radiation dose rate in the

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area and alarms when a pre-set integrated dose is reached. Entry into such areas with u

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this monitoring device may be made after the dose rates in the area have been established e

and personnel have been made knowledg'eable of them.

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- An individual qualified in radiation protection, with a radiation dose rate monitoring device, who is responsible for providing positive control over the activities within the P

area and'shall perform periodic radiation surveillance at the frequency specified by the l Manager Radiation Protection or designated on the Radiation Work Permit.

NMPC determined the root cause of this event to be a failure of multiple barriers, including:

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training, verbal communication, work practices, and managerial methods. The inspector reviewed the completed root cause evaluation and discussed the corrective actions taken to u

. prevent: reoccurrence with plant management. NMPC did not identify any other similar

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occurrences by other. personnel.'

NMPC's corrective actions included revoking the representative's RCA access pending satisfactory retraining in radiological work practices. In addition, radiation protection standdown meetings were conducted by all site departments to review the event and to improve adiation protection work practices. Safety significance was minimal in that although the representative failed to meet the HRA entry requirements-the equipment operator accompanying the representative had signed in on an RWP'and had the proper dosimetry monitoring device.

The inspector concluded that NMPC appropriately responded upon the identification of this occurrence.

The is a violation of TS 6.12.1, high radiation area entry requirements. However, in that the licensee identified the problem and took immediate and adequate corrective action, the NRC is

. not citing this violation in accordance with 10 CFR 50, Appendix C, VII.B.2.

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'5 2 Security and Safeguards

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. Implementation of the physical security plan was observed in various plant areas with.egard to the following: protected area and vital area barriers were well maintained and not co:npk mised;

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isolation zones were clear; personnel and vehicles entering and packages being delivered to the

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protected area were properly searched and access control was in accordance with approved j

licensee procedures; persons granted access to the site were badged to indicate whether they have

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unescorted access or escort authorization; security access controls to vital areas were maintained and persons in vital areas were authorized; security posts were adequately staffed and equipped, security personnel were alert and knowledgeable regarding position requirements, and written procedures were available; and adequate illumination was maintained. Licensee personnel were observed to be properly implementing and follcwing the physical :ecurity plan, with the exception of an improperly. escorted visitor discussed below.

Individual in the Protected Area Without a Reauired Escort During a routine backshift tour on August 3,1993, the inspector discovered a Unit 2 visitor, escort required, in the protected area without an escott. The visitor was unattended for about 10" minutes in the vicinity of the offgas system control panel. The inspector assumed escort C ' -e

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responsibilities for about 15 minutes until the escort returned, then the inspector reported the incident to the SSS. For approximately 25 minutes the visitor was without an NMPC escort.

NMPC initiated a DER and the subsequent investigation determined that a system engineer transferred escort responsibilities to a plant operator in an informal manner. The operator,

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unaware that he was the visitor's escort, left the visitor at the control panel to obtain required N purge data in the charcoal bed room and then assisted another operator with hanging an

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offgas system markup.

NMPC ' performed a formal root cause analysis and determined that inadequate verbal communications allowed an unescorted visitor in the protected area. Specifically, when the

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system engineer turned over the visitor to the operator he used words like "can you watch (iisitor's name) while we (his relief and himself) go to the control room." His assumption was that the operator knew that the visitor needed an escort. However, the operator had not noted

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- the visitor badge and was under the impression that he was only to watch over the offgas system and the visitor. This thought process was also fostered by the casual manner in which the visitor was being treated.

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The = inspector interviewed several persons involved in the event and reviewed the DER

. disposition, root cause analysis, lessons learned transmittal, site stand down briefing paper, and

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the SORC meeting minutes that discussed the event. Based on the above, the inspector concluded that NMPC completed a timely and ' effective determination of the primary and contributing causes of the event. Also, the corrective actions were considered appropriate for

the event and properly addressed prevention of similar events in the future.

The safety significance of this event was low; however, a visitor in the protected area without his required escort is a violation of 10 CFR 73.45(d)(13) and the Nine Mile Point Nuclear Power Station Physical Security Plan, which require that individuals not granted unescorted access will be continuously accompanied by a person who has unescorted access authorization while within the protected area. Based on the timely and complete corrective actions, a response to this

- violation is not necessary. (VIO 50-410/93-18-03)

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5.3 Employee Concerns Program (TI 2500/028)

- The inspector reviewed NMPC's employee concern program as described in NIP-ECA-04, Quality First Program-(QlP) and interviewed the QlP program director.

The inspector

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. determined that NMPC implemented an adequate program for addressing employee safety concerns. Results of the formal review of the program are documented in Attachment A to this j

inspection report.

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.. PREVIOUSLY IDENTIFIED ITEMS (92701)

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. (Closed) Unresolved Items (220/92-24-04) and (410/92-28-04):

U Weaknesses in Corrective Actions

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Inspector review of corrective actions taken for several similar occurrences (partial loss of offsite power and partial loss of feedwater events) determined the proposed corrective actions were narrowly focused and did not address broad corrective actions to prevent event recurrence.

NMPC conducted several independent reviews of the DER system and self-identified several

- recommendations to improve the corrective action / DER program. In addition, QA issues a periodic Corrective Action Summary Report which evaluates the DER process, timeliness and effectiveness.of corrective actions, and compares current performance with results of the previous QA review. The inspector reviewed the corrective action summary report dated May 27, 1993, and determined that the review adequately addressed the effectiveness of the DER program. NRC review of recent events and licensee event reports identified no adverse trends and assessed.NMPC's reviews to be of high quality with appropriate corrective actions to prevent reoccurrence. This item is closed.

(Closed) Unresolved Item (50-410/93-11-01):

Offgas Charcoal Bed Overheatine.

The inspector ideptified that the offgas system. operating procedure did not include recommendations'for preventing, detecting, and extinguishing offgas fires, in accordance with GE Service Information Letters (GE SILS) 150 and 497. The issue of the adequacy of NMPC's review of previous industry experience and the operating procedure were unresolved pending

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inspector review of NMPC's root cause investigation.

' NMPC identified the root cause of the offgas fire to be a failure to utilize lessons learned from

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industry experience gained during water introduction to the offgas hydrogen recombiners during l

- shifting of the steam jet air ejectors. This resulted in excessive hydrogen accumulation

. downstream of the recombiners and caused a low flow isolation. The hydrogen detonation d

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. occurred when operators restore system flow. The nspector assesse t e root cause eva uat on to be thorough and provided the necessary recommendations and corrective actions to prevent recurrence. This item is closed.

(Gosed) Unresolved Item (50-410/92-14 02h MSIV Closure ' Ability Following Loss-of-Coolant-Accident This issue dealt with the ability of the Unit 2 main steam isolation valves (MSIVs) inside the primary containment to stay closed during a containment pressurization following a design basis loss of coolant accident (LOCA).

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NMPC adequately addressed the technical aspects of this issue previously, the issue remained p

Te open pending a change to the operating procedure for the pneumatic nitrogen pressure source to the MSIVs. ' The design contains a non-safety related pressure switch and gauge which

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. monitor the pressure in the nitrogen storage tank, located in the secondary containment, which b

provides the.MSIV operating force. This arrangement would preclude the monitoring of the

b pressure on the nitrogen supply inside the primary containment, should the primary containment

. isolation valves (PCIVs) on the pneumatic supply line to the MSIVs close. To address this the y

operations department changed the procedure (OP-61A) to include a precaution that if the

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pneumatic supply PCIVs close and cannot be reopened, the LCO for inoperable MSIVs should be entered and the appropriate actions taken. Based on the procedure change and other corrective actions already taken, this item is closed.

7.0 MANAGEMENT MEETINGS At periodic intervals and at the conclusion of the inspection, meetings were held with senior station management to discuss the scope and findings of this inspection. Based on the NRC Region I review of this report and discussions held with Niagara Mohawk representatives, it was

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determined that this report does not contain safeguards or proprietary information. NMPC did.

not object to any of the findings or observations presented at the exit meeting.

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ATTACIIMENT A: Employee Concerns Program

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n Attachment A

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' EMPLOYEE CONCERNS PROGRAMS

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PLANT NAME:

. LICENSEE:

DOCKET #

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Nine Mile Point '

Ninhara Mohawk Power Cor_poratian 50-220 & 50410

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. 'NDTE: -

Please circle yes or no if applicable and add comments in the space provided.

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PROGRAM:.

'1.

~ Does the licensee have an employee concerns program?

. Yes

'2.

Has NRC inspected the program?

Report #:

Combined Insoection 50-220/89-21 and 50-410/89-16. dated l

Seotember 15.1989

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.B..

. SCOPE: (Circle all that apply) -

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Is it for:

l a.

Technical? Yes-i

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b.

Administrative? Yes

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c.

Personnel issues 7No (Personnel issues referred to Human Resources l

Department)

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2.

Does it cover safety as weIl as non-safety issues?

Yes i

3.

Is it designed for:

. a.

Nuclear safety? Yes o

b.

' Personal safety? Yes

c.

Personnel issues - including union grievances?

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care turned over to the Human ~ Resources Department)

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Does the program apply to all licensee employees?

.Yes -

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-EMPLOYEE CONCERNS PROGRA.M Attachment A (cont.)-

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5.

Contractors?

Yes

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6.

Does the licensee require its contractors and.their subs to have a similar program?

No (The Q1P Program is discussed during GET given to the contractors.)

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7.

Does_ the licensee conduct an exit interview upon terminating employees asking if they have any safety concerns?

No (Upon termination employees complete a termination checklist which gives the employees the option of completing a Q1P concerns form or a personal interview.)

C.

INDEPENDENCE:

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1.

What is the title of the person in charge?

Q1P Program Director

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2.

Who do they report to?

. Branch Manager Licensing 3.

Are they independent of line management?

Yes.(They report to the General Manager of Safety Assessment,. Licensing, and Training)

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.4.

Does the ECP use third party consultants?

Yes (When applicable utilizes lawyers, QA, or different technical branches)

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5.

How is a concern about a manager or vice president followed up?

Next higher level in chain of command (example Executive VP Nuclear resolves Q1P concerns for General Managers)

D.

RESOURCES:

1.

What is the size of the staff devoted to this program?

One individual 2.

What are ECP staff qualifications (technical training, interviewing training, investigator training, other)?

Q1P Program Director experience expands over 15 years diverse management and technical positions. Various positions held include QA/QC inspector, supervisor and manager, program coordinator independent assessmsnt group, A-2 o

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EMPLOYEE CONCERNS PROGRAM Attachment A (cont.)

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program director INPO, Q1P executive staff, and program director INPO/Q1P licensing.

Technical Training: SNT-TC-1A and ANSI 45.2.6 Level 2 Certifications

. held: Radiography Exaraination, Magnetic Particle testing, Special Processes, Electrical, Visual Inspection 1 through 4, Liquid Penetrant Testing, Solution

Him Testing, Mechanical, Receiving Inspection, Quality Control / Visual.

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interview Training: Completed management development training course L

" Interviewing for Fact Finding".

Investigator Training: HPES Training and Simple Root Cause Training.

t E.

REFERRALS:

1.

Who has followup on concerns (ECP staff, line management, other)?

Company lawyer for discrimination concerns.

Technical concerns addressed by the deficiency event report system which includes onsite safety review committee review of resolutioru.

F.

CONFIDENTIALITY:

1.

Are the reports confidential?

Yes 2.

Who is the identity of the alleger made known to?

ECP staff-3.

Can employees be:

a.

Anonymous? Yes l

b.

Report by phone? Yes (Site phone number 343-1172 and 1-800 phone number listed in city telephone book for Q1P Program)

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FEEDBACK:

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Is feedback given to the alleger upon completion of the followup?

Yes (Discussed openly person-to-person)

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EMPLOYEE CONCERNS PROGRAM Attachment A (cont.)

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Does program reward good ideas?

By nature of. concern,- can't reward individual without jeopardizing confidentiality. Licensee has an Employee Recognition Program, however, no example, where Q1P concerns have been advertised for recognition.

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3.

Who, or at what level, makes the final decision of resolution?

ECP validates corrective actions, Branch Manager is responsible for DER resolutions, Executive VP Nuclear Generation is responsible for resolution of

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concerns specific to the Q1P Program.

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4.

Are the resolutions of anonymous concerns disseminated?

F To the Senior Management Team which includes the Executive VP, Plant Managers and General Manager Site Support and Safety Assessment, Licensing and Training.

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5.

Are resolutions of valid concerns publicized (newsletter, bulletin board, all hands meeting, other)?

Examples of concerns and management buy-in for the program publicized periodically in weekly newsletter.

II.

EFFECTIVENESS:

1.

How does the licensee measure the effectiveness of the program?

1)

Compares ratio of NRC concerns /Q1P concerns.

2)

Benchmark other utilities.

3)

Monitor plant areas which identify concerns (throughout the plant is effective, localized would mean not all departments utilize the process).

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2.

Are concerns:

a.

Trended? Yes b.

Used? No (There have been no specilic trends identified)

3.

In the last three years how many concerns were raised?

Of the concerns raised, how many were closed?

What percentage were substantiated?

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EMPLOYEE CONCERNS PROGRAM Attachment A (cont.)

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4.

How are followup techniques used to measure effectiveness (random survey,

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interviews, other)?

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Approximately a year and a half ago a survey was provided to the site

population. ECP periodically meets in small group sessions with the plant staff. Periodic discussions at morning meetings and Individual interviews.

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5.

How frequently are internal audits of the ECP conducted and by whom?

Last internal audit conducted (Audit Report 91-25) during July 1991 by L

NMPC Internal Audits. Internal Audits reports directly to NMPC Chief Executive Officer (CEO).

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ADMINISTRATION / TRAINING:

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Is ECP prescribed by a procedure? Yes NIP-ECA-04, Quality First Program (QIP)

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2.

How are employees, as well as contractors, made aware of this program (training, newsletter, bulletin board, other)?

General Employee Training Bulletin Boards, conspicuous signs in plant, and in weekly newsletter ADDITIONAL COMMENTS:

(Including characteristics which make the program especially effective, if any.)

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Senior Management Endorsement of the Program.

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2.

. Accountability and resolution of concerns is the responsibility of the organization that the concern effects.

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NAME:

TITLE:

PHONE #:

DATE COMPLETED:

. Richard Plasse Resident Inspector G15)342-4042 8/26/93 A-5 C