ML20141G921

Insp Rept 50-271/97-04 on 970420-0531.Violations Noted.Major Areas Inspected:Operations,Engineering,Maint & Plant Support

ML20141G921
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	07/07/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20141G915	List: ML20141G912 ML20141G916 ML20141G921
References
50-271-97-04, 50-271-97-4, NUDOCS 9707110312
Download: ML20141G921 (61)

See also: IR 05000271/1997004

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I t

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Docket No. 50-271

Licensee No. DPR-28

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Report No. 97-04

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Licensee: Vermont Yankee Nuclear Power Corporation '

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l Facility: Vermont Yankee Nuclear Power Station

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l Location: Vernon, Vermont l

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Dates: April 20 - May 31,1997  ;

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! Insp'.sctors: William A. Cook, Senior Resident inspector  !

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Edward C. Knutson, Resident inspector  !

Edward B. King, Physical Security inspector

George W. Morris, Reactor Engineer

l Approved by: Curtis J. Cowgill, Ill, Chief, Projects Branch 5 l

Division of Reactor Projects t

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9707110312 970707

PDR ADOCK 05000271

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EXECUTIVE SUMMARY

Vermont Yankee Nuclear Power Station

NRC Inspection Report 50-271/97-04

This inspection included aspects of licensee operations, engineering, maintenance, and

plant support. The report covers a six-week period of resident inspection. In addition, it

includes the results of physical security inspections by a physical security specialist and a

regional reactor engineer.

Operations

A reactor scram occu red from 100 percent power due to personnel error while performing

local power range inonitor calibration, when two average power range monitor channels

were inapproprittely taken out of bypass while they were set to zero power. This failure

to adhere to the calibration procedure was contrary to Technical Specification 6.5 and was

a cited violation. Operator response to the transient was very good and, with some minor

exceptions, plalt response was normal. The licensee concluded that the root causes of

this event were pemennel errors in the areas of work practices and communications.

Immediate and long-term corrective actions appeared to have adequately addressed the

identified weaknesses. (Section 01.1)

Following completion of a nine-day maintenance outage, the subsequent plant startup and

return to full power operation was well controlled. (Section 01.2)

A weekly surveillance revealed that oxygen concentration in the torus air space was

greater than allowed by Technical Specification (TS). Prompt action was taken to verify

this result and to reduce oxygen concentration to within TS limits. The condition was

preliminarily determined to be due to inadequate nitrogen purging during containment

inerting following plant startup. It also appears to have been the result of an unforeseen

consequence of a recent change to eliminate the procedural option to inert the drywell and

torus in parallel. Pending further inspector review, this issue was unresolved. (Section

01.3)

VY declared an unusual event (UE) based on receipt of a seismic monitor alarm. The cause

of the alarm was later determined to have been a spurious indication from a single

accelerometer, and the UE was terminated. Although, the event was correctly classified in

accordance with the emergency procedures. (Section 01.4)

Severalinstances of weak operator performance were noted. The inspector was

concerned that the number and nature of these instances was above normal. These

observations and concern were discussed with and acknowledged by VY station

management. (Section 04.1)

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Maintenance

The licensee's decision to shut down for repair of main steam bypass valve, V2-77, was i

the result of a thorough review of the available repair options. Licensee preparations for

this maintenance were thorough. The outage duration was extended primarily due to '

! emergent maintenance that could not have been foreseen going into the outage. These

j issues were appropriately addressed prior to plant restart. (Section M2.1)

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Post scram review of individual control rod scram times revealed that one rod was l

significantly slower than the others. During subsequent scram time testing, the rod did not l

l insert when scrammed. The cause was determined to be a defective scram solenoid pilot l

l valve (SSPV) assembly. VY had replaced all SSPVs during the 1996 refueling outage, with

l units that are unique to VY in this application. The f ailed SSPV was returned to the vendor

(Automatic Valve, or AVCO), who determined the cause to be binding of one of the two

l solenoid plungers. The binding was the result of wear products that were produced by  ;

l cyclic impact (induced by the 60-cycle AC solenoid) of the plunger on the plunger j

backseat. The failed SSPV had been noted to be buzzing, along with nine other SSPVs, at

the beginning of the operating cycle. As a result, VY inspected the remaining nine SSPVs

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- that had been buzzing, and found evidence of wear on all of the associated plungers. No i

l significant wear indications were observed on the plungers in solenoids that were not

burzing= VY concluded that solenoid buzzing could be used as a reliable indicator of

incipient failure, and listituted periodic checks for noise. The root cause of this failure

mechanism is currently under investigation. (Section M2.2)

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Enaineerina

The emergency diesel generator (EDG) service water flow control valves are air-operated

and were found to be supplied via non-nuclear safety related (NNS) pressure regulators in

the instrument air system. A failure of the NNS pressure regulators could cause the flow

control valves to failin the closed position, which would isolate service water cooling flow

through the EDG heat exchangers. The discovery of this system design vulnerability was

made by the NRC Architect Engineering Team. A more detailed examination and summary

of this finding will be documented in their report. (Section E1.2)

The VY Individual Plant Examination of External Events review identified that failure of

several non-seismic piping systems could adversely impact safety related equipment.

However, the licensee's immediate systems operability assessment concluded that the '

identified piping, although not seismic category 1, was of sufficient design and strength to

withstand design basis earthquake dynamic loading. (Section E7.2)

NRC reviewed the licensee's capability to meet station blackout backup electrical ,

requirements. The licensee satisfies 10 CFR Part 50, Appendix A, GDC 17, " Electric  !

Power Systems," and has committed to come into full compliance with 10 CFR 50.63 prior

to start-up from the 1998 refuel outage. (Section E8.1)

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) A regional specialist visited the site and YNSD during this inspection period. The specialist

reviewed the Vernon tie line cable testing and found it acceptable. The inspector also

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provided an update for Violation 50-271/96-09-06 corrective actions. One inspector

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followup item was opened as a result of those visits on the electrical circuit model used to

support the evaluation of voltage dip during start of the fire pump. (Section E2)

Plant Suonort

The licensee maintained an effective security program. Management support was evident

based on the effective implementation of the security program. Management controls for

identifying, resolving, and preventing programmatic problems were effective, audits were

thorough and in-depth, alarm station operators were knowledgeable of their duties and

responsibilities, and security training was being performed in accordance with the NRC-

approved training and qualification plan. The licensee's provisions for land vehicle control

measures satisfy regulatory requirements and licensee commitments. Vehicles were being

properly searched prior to permitting protected area access, as required in the Plan and

applicable implementing procedures. (Section S)

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TABLE OF CONTENTS -

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EX EC UTIV E S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii

TAB LE O F C O NT ENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v I

Summ ary of Plant Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 i

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l. Operations .................................................... 1  ;

O1 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 l

01.1 Reactor Scram Due To Personnel Error During Nuclear i

instrument Surveillance Testing ........................ 1 .

01.2 Plant Startup and Return to Full Power Operation . . . . . . . . . . . . 4 l

01.3 (Open) Unresolved item (97-04-02): high oxygen concentration l

in the torus air space during plant operations . . . . . . . . . . . . . . . 4

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01.4 Unusual Event Declared due to Indication of a Possible Seismic

Event ........................................... 6

04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . 7

04.1 Operator Performance Observations ..................... 7

II. Maintenance .................................................. 8

M1 Conduct of Maintenance .................................. 8 i

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M1.1 Maintenance Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8  !

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M1.2 Surveillance Observations ............................ 8 I

M2 Maintenance and Material Condition of Facilities and Equipment ...... 9

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M2.1 Planned Mini-Outage for Repair of Main Steam Bypass Valve

V2-77........................................... 9

M2.2 Scram Solenoid Pilot Valve Malfunction . . . . . . . . . . . . . . . . . . .10

M2.3 Main Station Transformer Oil Leak ..................... 12

l 111. En g i n e e ri n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

El Conduct of Engineering .................................. 12

E1.1 Emergency Diesel Generator Potential Common Mode Failure .. 12

! E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 16

E2.1 Post-Modification Test of the Vernon Tie 5 kV Cable ........ 16

E7 Quality Assurance in Engineering Activities .................... 17

E7.1 RHR Service Water Flow Requirements . . . . . . . . . . . . . . . . . . 17

l E7.2 Individual Plant Examination of External Events (IPEEE) Review

issues.......................................... 17

E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

E8.1 (Closed) Follow-up Item 50-271/97-02-07: offsite electrical

power sources ................................... 18

E8.2 (Closed) LER 50-271/97-007: inadvertent primary containment

isolation system actuation due to a spurious spike on a reactor

building vent radiation monitor, dated May 21,1997 ........ 19

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l IV. Plant Support ................................................ 22

S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 22

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S2 Status of Security Facilities and Equipment .................... 22

S2.1 Alarm Stations and Communications . . . . . . . . . . . . . . . . . . . . 22

SS Security and Safeguards Staff Training and Qualification .......... 23

S6 Security Organization and Administration . . . . . . . . . . . . . . . . . . . . . . 24

S7 Quality Assurance in Security and Safeguards Activities . . . . . . . . . . . 24 i

' S7.1 Effectiveness of Management Controls . . . . . . . . . . . . . . . . . . 24 }

S7.2 Audits ......................................... 25

S8 Miscellaneous Security and Safety Issues ..................... 26

S8.1 Vehicle Barrier System (VBS) ......................... 26 -

S8.2 Bomb Blast Analysis ............................... 27 l

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S8.3 Procedural Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 _j

V. Ma nagem ent Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

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X.2 Management Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28  :)

X.3 Review of Updated Final Safety Analysis Report (UFSAR) . . . . . . . . . . 28

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INSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

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PARTIAL LIST OF PERSONS CONTACTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 i

LI ST O F AC R O NYM S U S ED . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

ENCLOSURE 3 .................................................. 33

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Report Details

Summarv of Plant Status

At the beginning of the inspection period, Vermont Yankee (VY) was operating at 100

percent reactor power. On April 24, an inadvertent reactor scram occurred due to

personnel error while performing a nuclear instrumentation surveillance. The plant utilizsv

the unplanned shutdown for early commencement of a scheduled maintenance outag -

Emergent work on the main transformer extended the original two day outage duratir - hy

approximately one week. A reactor startup was performed on May 7 and full pow?  !

operation was achieved on May 9. The plant operated at 100 percent reactor pc er for

the remainder of the inspection period with the exception of power reductions to conduct

planned surveillance testing.

1. Operations

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01 Conduct of Operations' ,

O 1.1 Reactor Scram Due To Personnel Error Durina Muclear Instrument Surveillance

Testina

a. Inspection Scope (71707)

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The inspector observed operator response to an inadvertent reactor scram that j

occurred on April 24, and reviewed the licensee's investigation of the cause and ~

actions to prevent recurrence.

b. Observations and Findinas

On April 24 at 9:10 a.m., a reactor scram occurred from 100 percent power. The )

cause of the scram was personnel error while performing local power range monitor 1

(LPRM) calibrations; specifically, two average power range monitor (APRM, an i

instrument that uses the output from several LPRMs to determine average power) )

channels were inappropriately taken out of bypass while they were set to zero l

power, which generated a reactor protection system (RPS) scram signal (APRM

downscale). Plant response was as expected; all rods fully inserted, the main

turbine tripped, and the turbine bypass valves operated to control reactor pressure.

The rapid power reduction caused reactor water level to decrease to less than 127

inches (normal operating level is 160 inches), which produced primary containment

isolation system (PCIS) isolations of group 2, (drywell drains and portions of the

RHR system) group 3, (drywell ventilation), and group 5 (reactor water cleanup

system). Feedwater control system response, along with level swell caused by

reactor heating of the feedwater, subsequently caused reactor water level to exceed

the high level trip setpoint for the reactor feedwater pumps. Feedwater pump i

restart was complicated by a failure of the condensate flow control valve automatic

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controller, but a pump was successfully started after the controller was placed in 1

l the manual mode. Reactor vessel level was then stabilized at its normal level. The

! reactor scram and PCIS actuation was reported to the NRC operations center (EN

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32213) as required by 10 CFR 50.72.

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

reactor inspection report outline. Individual reports are not expected to address all outline topics.

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The licensee had been planning to perform a controlled shutdown on April 29 for a

two day mini-outage, primarily to repair a leaking main steam bypass valve. Rather

than restarting the unit to operate for only four days, VY management decided to

commence the scheduled outage early. Following single rod scram time testing and

inspection of the drywell, plant cooldown was commenced on April 25, and cold

shutdown conditions were established at 12:30 p.m. Outage activities are

discussed in section M2.1 of this report.

The inspectors arrived in the control room several minutes after the scram. The

inspectors obserfed that the operators were responding in accordance with the

scram procedure, and that the response was well controlled. In particular, the

inspectors noted that the shift supervisor demonstrated excellent command and '

control; while not becoming overly involved in specific operations, he demonstrated

thorough comprehension of overall plant conditions through the conduct of seveial

short briefings with the control room operators. These briefings reviewed the

existing plant conditions, and addressed target conditions and near-term activities.

The licensee conducted an investigation to determine the root cause of the

inadvertent reactor scram. The event occurred during the course of performing

LPfiM calibration and functional checks per Operating Procedure (OP)-4406, "LPRM

Calibration and Functional Checks," Revision 13, dated October 18,1996. This i

activity was being directed by a member of the reactoi engineering staff (the reactor I

engineer), with actions being performed by operators and instrument and controls )

(l&C) technicians. At the beginning of the procedure, the two APRM ct.annels (A  ;

and D) that were supplied by the LPRM channels to be calibrated, were placed in l

bypass (per step I.A.4.). These switches are on the main control board (MCB) and  !

the action was performed by an operator. This action prevents test signals from j

being input to the RPS while the associated LPRMs are being calibrated. A -

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subsequent procedural step (l.A.6.) performed by an l&C technician behind the MCB

placed the APRM mode switches in the "Zero" position, but the restoration portion

of the step which directed that these switches be placed back to the " Operate"

position was missed. L ater in the calibration, the procedure (step l.A.10.) called for i

a verification that APRM power was consistent with actual core thermal power, in

preparation for taking the APRM channels out of bypass. However, the APRM

channels both stillindicated zero power, due to the earlier mispositioning of their

mode switches. The reactor engineer knew that the next procedural step took the

APRM channels out of bypass, and incorrectly concluded that this action would

restore normal indication and allow the required comparison to be completed. The

reactor engineer then directed the operator (a licensed reactor operator) to take the

APRM channels out of bypass (per step I.A.11). The operator did not notice that

the APRM channels indicated zero and restored both channels to operate in rapid

succession (within about one second of one another). When each affected APRM

channel was placed in operate, its zero indication generated a reactor trip signal

i (APRM downscale) on its respective RPS channel. Since the affected APRM

channels each input to different RPS channels, this produced an actual reactor trip.

The f ailure of the VY operating staff to have adhered to OP-4406 steps I.A.6. and

I.A.10., directly resulted in the reactor protection system actuation and reactor

scram from 100 percent power at 9:10 AM on April 24,1997. This is a violation of

Technical Specification 6.5, " Plant Operating Procedures." (VIO 97-04-01)

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The licensee concluded that the root causes were personnel errors in 1) work

practices, and 2) communications. Specific work practice errors by the reactor

engineer were failures to follow the procedure, in omission of the step to return the

APRM mode switches to " Operate," and in not completing the procedural step to

verify that APRM power was consistent with core thermal power prior to proceeding

to the next step. The work prectice error that was attributed to the reactor operator

was failure to verify correct system response after returning the first APRM to

service. Such a verification would have revealed the unexpected system response

(one channel of the RPS tripped) and allowed it to be resolved before plant

operation was affected. The verbal communication error was that the reactor

engineer did not seek resolution of what he interpreted to be a procedural conflict

(the APRM power comparison that could not be completed without performing the

subsequent procedural step to take the APRMs out of bypass). In addition, the

licensee identified procedure inadequacy (multiple actions required to be performed

within a single procedural step) and lack of knowledge of APRM operations, as

contributing causes. -

As immediate corrective action, the licensee conducted training on lessons learned

from this event with alllicensed operators. In a meeting with a!I plant personnel,

the expectation for procedural adherence and communication of emergent problems

was stressed. Long term corrective action included review and upgrade of all

reactor engineering procedures that have the potential to produce a half or full

scram, and training for reactor engineering personnel on the neutron monitoring and

reactor protection systems. These actions are anticipated to be completed prior to

the end of 1997.

The inspector agreed that the cause of the scram was a combination of personnel

errors. The inspector considered that a significant contributing factor was that the

calibrations were being simultaneously performed on two APRM channels, with

each APRM providing input to its respective RPS channel. While this is acceptable

with respect to operability requirements, the operational consequences of an

equipment malfunction or procedural error have the potential to be much more

severe (as demonstrated by this event) than with a single channel calibration. The

inspector noted that this aspect of the event, while not specifically identified as a

cause in the licensee event report (LER 98-008, revision 0), will be examined as part

of VY's corrective action,

c. Conclusions

The April 24 reactor scram occurred due to personnel error. The specific error was

the failure to adhere to the surveillance test procedure OP-4406, "LPRM Calibration

and Functional Check," steps 1.A.6. and I.A.10., and is a violation of Technical

Specifications. Operator response to the transient was very good and, with some

minor exceptions, plant response was normal.

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01.2 Plant Startuo and Return to Full Power Ooeration

a. Inspection Sr.o_pe (71707)

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l During the pai. ad May 7-9,1997, the inspectors observed portions of the plant i

startup and ret an to t;:l power operation.

b. . Observations, Findinas, and Conclusions

Following completion of the outage to repair main steam bypass valve V2-77, plant

startup was commenced on May 6. The reactor mode switch was placed in the

STARTUP position at 9:34 p.m. Reactor startup was commenced at 12:57 a.m.,  ;

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May 7, and criticality was achieved at 2:38 a.m. Following reactor heatup and '

l startup of the steam plant, the reactor mode switch was placed in the RUN position

at 8:20 p.m. The main generator was synchronized to the grid at 10:08 a.m., May 1

8, and 100 percent power was achieved at 7:37 a.m., May 9. i

The inspector observed portions of the plant startup from the control room.  !

Operations were deliberate and well controlled. For example, when difficulty was '

encountered with initial rod movement on one rod (a condition that occasionally i

occurs due to the design of the control rod drive), actions were closely supervised i'

by the shift supervisor, and strict procedural compliance was observed. Turbine

generator startup and synchronization to the grid was also observed to have been i

performed deliberately and with close direction and oversight.

01.3 (Ocen) Unresolved item (97-04-02): high oxygen concentration in the torus air

space during plant operations

a. Inspection Scope (71707)

On May 12,1997, a weekly surveillance to measure oxygen concentration in the

torus air space revealed that the concentration was greater than the four percent

limit established by Technical Specification (TS) 3.7.A.7.

b. Observations and Findinas

At 12:25 a.m., the torus air space oxygen concentration was measured to be 8.5

percent. This determination was made with one of the installed drywell

hydrogen / oxygen monitors. A local sample, taken by a radiation protection (RP)

technician using different monitoring equipment, indicated 7.5 percent oxygen. At .

12:30 a.m., operators entered TS 3.7.A.8, which requires that an orderly shutdown

be initiated immediately and that the reactor be in a cold shutdown condition within

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, if TS 3.7.A.1 through A.7 cannot be satisfied.

l Operators noted that similar indications had been observed during a weekly torus

l oxygen sample that was performed during November 1996, and that the cause had

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been an air leak on the containment air monitor (CAM); this event is discussed in

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inspection report 96-200. To eliminate this possible cause, the CAM was isolated.

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The filter cover was examined and determined not to be leaking. In addition, torus l

oxygen concentration remained unchanged with the CAM isolated, further indicating }

that air leakage into the sample stream was not the cause of the problem. The RP  ;

technician then obtained a second grab sample from an alternate sample point in the i

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containment atmosphere dilution system. At 4:00 a.m., this sample indicated 7.7

percent oxygen in the torus air space.

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At 5:30 a.m., operators had commenced reducing reactor power as required by TS  ;

3.7.A.8. In accordance with 10 CFR 50.72, the NRC was notified at 6:13 a.m. that '

the plant had commenced a TS required plant shutdown (EN 32314).

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, The torus air space had been inerted on May 8, in the normal course of the plant

l startup. The licensee suspected that the high oxygen concentration was the result

of inadequate nitrogen purging during that operation, rather than being caused by air  ;

leakage into the torus air space. The apparent reason for the inadequate purge was 1

that the procedure for inerting the drywell had been revised, since its previous use, i

i to delete the option of inerting the drywell and torus in parallel (the previous

preferred method of inerting vice inerting the torus and drywell individually). This

change was made due to a recently identified concern that a design basis loss of-  ?

coolant accident, coincident with operations to purge or inert the drywell, could

overpressurize the standby gas treatment system, despite automatic system ,

isolation at the onset of the accident. This issue was discussed in inspection report l

97-03 and is the subject of an inspector follow item (97-03-01). Previously, the - l

l drywell and torus were purged at the same time, and the licensee considered that  !

this likely resulted in better mixing of the air and nitrogen. The licensee further

considered that the close proximity of the sample point to the torus nitrogen inlet'

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- 8 inerting operation, leading operators to secure the nitrogen purge too early. 1

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Therefore, VY station management directed that inerting of the torus would be

resumed in parallel with the plant shutdown, with the shutdown to be terminated

when torus air space oxygen concentration was reduced to less than four percent.

l Torus inerting was commenced at 9:45 a.m. At 12:00 noon on May 12, torus air

space oxygen concentration was measured to be 1.0 percent, and torus inerting

was secured at 12:30 p.m. Power reduction for the reactor shutdown was stopped

at 12:40 p.m., at 94 percent power. At 2:00 p.m., the licensee exited TS 3.7.A.8,

i and commenced power escalation at 2:30 p.m. The plant returned to full power

l operation at 5:22 p.m. The licensee instituted daily torus oxygen sampling until

consistent oxygen concentration had demonstrated that adequate inerting had been

performed, and verified that the source of oxygen had not actually been an air leak

into the torus. j

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The licensee initiated an event report (ER No. 97-0516) to document this event and

to initiate corrective action. At the close of the inspection period, this event report 3

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remained open. I

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c. Conclusions

A weekly surveillance revealed that oxygen concentration in the torus air space was

greater than allowed by Technical Specification (TS). Prompt action was taken to

verify this result and to reduce oxygen concentration to within TS limits. The

condition was preliminarily determined to be due to inadequate nitrogen purging

during containment inerting following plant startup. While the licensee's response

to the high oxygen concentration was found acceptable, the inspectors were

concerned that the licensee controls were not successful in avoiding this condition.

Pending further inspector review of the cause of this event, this issue is unresolved

(URI 97-04-02).

01.4 Unusual Event Declared due to Indication of a Possible Seismic Event _

a. Insoection Scope (71707)

The inspector reviewed the events surrounding the licensee's declaration of an

Unusual Event (UE) in response to a plant seismic monitor alarm.

b. Observations and Findinas

i

At 7:03 a.m. on May 31,1997, operators received a seismic monitor alarm. There

were no other indications that a seismic event (earthquake) had occurred. The

licensee declared an Unusual Event at 7:25 a.m., based on procedure AP-3125,  !

" Emergency Plan Classification and Action Level Scheme," entry criteria U-5-c, ,

"Any earthquake sensed on-site as recognized by observation or detection." The

states of Vermont, New Hampshire, and the Commonwealth of Massachusetts were

notified, and a one-hour emergency notification (EN 32420) was made to the NRC

as required by 10 CFR 50.72.

l

The licensee responded in accordance with operating procedure OP-3127, " Natural j

Phenomena." This included visual inspection of selected plant structures for

possible damage, and completion of a seismic damage indicator walkdown of plant

systems. No evidence of earthquake damage was observed. Examination of data

retrieved from the seismic monitor revealed that only one of the three

accelerometers had detected motion. Given that no other monitoring stations had

detected an earthquake, the licensee concluded that the cause of the seismic

monitor alarm had been a spurious indication from a single accelerometer. The

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licensee terminated the UE at 9:35 a.m. Subsequent troubleshooting of the seismic

monitor demonstrated that the suspect accelerometer had failed.

c. Conclusions

l The VY staff responded appropriately to the seismic monitor alarm and the

declaration of an Unusual Event was in accordance with their emergency

procedures. However, the inspector considered that the procedural requirement to

declare an Unusual Event based on a single indication was overly conservative.

Allowance to verify that a seismic event has actually occurred prior to making an

_ _ . _ _ _ _ _ _ _ . _ . _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ . _

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event determination would potentially avoid the unnecessary mobilization of state

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and federal emergency response organizations.

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04 Operator Knowledge and Performance  ;

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04.1 Operator Performance Observationc

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a. Inspection Scope (71707)  ;

!

As discussed in section 01.1, the cause of the April 24 reactor scram was

personnel error. During this inspection period, the inspectors noted other instances  :

j of weak operator performance: t

!

b. Observations and Findinas

l

During a planned shift of shutdown cooling from residual heat removal (RHR) loop A

l to loop B, a licensed operator attempted to start a B-loop RHR pump while its i

suction valve was still closed. I

!

!

While placing the second feedwater regulating valve in service during the plant

l startup from the outage, the shift supervisor became engaged in non plant-related .

!

activities in the control room that reduced his effectiveness at monitoring the I

l evolution.

i

The pre-job brief for single rod scram testing on April 24 did not include a i

. discussion of possible problems and actions to be taken. 'Nhen a rod failed to i

l scram, attention was initially focused on determining whether an error had been  ;

'

made in the test equipment setup rather than on restoring the plant condition to  !

normal. Later, the shift supervisor directed that the rod be fully reinserted using the  !

manual rod control system.  !

c. Conclusions

The inspector was concerned that the number and nature of these instances were

above normal, with respect to operations staff performance in recent inspection

l periods. This concern warrants additional management attention to ensure that this

l in not an early indication of a performance trend. These observations and concern

were discussed and acknowledged by VY station management.  ;

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11. Maintenance i

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M1 Conduct of Maintenance ,

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j M 1.1 Maintenance Observations l

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a. Inspection Scope (62707)  !

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The inspectors observed portions of plant maintenance activities to verify that the

correct parts and tools were utilized, the applicable industry code and technical .;

specification requirements were satisfied, adequate measures were in place to ,

l ensure personnel safety and prevent damage to plant structures, systems, and  !

l components, and to ensure that equipment operability was verified upon completion l

of post maintenance testing.  !

!

b. Observations. Findinas. and Conclusions [

The inspector observed all or portions of the following maintenance activities:

e Disassembly and inspection of one of the scram solenoid pilot valves

(SSPVs) suspected of having excessive wear, observed on April 26,1997.  !

SSPV malfunction is discussed in section M2.2 of this report; the inspector

observed that only the suspect solenoid valve plunger showed indication of

wear (black dust), and that the other solenoid valve plunger appeared as if  !

new. No deficiencies were noted in the conduct of this maintenance. j

e Replacement of air pressure regulators for the emergency diesel generator i

service watet flow control valves, observed May 22,1997. This

maintenance was performed to address the possibility that non-nuclear

safety (NNS) regulator malfunction could cause the SW flow control valves L

to fail shut and thereby render the EDGs inoperable; this problem is  !

discussed further in section E1.3 of this report. The NNS regulators were j

replaced in-kind with units that had undergone commercial grade dedication. -!

No deficiencies were noted in the conduct of this maintenance.

M1.2 S_urveillance Observations

a. Insoection Scone (61726)

The inspectors observed portions of surveillance tests to verify proper calibration of

test instrumentation, use of approved procedures, performance of work by qualified

personnel, conformance to LCOs, and correct post-test system restoration.

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i b. Observations, Findinas, and Conclusions  !

The inspector observed all or portions of the following surveillance tests

!

Single rod scram time test for rod 06-11, observed on April 24,1997. This i

testing was performed in response to the slower than expected individual rod

l scram time that was observed during the April 24 reactor scram, and led to

the discovery that the scram solenoid pilot valve assembly was defective. i

This material problem is discussed further in section M2.2 of this report; i

performance observations from this testing are discussed in section 04.1 of

this report.

Main turbine minimum speed oil trip test, observed on May 8,1997. This

l' test was performed during the main turbine startup in preparation for

synchronizing the main generator to the grid. The test was well controlled

and was completed satisfactorily. i

Torus-to-drywell vacuum breaker cycling, observed on May 30,1997. Along ,

with a raview of the precedure, the pre-job brief included discussion of how

communications would be handled, problems that had previously occurred, ,

and actions to be taken if problems were encountered. The test was

completed satisfactorily.

M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Planned Mini-Outaae for Repair of Main Steam Bvoass Valve V2-77

.

a. Inspection Scope (62707)

The inspector reviewed the scope of maintenance activities that were completed

during the April 24 - May 7 maintenance outage. l

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b. Observations and Findinas l

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The principle activity that required the plant to be shut down and cool down was

repair of the main steam bypass valve, V2-77. This valve had developed a body-to-  !

bonnet leak soon after startup from the 1996 refueling outage, and attempts to i

perform an on-line temporary leak repair had been unsuccessful; these activities

were discussed in inspection report 96-11. The plan was to repair the existing

valve, but a replacement valve was ready for installation, if repair proved unfeasible.

'

No other major maintenance activities were originally planned to be worked, and the

outage was projected to last approximately two days. However, several emergent  !

- problems forced extension of the outage to May 7. The problem that most i

significantly affected the schedule was an oilleak that developed on the mam

transformer; this item is discussed further in section M2.3 of this report. Other

emergent issues included:

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l e Scram solenoid pilot valve refurbishment / replacement; this item is discussed

in section M2.2 of this report i

• Repair of a small oil leak on the "B" recirculation pump motor

e Replacement of a leaking valve body seal on each the "A" and "C" main  ;

steam relief valves

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e Rerouting of several electrical cables to resolve cable separation concerns;

this issue was discussed in inspection report 97-03, and is further addressed

in section E1.1 of this report ,

c. Conclusions

The licensee's decision to shut down for repair of V2-77 was the result of a  ;

thorough review of the available repair options. Licensee preparations for this i

maintenance were thorough. The outage duration was extended primarily due to *

emergent maintenance that could not have been foreseen going into the outage.

These issues were appropriately addressed prior to plant restart.

M2.2 Scram Solenoid Pilot Valve Malfunction ,

a. Inspection Scooe (62707) ,

During post-scram review of individual control rod scram times, the licensee noted  :

that rod 06-11 was significantly slower that all of the other rods. The scram time

from position 48 to 46 for rod 06-11 was 0.526 seconds, as opposed to the core  ;

average of 0.280. The licensee initiated additional testing of rod 06-11 to I

determine the cause of the slow scram time.

!

b. Observations and Findinas

]

On the afternoon of April 24, with the plant stillin HOT SHUTDOWN, single rod

scram time testing was attempted on rod 06-11. However, the rod did n'at insert l

when scrammed, remaining instead fully withdrawn at 48 steps. TrouNeshooting

by instrument and controls (l&C) personnel identified the cause to be that the scram

l solenoid pilot valve (SSPV) assembly was not venting in response to a scram signal,

!

thereby preventing the hydraulic control unit (HCU) scram valves from operating to

scram the rod. VY informed the NRC of the failed scram time test as required by

10 CFR 50.72 (EN 32263).

During the 1996 refueling outage, VY had replaced all SSPVs. The replacement.

valves were developed and qualified for this application in a cooperative effort

between VY and a valve manufacturer (Automatic Valves, or AVCO), in response to

historic difficulties that had been experienced with existing SSPVs. The new valves

differ from existing SSPVs in that they do not use elastomer diaphragms. They are

configured such that both SSPVs for a particular HCU are contained in a common

valve body, whereas the original SSPVs were two independent units. Although VY j

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is currently the only licensee that uses this dual solenoid valve unit in an SSPV  !

application, these valves are used in different applications by other licensees. VY

also uses these valves to operate the scram discharge volume vent and drain

valves, and the main steam isolation valves.

Soon after startup from the 1996 refueling outage, VY noted that several of the

l new SSPV units were producing a buzzing noise. VY inquired to AVCO regarding

the noise, and the response was that such noise was expected with AC-powered l

solenoids (60-cycle hum) and that it did not constitute a problem. Nevertheless, VY '

tracked the condition, periodically noting which units were buzzing and how loud

they were buzzing (based on a qualitative scale, developed specifically for this

condition). RPS surveillance testing made it possible to identify which of the two

solenoids was buzzing by noting whether the noise stopped when a half scram

signal was inserted. This accumulated information became significant when it was

recognized that the SSPV that failed on April 24 (HCU 06-11) was one of the units

that had been buzzing.

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VY sent the failed SSPV unit to AVCO for cause determination. No prior  ;

troubleshooting of the unit was attempted by VY, so that the as-failed condition '

would not be disturbed. AVCO determined that the cause of failure was that one of

the solenoid plungers was bound in the energized position (pilot valve remains

closed). The SSPV solenoids de-energize to scram and both solenoids pilot valves

must be open for the associated rod to scram. The top of the plunger was found to )

! have a peened edge around the upper end. The peened material had caught in the  ;

plunger guide and caused the plunger to stick. AVCO concluded that the cause of

the plunger deformation was slight, cyclic movement of the plunger, in6Jced by the

60-cycle AC power to the solenoid, which was causing the top of the plunger to

strike the plunger backseat. This condition had been the source of the buzzing

noise and, over time, had produced wear and deformation of the plunger end.

AVCO notified the NRC that they were initiating the 10 CFR 21 process for

reporting of a defective component (EN 32253).

Based on this proposed failure mechanism, VY inspected the remaining SSPVs that

had been producing a buzzing noise. For all nine units inspected, the solenoid that

had been identified to be buzzing (through l&C's earlier informal monitoring) was

found to have a worn plunger. The wear was evidenced by the presence of black

dust. The black dust had also been present in the SSPV that was sent to AVCO,

and had been identified by them to be the same material as the plunger (400-series

stainless steel). By unaided visual inspection, none of the worn plungers showed

evidence of deformation or peening. However, the degree of wear (that is, the

amount of black dust) was found to correlate roughly with the level of noise that

the solenoid had been making. The nine associated solenoids that had not been

i buzzing showed no indication of wear.

l

The worn plungers were replaced and the SSPVs were tested to verify that the

buzzing noise had been eliminated. In one case, the noise persisted after plunger

replacement, so the entire SSPV unit was replaced. The replaced components were

sent to AVCO for additional evaluation. Single rod scram time testing was

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pe'rformed on all rods associated with the SSPV refurbishment / replacement, with

satisfactory results.  !

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l Although the root cause of failure was still under investigation by AVCO, VY.  !

L . concluded.that the inspections of the nine SSPV units had demonstrated that the  !

l buzzing noise was a conclusive indicator of incipient solenoid failure. To support l

! continued operation pending completion of the root cause determination, VY {

instituted a weekly inspection of all SSPVs by I&C personnel, and shiftly checks for

abnormal noise, to be performed by operations personnel. A basis for maintaining

operation, BMO 97-19, was generated to document this approach,

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c. Conclusions  !

!

L The conclusion that solenoid buzzing could be used as an indicator of incipient  !

failure was adequately supported by the SSPV inspection results. Increased- j

monitoring of the SSPVs for noise was an appropriate interim corrective action.  !

Resolution of.this issue will be tracked by the licensee's BMO, and will be  !

progressed by the inspectors as a matter of routine inspection.  ;

' M2.3 Main Station Transformer Oil Leak

Following the plant shutdown 'on April 24, plant workers identified an oil leak on i

one of the gasketed manways to the main transformer (T-1).' A number of repair  ;

alternatives were considered, but VY concluded that gasket replacement was the i

most prudent resolution. During the process of manway removal and gasket i

L replacement, additional inspections of transformer internals were conducted. These i

( inspections identified additional repair work which required ' partial oil draindown and

an increase in the original transformer work scope. The transformer problems and

repair work had no direct nuclear safety impact. However, main transformer  :

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reliability and availability does affect balance of plant related transients and

challenges to the reactor protection system. It was the inspector's understanding

that the transformer repairs were prudently authorized, but not essential to

continued safe and reliable operation of the generating unit. Licensee staff

inspection of the transformer following it being placed in service on May 8,1997

identified no discrepancies.

111.- Enaineerina  !

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[ E1 Conduct of Engineering [

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E1.1 Emeroency Diesel Generator Potential Common Mode Failure .j

On May 21,1997, the control room operators notified the NRC in accordance with

10 CFR 50.72 (EN 32370) of a condition outside their design basis which

_

i potentially could have rendered both emergency diesel generators (EDGs)

l inoperable. The EDG service water (SW) flow control valves (FW-104-28A and B)

[-

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- are air-operated and supplied via non-nuclear safety related (NNS) 100/35 psig

pressure regulators in the NNS instrument air system. The failure of the NNS

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pressure regulators could cause the FCV-104-28A and B valves to failin the closed

position, whv,h would isolate service water cooling flow through the EDG

lubricating oil and jacket water cooling heat exchangers.

The discovery of this EDG system design vulnerability was made by the NRC

Architect Engineering Team inspection staff. A more detailed examination and

summary of this finding will be documented in their inspection report. The resident

inspectors verified that, upon recognition of tnis design vulnerability, the VY staff

made an operability assessment of each EDG and properly notified the NRC per 10

CFR 50.72 of this design issue. As discussed in section M1.1 of this report, the

inspector witnessed and verified prompt replacement of the NNS pressure regulators

with similar commercially dedicated regulators. An inspector followup item will

track this issue pending issuance of the inspection report and final characterization

of the inspection finding. (IFl 97-04-03)

E1.2 480 Volt AC System

a. inspection Scope (37551)

The inspector reviewed the licensee's protection and coordination for the rotating

uninterruptible power supply (RUPS), and the 480 Volt Bus 9 (supply bus) and MCC

89A (load bus) to assess the coordination of the RUPS with its associated buses.

b. Observations and Findinas

The inspector reviewed calculation VYC-1087, Attachment B, page 36,480 Volt-

SWGR Bus 8 and 9 Breaker Settings, Rev 1, dated July 8,1992. This document

provided the protection and coordination time-current characteristics for Bus 8 and

9 related protective devices. The inspector observed that the information for the

RUPS ac feeder protective devices included the conductor sizes for the motor

feeders. The inspector obse:ved that the ac motor feeder included a 350 MCM

conductor with a transition to an AWG No.1 conductor local to the RUPS. The

inspector questioned the apparent lack of overcurrent protection for the AWG No.1

conductors on the RUPS ac input power circuit. In response, the licensee produced

an internal schematic for the RUPS, drawing 502011266, Sheet 1, Rev.2, dated

December 30,1996, which also indicated AWG No.1 conductors located between

the internal RUPS ac breaker and the ac motor. The licensee's drawing confirmed

the RUPS ac breaker was rated 150 amps consistent with the coordination curve.

The inspector confirmed that the 1990 National Electrical Code, Table 310-16,

permitted an AWG No.1 conductor with a 90 C rating to continuously carry 150

amps. The inspector also confirmed the nameplate fullload current of the ac motor

was 105 amps.

The inspector observed that the RUPS was not the largest load on Bus 8 or 9. Both

buses have a 250-HP control rod drive water pump and a 125 HP reactor building

cooling water pump. In addition, Bus 9 also has a 250-HP fire water pump.

Licensee Event Report 50-271/92-018 addressed a previous problem that had

resulted in a transient low voltage when starting the fire pump with reduced bus

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voltage. In the past, this had resulted in a swap-over of the RUPS from its ac  ;

source to dc power. The inspector reviewed an evaluation, Yankee Nuclear

Services Division (YNSD) had performed in response to VY Service Request PM No.

1350. That evaluation, contained in file VYE 89/92, Bus 9 Voltage Analysis for ,

RUPS Evaluation, dated December 4,1992, concluded, based on a computer model l

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(DAPPER), that under reduced bus voltage of 460 Vac, starting the fire pump motor

could result in the observed transfer of the RUPS from ac to de supply power. The

inspector was informed that this evaluation formed the basis for a niodification to l

the RUPS trip circuit performed under JO920068. The inspector reviewed the i

results of that evaluation and questioned the input data and results. In response, ,

the YNSD agreed that there appeared to be errors in the model used for the i

evaluation. However, these apparent errors would result in an even lower voltage

than the YNSD model had calculated. The inspector was informed YNSD would

issue an event report to document the discrepancy and initiate appropriate

corrective action to re-evaluate the model used for the fire pump starting evaluation.

The details of JO920068 were not available during this inspection. These items will ]

remain open pending NRC review of the revised modeling of the fire pump starting

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and retrieval of JO920068 from the historical records (IFl 50-271/97-04-06). j

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The inspector requested information on the Bus 9 load and breaker settings to j

confirm the coordination of the Bus 9 incoming breaker with the largest loads on the '

bus. The inspector reviewed selected coordination sheets from drawing B-191305,

480 V SWGR Bus 8 and 9, CAPTOR Project VY480SI, Rev. O, dated July 8,1992,  !

and proposed changes, dated August 9,1996. The inspector confirmed that

sufficient coordination existed for the feeder breakers to Bus 9 and all the load

breakers. The inspector confirmed that the existing and future settings contained in i

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the coordination package for the Bus 9 incoming and tie breakers provided sufficient

protection for both the station service transformer and the 480 Volt bus. The

inspector also confirmed the fire pump motor (FPM) coordinated with the bus feeder

breakers during starting of the FPM.

The licensee provided breaker information for the RUPS ac load side connection

which was based on the original static inverter. The licensee indicated they had i

planned an update for the coordination study for these breakers during 1997 for

consistency.

c. Conclusions

The inspector concluded the coordination curve for the ac supply side of the RUPS

should have clarified the apparent lack of protection for the AWG No.1 transition

cable to the ac motor. This was considered a weakness in the calculation. The

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inspector concluded the coordination of the 480 Volt Bus 9 feeder breaker with the

l RUPS and the 250 HP motors were acceptable,

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E1.3 Rotatina Uninterruotible DC Power Sucolv

a. Insoection Scoce

The de power supply for the rotating uninterruptible power supplies (RUPS) consists

of the batteries and a de machine. The batteries had been the de supply for the l

l original static UPS. The de machine acts as a battery charger when driven from the l

ac motor and a de motor when it is driving the ac generator upon loss of the ac l

supply. The inspector reviewed the basis for the selection, sizing and test {

acceptance criteria for the batteries associated with the RUPS.

)

l b. Observations and Findinas

The inspector reviewed calculation VYC-1630, Battery Sizing Calculation for 400 l

VDC RUPS Batteries, dated February 26,1997, to assess the design requirements

for the RUPS batteries. The inspector found that the sizing calculation was based j

on a minimum permissible battery terminal voltage of 360 Volts, derived a duty '

cycle from a previous ECCS Integrated Automatic Initiation Test, and included

appropriate margins for battery aging and minimum temperature. The calculation

estimated the maximum current seen by the battery would be 75 amps during

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stroking of valve V10-27A. In addition, the calculation held that current for five i

minutes. The inspector found the calculation acceptable.

l

The inspector reviewed the test procedures for the safety-related batteries

associated with the RUPS batteries-1 A and 18. The inspector reviewed the results

of the last performance test performed on battery RUPS-1 A on September 5,1993

(Procedure OP 4209, Rev. 6). The results of the discharge test indicated the

battery had a capacity of 110% of the manufacturer's rating.

The inspector reviewed the latest service test results obtained on October 10,

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1996, for battery RUPS-1B (Procedure OP4219, Rev. 6). The inspector found that

the acceptance criteria only required the demonstration that the battery was capable

of supplying the UPS with the power necessary for the UPS to supply its ac loads

!

during the integrated ECCS test. No minimum battery voltage was specified and

the data indicated the voltage at the battery dropped to 385 Volts after 173

seconds. The inspector confirmed the longest stroke time permitted for MOV V10-

27B by the RHR System Surveillance Test, OP 4124.01, Rev.46, dated

l April 24,1997, was 44.45 seconds. The inspector found that the post-

modification test that was performed following installation of the RUPS indicated

the RUPS low voltage dc trip was set at 365 +/-2 Volts. Therefore, the inspector

found the test acceptable.

c. Conclusions

The inspector concluded the RUPS batteries were adequately sized for their present

application and had additional margin beyond their design basis.

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E2 Engineering Support of Facilities and Equipment {r

E2.1 Post-Modification Test of the Vernon Tie 5 kV Cable 1

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a. Insoection Scooe

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The inspectors reviewed the maintenance and testing performed on the 5.0 kV l

cable that forms part of the power supply from the Vernon hydroelectric station to

assess its reliability. i

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b. Observations and Findinas

The inspectors found that the feed had been upgraded in 1993 by installing a new l

buried 15 kV line from Vernon to the VY site (EDCR 90-412.) This EDCR was  ;

originally installed to upgrade the feed to support 10 CFR 50.63, the Station  ;

Blackout Rule. A new transformer was also installed at the VY end of the line to  !

interface with the VY 4160 volt bus. A new section of 5 kV cable was installed  !

from the transformer to a manhole where it was spliced to a section of the existing  !

5 kV cable into the plant.

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The inspectors observed that the installation included high-direct-voltage testing  ;

(Hi-pot) of the new cables and an insulation resistance (IR) test of the existing 5 kV i

cable section. The inspectors reviewed the test results of the Hi-pot testing that - I

was performed in June 1993 and noted that the new 15 kV and 5 kV cables )'

appeared to have successfully withstood a de proof test at 65 kV and 35 kV

respectively.

The inspector questioned why the existing cable was also not subjected to a de Hi-

pot. The existing cable section had been installed in underground duct banks,

subject to moisture, and normally energized, but unloaded, for most of its installed 3

life. This type of installation has historically been responsible for most of the i

medium voltage cable failures reported in the electrical power industry. The .

licensee indicated hi-pot testing for the existing cable section was not required by i

engineering design change request (EDCR)89-407 and the insulation resistance test l

showed good IR values. The inspector reviewed the post-modification test data and

confirmed the IR testing performed on August 20,1993, produced excellent results

with the minimum value recorded of 375 Megohms. These readings included both

the new and old sections of the 5 kV cable and the splice joining them together.

The licensee indicated that when apparent lightning damage was found on another

section of the old abandoned Vernon tie 5 kV cable, the old, still-used section of

cable that was the transition into the plant was given a reduced voltage (10 kV) hi-

pot test. The inspector reviewed the results of hi-pot tests that were performed on

July 18,1995, and concluded, based on a review of IEEE Std. 400-1991, Guide for

Making High-Direct-Voltage Tests on Power Cables in the Field, that the step

voltage method was superior to the original high voltage proof test performed in

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1993. The inspector also confirmed the leakage currents at the 10 kV test voltage

j were equal to or less than 1 microamp.

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The inspectors reviewed the background for determining the reduced test voltage  !

and compared it to other guides, recommendations and practices used throughout ,

the electric industry. The inspector noted that there is no universal standard in test  ;

voltages for cables installed for more than five years. Test voltages for 5 kV cables

range from 10 to 25 kV and often refer the user to the manufacturer for their

recommendation. The inspector confirmed the licensee had contacted various

manufacturers, other utilities and industry experts during a previous review for i

testing associated with the startup transformer cables in 1993. Based on the

industry practices and the review of the 1995 hi-pot test results, the inspector i

found the test voltage used was acceptable.  ;

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c. Conclusions

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The inspectors concluded the installation and followup testing of the Vernon tie was j

acceptable based on industry test practices ano the Vernon tie cable test results, '

which showed good insulation resistance and adequate dielectric strength.

E7 Quality Assurance in Engineering Activities

The licensee's Design Basis Documentation (DBD) and Improved Technical

Specifications (ITS) projects have the potential for identifying inconsistencies

between the design, licensing, and operating bases of plant structures, systems,

and components. Such inconsistencies will be documented in this section of the.

report and tracked to resolution as inspection follow items.

1

E7.1 RHR Service Water Flow Reauirements l

!

On May 6,1997, the control room operators notified the NRC in accordance with

10 CFR 50.72 (EN 32285) of a potentially degraded /unanalyzed condition involving

the residual heat removal service water (RHRSW) system. Examination of the l

UFSAR accident analyses assumptions by the NRC Architect Engineering Team  !

identified that the minimum RHRSW flow through the RHR heat exchangers (2,700 i

gpm) may not be achieved because the existing flow instrument uncertainty of plus j

or minus 200 gpm. Station Operating Procedure (OP)-2124 instructs operators to

limit RHRSW system flow to a maximum of 2,700 gpm. Consequently, the actual

flow may exceed the established limit (potentially adversely impacting heat

exchanger design flow limits) or fall short of the prescribed cooling flow (potentially

compromising torus heat removal and containment response assumptions).

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The inspector verified the interim actions taken by the VY staff to limit continued

re,ctor plant operations to Connecticut River water temperatures of 70 degrees F

and below which will ensure the facility remains within established ultimate heat

sink heat removal capacity assumptions. This issue will be tracked via an

l Inspection Follow item pending final characterization of this inspection finding and

issuance of the inspection report. (IFl 97-04-04)

E7.2 individual Plant Examination of External Events (IPEEE) Review issues (37551)

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The licensee's IPEEE review project has the potential for identifying inconsistencies

i between the plant design and its capability to cope with certain external events,

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The issues identified via this project will be documented in this section of the report

and tracked to resolution as inspection follow items, as appropriate. The VY staff is

currently targeting completion of their IPEEE by the end of 1997.

Failure of Various Non-Seismic Pioina Could Affect Safety Related Eauioment

On May 20,1997, the control room operators notified the NRC in accordance with

10 CFR 50.72 (EN 32362) of a condition outside the plant's design basis, involving

the postulated failure of non-seismic piping which could adversely impact safety

related equipment. Specifically, the failure of service water supply lines in the '

HVAC room, sers.ce water lines to non-safety related components in the reactor

building (recirculation motor-generator set lube oil coolers), and fire protection

suppression water system piping in the reactor core isolation cooling (RCIC) room

have all been postulated to result in flooding of the safety related components in the

immediate and/or adjacent areas. These postulated failures and their consequences

were not previously identified in VY's 1988 Flooding Study.

The inspector reviewed the licensee's immediate systems' operability assessments

which concluded that the identified piping, although not seismic category 1, was of

sufficient design and strength to withstand design basis earthquake dynamic

loading. In addition, established operator actions for dealing with internal plant

flooding and formal Emergency Operating Procedures provide appropriate guidance

for dealing with these types of postulated events. The inspector found this initial

operability assessment satisfactory and the interim compensatory actions

appropriate. Pending final resolution, this design concern will be tracked as an

laspector Followup item. (IFl 97-04-05)

E8 Miscellaneous Engineering issues

E8.1 (Closed) Follow-uo item 50-271/97-02-07: offsite electrical power sources

a. Inspection Scope (37551)

By letter dated February 25,1997, the NRC staff requested additional information

pertaining to the VY offsite power system design. The NRC staff was completing a

review of older operating plants' offsite power systems based upon the lessons

learned from the Maine Yankee Independent Safety Assessment. The review was

focused on the adequacy of the delayed offsite power circuits as required by

General Design Criteria (GDC) 17, and in particular, the reliance upon main and unit

auxiliary transformers to backfeed power to the onsite distribution system.

VY responded to the request for additional information by letter dated March 26,

1997. The March 26,1997 letter established that no analysis had been cornpleted

to demonstrate that the main transformer backfeed delayed offsite power source

could be established in sufficient time to prevent fuel design limits and design

conditions of the reactor coolant pressure boundary from being exceeded. In lieu of

this analysis, the licensee relied upon the Vernon Tie (a second delayed offsite

power circuit) to restore electrical power (within ten minutes via switches in the

control room) until the main transformer backfeed could be made available (in

approximately six hours). The March 26,1997 letter also established that VY

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considered the Vernon Tie as acceptable for compliance with both GDC 17, as a

delayed access source and 10 CFR 50.63, " Station Blackout Rule" as an alternate ,

alternating current (AC) power source.

.

Following review of VY's March 26 response, the NRC conducted a telephone

,

discussion with the VY staff followed by a letter dated April 17,1997 summarizing i

I the NRC staff's understanding of the offsite power systems and their conclusion  !

that the Vernon Tie cannot serve as one of the GDC 17 offsite power sources and I

as an alternate AC power source. The VY staff attempted to clarify their licensing

and design basis of the offsite power systems via VY letter dated April 24,1997.  ;

b. Observations and Findinas

Via conference calls between the NRC staff and VY management on April 25,  !

1997, the NRC staff informed VY that GDC 17 was satisfied via the 345 kv auto- '

transformer (for immediate access power) and the Vernon Tie (for delayed access

power). Further, that the Vernon Tie could not be credited for satisfying 10 CFR

l 50.63. In addition, the NRC staff considered this issue not to be a unit restart

impediment, provided VY submitted their plans within 30 days for complying with

l 10 CFR 50.63. Via letters dated April 29,1997 and May 1,1997, the licensee

l formalized their commitments for complying with 10 CFR 50.63 and the NRC staff l

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acknowledged the acceptability of VY's schedule to achieving full compliance,

respectively.

l By subsequent letter dated May 29,1997, VY docketed their plans to implement

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j modifications, with supporting analysis and licensing bases, to establish the main

transformer back feed capability as the GDC 17 delayed access power circuit. In

addition, VY docketed their plans to initiate the appropriate licensing actions to

support the re approval of the Vernon Tie as the 10 CFR 50.63 Station Blackout

alternate AC power source.

c. Conclusions

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l The licensee satisfies 10 CFR Part 50, Appendix A, GDC 17, " Electric Power

j Systems' and has committed to comply with 10 CFR 50.63 prior to start-up from

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the 1998 refuel outage. This inspection follow-up item is closed. NRC staff review

of VY's proposed modifications and licensing changes will be examined during a

future inspection period.

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E8.2 (Closed) LER 50-271/97-007: inadvertent primary containment isolation system

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actuation due to a spurious spike on a reactor building vent radiation monitor, dateri

May 21,1997. VY staff response was appropriate for this spurious radiation

monitor electronic noise spike and subsequent ventilation systems automatic

isolation and initiation. Proper verification measures were initiated to confirm

radiological conditions did not cause the event and that automatic system responses

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were as designed. The control room staff appropriately notified the NRC in

accordance with 10 CFR 50.72 (reference Event No. 32192, dated April 21,1979.

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E8.3 (Closed) LER 50-271/97-008: plant scram due to procedural non-compliance and

failure to perform self-verification during nuclear instrumentation calibration, dated

May 23,1997. This event is discussed in section 01.1 of this report.

E8.4 (Closed) LER 50-271/97-009: lack of specificity in plant Technical Specifications {

results in operation of the plant service water systems which was inconsistent with '

prescribed limiting conditions for operation and testi~g requirements, dated May 21,

1997. The inspector noted that the root cause of th s issue could not be

determined because of the length of time this TS reg Jirement had been in effect

(since initial licensing in 1971). The interim and more restrictive administrative

limits placed upon service water subsystem operation were determined appropriate

by the inspector. The VY staff plans to remedy this TS discrepancy upon NRC staff

review and approval of their improved TSs, targeted for 1998. Also, reference

inspection report 97-02, section E7.1 and inspector follow item 97-02-08. i

E8.5 (Closed) LER 50-271/97-010: individual control rod drive scram time greater than ,

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normal due to manufacturing defect in scram solenoid pilot head assembiy,69d

May 21,1997. This event is discussed in section M2.2 of this report.  ;

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E8.6 (Ocen) Violation 50-271/96-09-06. inadeauate batterv service test accentme I

criteria i

a. Inspection Scope (92701)

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Inspection report 50-271/96-09 discussed a problem with test control for the main

station batteries. The licensee had failed to incorporate any appropriate acceptance

criteria for the battery service test. The criteria that was provided had no basis in

any design document and failed to consider the minimum battery terminal voltage l

used to determine the acceptable operation of safety-related de equipment. The

inspector reviewed the licensee's corrective action in response to Violation 96-09-

06.

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b. Observations and Findinas

in their response letter, BVY 96-161, dated December 20,1996, the licensee

indicated four corrective actions would be taken to avoid further violations. The

licensee indicated that the first three items (update the calculation, perform a

consistency review of the battery test procedures and define ownership of design

basis calculations) would be completed by April 30,1997, and the remaining item

(update procedure OP 4215) would be completed by June 30,1997. These

corrective actions were further defined by the licensee in their Event Report (ER) No. 7

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The inspector confirmed that calculation VYC-298, Battery Sizing Calculation for

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Vermont Yankee Station Batteries A-1 and B-1 was revised (Rev.10) on

April 22,1997, and calculation VYC-1349,125 Volt DC Voltage Drop, was revised

(Rev.1) on April 30,1997. The inspector also confirmed copies of the calculations

were forwarded to the electrical maintenance engineer at VY. At the time of this i

inspection, the Main Station Battery Test Procedure, OP 4215, had not yet been i

updated to be consistent with the new calculations, j

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The inspector confirmed that the Electrical /l&C Design Group established a

Calculation Tracking System in response to the NOV. The controlling list of

calculations was issued on April 7,1997. The tracking system lists the

calculations by number, responsible engineers, affected calculations and procedures

! and pending revisions to the base calculation. The inspector noted that even

though calculation VYC-1349 was listed in the cover memorandum, the tracking

system failed to identify a pending revision against the calculation. The inspector

was later provided a copy of the June 1,1997, issue of the tracking system and

noted it correctly indicated calculation VYC-1349 had been revised.

The inspector noted ER 96-0748 did not limit this corrective action to just

Electrical /l&C Design Engineering but it was assigned to Design Engineering in

general. The inspector also noted the Plant Operating Review Committee (PORC)

review of the ER specifically indicated all Design Engineering departments should

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evaluate if a similar tracking system is necessary. As of the close of this

inspection, it did not appear that any other discipline had initiated an evaluation of a

.similar calculation tracking system. The inspector did confirm that Vermont Yankee

Design Engineering Procedure (VYDEP) 15, Calculations, had been revised (Rev.2)

on March 31,1997, to emphasize the relationship of calculations to procedures and

other documents.

The inspectors confirmed that the licensee had performed a consistency review of

the surveillance procedures associated with the batteries defined in the technical

specifications. The licensee issued an interoffice memorandum, dated

May 20,1997, which documented the review of the service test procedures for

batteries AS-2, the ECCS batteries and the main station batteries against their

design basis calculations. The licensee indicated that all the associated battery

calculations were revised in 1997 and the procedures are being revised to include

the new load profiles.

The inspector noted the absence of the RUPS batteries from the May 20th

memorandum. Tne !!censee explained that the RUPS batteries were purposefully

not included in the memorandum because they are tested with the actualloads

during their surveillance test and are not tested to a calculated load profile. The ,

inspector found this acceptable.

c. Conclusions

The inspector concluded the licensee had not completed all the corrective actions in

response to the notice of violation. The licensee had updated the battery sizing and j

voltage drop calculations. These calculations had been transmitted to the site in l

response to the new calculation ownership process. The inspectors noted that the j

licensee is continuing to review these calculations.

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IV. Plant Support i

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S1 Conduct of Security and Safeguards Activities

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a. Inspection Scope

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Determine whether the security program, as implemented, met the licensee's  :

commitments in the NRC-approved security plan (the Plan) and NRC regulatory

l requirements. The security program was inspected during the period of  ;

l May 27-30,1997. Areas inspected included: management support and audits;

l effectiveness of management controls; alarm stations and communications; training

and qualification; and the vehicle barrier system,

b. Observations and Findinas

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Management support was evident based on the effective implementation of the  !

security program as documented in this report. The Security Manager's position in ,

the organizational structure and reporting chain permits management's awareness l

of issues and concerns, management controls for identifying, resolving, and

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preventing programmatic problems were effective, and audits were thorough and in-

depth. Alarm station operators were knowledgeable of their duties and i

responsibilities and security training was being performed in accordance with the -

NRC-approved training and qualification (T&O) plan.

Based on the inspection of the land vehicle barriers and discussions with plant. j

engineering and security management, the inspector determined that the licensee's i

provisions for land vehicle control measures satisfy regulatory requirements and

licensee commitments. After review of UFSAR and Section 5.3.2 of the Plan, i

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entitled " Vehicle Searches," the inspector determined by observing security force

members performing vehicle searches, discussing with security supervision, and 1

l reviewing applicable procedures and records that vehicles were being properly l

searched prior to permitting protected area access as required in the Plan and -

applicable procedures.

c. Conclusions

The inspector determined that the licensee was conducting its security and

safeguards activities in a manner that protected public health and safety and that

the program, as implemented, met the licensee's commitments and NRC

requirements.

S2 Status of Security Facilities and Equipment

S2.1 Alarm Stations and Communications

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8. InsDection Scope

Determine whether the Central Alarm Station (CAS) and Secondary Alarm Station

r (SAS) are: (1) equipped with appropriate alarm, surveillance and communication

capability, (2) continuously manned by operators, and (3) use independent and

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! diverse systems so that no single act can remove the capability of detecting a threat

l and calling for assistance, or otherwise responding to the threat, as required by

l NRC regulations.

b. Observations and Findinos

Observations 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. l

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c. Conclusion j

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The alarm stations and communications met the licensee's Plan commitments and 1

NRC requirements.

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S5 Security and Safeguards Staff Training and Qualification l

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a. Inspection Scone i

Determine whether members of the security organization are trained and qualified to

perform each assigned security-related job task or duty in accordance with the T&Q

Plan.

b. Observations and Findinos

On May 29,1997, the inspector observed tactical response training. The training  !

involved the proper use of cover and concealment, tactical movement, weapons  ;

manipulation, and shooting under stress. Based on observations, toe training was

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properly controlled, safety was stressed at all times, and the instructors were

knowledgeable of the subject matter. Additionally, the inspector interviewed a

number of SFMs to determine if they possessed the requisite knowledge and ability

to carry out their assigned duties,

c. Conclusions

The inspector determined that training had been conducted in accordance with the

T&Q Plan. Based on responses to the inspector's questions, the training provided

by the security training staff was found to be effective.

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S6 Security Organization and Administration

a. Insoection Scoce

Conduct a review of the level of management support for the licensee's physical

security program.

b. Observations and Findin_qs

The inspector reviewed various program enhancements made since the last program

inspection, which was conducted in July 1996. These enhancements included the

procurement of tactical response training aids and ongoing range improvements.

The inspector reviewed the Security Manager's position in the organizational

structure and reporting chain. The Security Manager reports to the Technical

Services Superintendent, who reports to the Plant Manager, who reports directly to

the Vice-President of Operations. Additionally, the inspector noted that the access

authorization and fitness-for-duty programs, being safeguards related, report directly

to the Security Manager.

c. Conclusions

Management support for the physical security program was determined to be  !

effective. No problems with the organizational structure that would be detrimental

to the effective implementation of the security and safeguards programs were

noted. )

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S7 Quality Assurance in Security and Safeguards Activities j

S7.1 Effectiveness of Manaaement Controts

a. Inspection Scoce  !

Determine if the licensee has controls for identifying, resolving, and preventing I

programmatic problems.

b. Observations and Findinas

The inspector reviewed the licensee controls for identifying, resolv'ing, and

preventing security program problems. These controls included the implementation

of a departmental self-assessment program, which includes the performance of post

assessments by security supervision and the performance of the NRC-required

annual quality assurance (QA) audits. The licensee also utilizes industry data, such

as violations of regulatory requirements identified by the NRC at other facilities, as

l criteria for self-assessment. The inspector reviewed documentation applicable to

the performance of the self-assessment program and noted that 51 self-

assessments were conducted in 1996 and, as of this inspection, 26 self-

assessments were performed during 1997.

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l Additionally, the inspector noted that an average of 67 post assessments are )

l performed per month by security shift supervision. The inspector determined, based '

on a review of the safeguards event logs, self-assessments, and post assessments i

that personnel performance errors were minimal. i

! c. Conclusions

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The inspector concluded that controls were effectively implemented to prevent and  !

resolve potential weaknesses.

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S7.2 Audits

a. inspection Scope

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Review the licensee's Quality Assurance (QA) report of the NRC-required security

program audit to determine if the licensee's commitments as contained in the Plan

were being satisfied.

b. Observations and Findinas I

The inspector reviewed the 1996 QA audit of the security program, conducted

October 21-24,1996, (Audit No. VY-96-04) and the 1997 combined QA audit of I

the fitness-for-duty (FFD)/ access authorization (AA) programs, conducted l

February 12-23,1997, (Audit No. VY-97-19). The audits were found to have been i

conducted in accordance with the Plan and FFD rule. To enhance the effectiveness

of the FFD/AA audit, the audit team included one independent technical specialist.

The security audit report identified no findings. The combined FFD/AA audit

identified four findings and six recommendations. The findings involved general

employee training weaknesses concerning information on the effects of prescription 1

and over-the-counter drugs on job performance and chemical test results, two

documentation issues involving AA records, and the accuracy of the random drug  !

testing pool. The audit results had been disseminated to the appropriate levels of l

management. The inspector determined, based on discussions with security

management and FFD/AA supervision, that the responses to the audit have not

been finalized as of the inspection. Those findings will be reviewed during a

subsequent inspection.

c. Conclusions

The review concluded that the audits were comprehensive in scope and depth, that

the findings were appropriately distributed, and that the audit program was being

properly administered. 1

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l S8 Miscellaneous Security and Safety issues

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S8.1 Vehicle Barrier System (VBS)

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On August 1,1994, the Commission amended 10 CFR Part 73, " Physical Protection

of Plants and Materials," to modify the design basis threat for radiological sabotage

to include the use of a land vehicle by adversaries for transporting personnel and

their hand carried equipment to the proximity of vital areas and to include the use of

a land vehicle bomb. The amendments require reactor licensees to install vehicle

control measures, including vehicle barrier systems (VBSs), to protect against the ,

malevolent use of a land vehicle. Regulatory Guide 5.68 and NUREG/CR-6190 were  !

issued in August 1994 to provide guidance acceptable to the NRC by which the i

licensees could meet the requirements of the amended regulations, j

A February 23,1996, letter from the licensee to the NRC forwarded Revision 27 to

its physical security plan that detailed the actions implemented to meet the

requirements of 10 CFR 73.55 (c)(7),(8), and (9) and the design goals of the

" Design Basis Land Vehicle" and " Design Basis Land Vehicle Bomb." A NRC

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June 19,1996, letter advised the licensee that the changes submitted had been )'

reviewed and were determined to be consistent with the provisions of 10 CFR

50.54(p) and were acceptable for inclusion in the NRC-approved security plan. 1

This inspection, conducted in accordance with NRC Inspection Manual Temporary

Instruction 2515/132, " Malevolent Use of Vehicles at Nuclear Power Plants," dated

January 18,1996, assessed the implementation of the licensee's vehicle control

measures, including vehicle barrier systems, to determine if they were

commensurate with regulatory requirements and the licensee's physical security

plan.

a. Insoection Scoce

The inspector reviewed documentation that described the VBS and physically

inspected the as-built VBS to verify it was consistent with the licensee's summary

description submitted to the NRC.

b. Observations and Findinas l

The inspector's walkdown of the VBS and review of the VBS summary description

disclosed that the as-built VBS was consistent with the summary description and

met or_ exceeded the specifications in NUREG/CR-6190.

c. Conclusion

The inspector determined that there were no discrepancies in the as-built VBS or the

VBS summary description. I

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S8.2 Bomb Blast Analysis

a. Inspection Scope

The inspector reviewed the licensee's documentation of the bomb blast analysis and

verified actual standoff distances provided by the as-built VBS.

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b. Observations and Findinas

The inspector's review of the licensee's documentation of the bomb blast analysis

determined that it was consistent with the summary description submitted to the

NRC. The inspector also verified that the actual standoff distances provided by

their as-built VBS were consistent with the minimum standoff distances calculated

using NUREG/CR-6190. The standoff distances were verified by review of scaled

drawings and actual field measurements.

c. Conclusion

No discrepancies were noted in the documentation of bomb blast analysis or actual

standoff distances provided by the as-built VBS.

S8.3 Procedural Controls

a. Inspection Scope

The inspector reviewed applicable procedures to ensure that they had been revised

to include the VBS.

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b. Observations and Findinas

The inspector reviewed the licensee's procedures for VBS access control measures,

surveillance and compensatory measures. The procedures contained effective

controls to provide passage through the VBS, provide adequate surveillance and

inspection of the VBS, and provide adequate compensation for any degradation of  !

the VBS.

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c. Conclusions l

The inspector's review of the procedures applicable to the VBS disclosed no

discrepancies.

V. Manaaement Meetinas

X.1 Exit Meeting Summary

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! The inspectors met with licensee representatives periodically throughout the

l inspection and following the conclusion of the inspection on June 10,1997. At  !

i that time, the purpose and scope of the inspection were reviewed, and the 4

l preliminary findings were presented. The licensee acknowledged the preliminary

inspection findings.  :

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X.2 Management Meeting Summary l

On April 30,1997, representatives of VY, General Electric, and Yankee Atomic

Electric Company met with the NRC staff in Rockville, MD, to discuss current and

future fuel cycle operation at VY. A summary of this meeting was provided by VY i

via correspondence to the NRC, BVY 97-69, dated May 22,1997.

On May 15,1997, VY managers met with the NRC Region I staff in King of Prussia, f

PA, to discuss performance improvements in the engineering area. Materials that  !

were presented during the meeting are attached to this report.

X.3 Review of Updated Final Safety Analysis Report (UFSAR)

A recent discovery of a licensee operating its facility in a manner contrary to the I

UFSAR description highlighted the need for a special focused review that compares l

plant practices, procedures, and parameters to the UFSAR description. While

performing the inspections discussed in this report, the inspectors reviewed the  :

applicable portions of the UFSAR that related to the areas inspected. Discrepancies l

that were noted were documented in the applicable section of the above report. t

Since the UFSAR does not specifically include security program requirements, the  ;

inspectors compared licensee activities to the NRC-approved physical security plan, ,

which is the applicable document. While performing the inspection discussed in this l

report, the inspector reviewed Section 5.3.2 of the Plan, Revision 27 dated ,

February 23,1996, titled, " Vehicle Searches." The inspector determined, by I

observing security force members performing vehicle searches, discussions with  :

security supervision and reviews of applicable procedures and records, that vehicles

are being properly searched prior to permitting protected area access as required in

the Plan and applicable procedures.

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l lNSPECTION PROCEDURES USED l

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! 62707 Maintenance Observations  :

l- 61726 Surveillance Observations j

71750 Plant Support Activities j

71707 Plant Operations  ;

37551 On-Site Engineering '

92700 - On-Site Follow Up of Written Reports of Non-routine Events

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81700 Physical Security Program for Power Reactors -

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Ti 2515/132 Malevolent Use of Vehicles at Nuclear Power Plants  ;

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! ITEMS OPENED, CLOSED, AND DISCUSSED .

OPEN  :

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- VIO 97-04-01 Violation of Technical Specification 6.5, " Plant Operating Procedures"

URI 97-04-02 Torus oxygen concentration outside TS limits  !

IFl 97-04-03 Potential for loss of EDG SW flow due to SW flow control valve air

pressure regulator failure l

l IFl 97-04-04 RHR service water flow requirements ~

! IFl 97-04-05 Failure of various non-seismic piping could affect safety related

l equipment  !

IFl-97-04-06 Electrical circuit model to support evaluation of voltage drop during  :

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start of the fire pump l

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IFl 97-02-07 Offsite electrical power sources l

LER 97-007 Inadvertent primary containtnent isolation system actuation, May 21,

1997

LER 97-008 Plant scram, May 23,1997  ;

,. LER 97-009 Lack of specificity in plant TS i

j LER 97-010 Individual control rod drive scram time greater than normal

DISCUSSED

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URI 97-03-02 Operability assessments for the identified cable separation  !

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PARTIAL LIST OF PERSONS CONTACTED

G. Maret, Plant Manager

S. Jefferson, Assistant to Plant Manager

F. Helin, Tech. Services Superintendent

E. Lindamood, Director of Engineering

K. Bronson, Operations Manager

M. Watson, l&C Manager

M. Desilets, Radiation Protection Manager

R. Gerdus, Chemistry Manager

G. Morgan, Security Manager

C. Nichols, Electrical and Controls Maintenance Manager

J. Moriarty, Security Operations Specialist

L. Pitts, Security Technical Assistant

W. Peterson, Quality Assurance (QA) Manager, Yankee Atomic Energy Company (YAEC) ,

A. Wonderlick, QA Engineer, YAEC

F. Harper, Project Manager, The Wackenhut Corporation (TWC)

E. Wright, Security Operations Supervisor, TWC

G. Sherer, Security Project Coordinator, TWC

J. Jasinski Security Training Supervisor, TWC

P. Corbett, Project Engineering Manager, VY

B. Donovan, Electrical Maintenance Engineer, VY q

' D. Maidrand, Electrical (DC) System Engineer, VY  !

D. Philips, Manager, Electrical and l&C Maintenance Engineering, VY

D. Jannary, Manager, Electric and l&C Design Engineer, YNSD l

P. Johnson, Sr. Electrical Engineer, YNSD l

R. Cox, Electrical Engineer, YNSD

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R. Moschella, Electrical Engineer, YNSD J

R. Vibert, Electrical Engineer, YNSD

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32

LIST OF ACRONYMS USED

VY Vermont Yankee

NRR Office of Nuclear Reactor Regulations

NRC Nuclear Regulatory Commission

TS Technical Specifications

EDG emergency diesel generator  ;

LER Licensee Event Report j

RHR residual heat removal l

HVAC heating, ventilation, and air conditioning l

DDFP diesel driven fire pump

DBD design basis documentation ,

HELB high energy line break  !

EDCR engineering design change request {'

URI unresolved item

IFl inspector follow item I

CS core spray I

SFM security force members l

QA quality assurance

the Plan NRC-approved physical security plan

PA protected area i

T&Q training and qualification

IDS intrusion detection systems

'

CAS central alarm system

SAS secondary alarm system

UFSAR Updated Final Safety Analysis Report l

CCTV closed circuit television )

VBS vehicle barrier system l

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ENCLOSURE 3

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, VERMONT YANKEE ENGINEERING UPDATE

l NRC Region i Meeting, May 15,1997

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May 15,1997

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